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Schlumberger - Reservoir Engineering - Reservoir Engineering Community

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Schlumberger - Reservoir Engineering - Reservoir Engineering Community Powered By Docstoc
					  Nov-09
NOTES:

           The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro
           The papers relating to reservoir engineering have been catergorised for inclusion on the   reservoirengineering.org.uk website
           The affiiations searched were;

                                                                    Total No Papers     Reservoir Engineering Related
                      BP                                                   551                      175
                      Shell                                                575                      279
                      Chevron                                              482                      238
                      ConocoPhillips                                       191                       68
                      Marathon                                             55                        37
                      Total                                                255                      129
                      Schlumberger                                        1130                      563
                      Imperial College, London                             95                        53
                      Heriot Watt University, Edinburgh                    235                      175
                      (Anywhere in Article)
                                                      Total               3569                          1717



                      Total number of papers published post 2005 =             10,000

                                                                   35% of papers published categorised
                      Paper
Organisation   Source No.          Chapter
SCHLUMBERGER     SPE   115707          CO2
SCHLUMBERGER     SPE   116422          CO2
SCHLUMBERGER     SPE   116424          CO2
SCHLUMBERGER     SPE   121970          CO2
SCHLUMBERGER     SPE   108540          CO2
SCHLUMBERGER     SPE   115247          CO2
SCHLUMBERGER     SPE    98617          CO2
SCHLUMBERGER     SPE   108528          CO2
SCHLUMBERGER     SPE   102968          CO2
SCHLUMBERGER     SPE   112259   Corporate Process
SCHLUMBERGER     SPE    98945         Drilling
SCHLUMBERGER     SPE   112365         Drilling
SCHLUMBERGER     SPE   119506         Drilling
SCHLUMBERGER     SPE   113843        EOR/IOR
SCHLUMBERGER     SPE   107445        EOR/IOR
SCHLUMBERGER     SPE    99720        EOR/IOR
SCHLUMBERGER     SPE    98142        EOR/IOR
SCHLUMBERGER     SPE   117622        EOR/IOR
SCHLUMBERGER     SPE   112021        EOR/IOR
SCHLUMBERGER     SPE   123773        EOR/IOR
SCHLUMBERGER     SPE   103329        EOR/IOR
SCHLUMBERGER     SPE   104755        EOR/IOR
SCHLUMBERGER     SPE   107101        EOR/IOR
SCHLUMBERGER     SPE   110968        EOR/IOR
SCHLUMBERGER     SPE   111512        EOR/IOR
SCHLUMBERGER     SPE   117066        EOR/IOR
SCHLUMBERGER     SPE   126063        EOR/IOR
SCHLUMBERGER     SPE   103900    Flow Assurance
SCHLUMBERGER     SPE   109591    Flow Assurance
SCHLUMBERGER     SPE   115485    Flow Assurance
SCHLUMBERGER     SPE    99994    Flow Assurance
SCHLUMBERGER    IPTC    11556    Flow Assurance
SCHLUMBERGER     SPE   110833    Flow Assurance
SCHLUMBERGER     SPE   103242    Flow Assurance
SCHLUMBERGER     SPE   100739    Fluid Description
SCHLUMBERGER     SPE   116501    Fluid Description
SCHLUMBERGER     SPE   121414    Fluid Description
SCHLUMBERGER     SPE   112977    Fluid Description
SCHLUMBERGER     SPE   102240    Fluid Description
SCHLUMBERGER     SPE   106375    Fluid Description
SCHLUMBERGER    IPTC    11239    Fluid Description
SCHLUMBERGER     SPE   109539    Fluid Description
SCHLUMBERGER     SPE   123423    Fluid Description
SCHLUMBERGER     SPE   100393    Fluid Description
SCHLUMBERGER     SPE   108097    Fluid Description
SCHLUMBERGER     SPE   102571    Fluid Description
SCHLUMBERGER     SPE   110511    Fluid Description
SCHLUMBERGER    IPTC    11582    Fluid Description
SCHLUMBERGER     SPE   122562    Fluid Description
SCHLUMBERGER    SPE    99386    Fluid Description
SCHLUMBERGER    SPE   109684    Fluid Description
SCHLUMBERGER    SPE   123430    Fluid Description
SCHLUMBERGER    SPE    89704    Fluid Description
SCHLUMBERGER    SPE   111911    Fluid Description
SCHLUMBERGER    SPE   108494    Fluid Description
SCHLUMBERGER    SPE    81481    Fluid Description
SCHLUMBERGER    SPE   120988    Fluid Description
SCHLUMBERGER    SPE   114702    Fluid Description
SCHLUMBERGER    SPE   115429    Fluid Description
SCHLUMBERGER    SPE   100937    Fluid Description
SCHLUMBERGER   IPTC    11268    Fluid Description
SCHLUMBERGER    SPE   116098    Fluid Description
SCHLUMBERGER    SPE   118893    Fluid Description
SCHLUMBERGER    SPE    97886    Fluid Description
SCHLUMBERGER    SPE   101219    Fluid Description
SCHLUMBERGER    SPE   117164    Fluid Description
SCHLUMBERGER    SPE   110364    Fluid Description
SCHLUMBERGER    SPE   115499    Fluid Description
SCHLUMBERGER    SPE   101084    Fluid Description
SCHLUMBERGER    SPE   100865    Fluid Description
SCHLUMBERGER   IPTC    11573    Fluid Description
SCHLUMBERGER    SPE   115622    Fluid Description
SCHLUMBERGER   IPTC    12886   Formation Damage
SCHLUMBERGER    SPE   120468   Formation Damage
SCHLUMBERGER    SPE   120947   Formation Damage
SCHLUMBERGER    SPE   114058   Formation Damage
SCHLUMBERGER    SPE   122844   Formation Damage
SCHLUMBERGER    SPE   112434   Formation Damage
SCHLUMBERGER    SPE   122845   Formation Damage
SCHLUMBERGER    SPE    98220   Formation Damage
SCHLUMBERGER    SPE   114255   Formation Damage
SCHLUMBERGER    SPE   107993   Formation Damage
SCHLUMBERGER    SPE   100112   Formation Damage
SCHLUMBERGER    SPE   101401   Formation Damage
SCHLUMBERGER    SPE   100516   Formation Damage
SCHLUMBERGER    SPE   108994       Giant Field
SCHLUMBERGER    SPE   126075       Giant Field
SCHLUMBERGER    SPE   105069       Giant Field
SCHLUMBERGER    SPE   117233       Giant Field
SCHLUMBERGER    SPE   110401       Giant Field
SCHLUMBERGER    SPE   118434       Giant Field
SCHLUMBERGER   IPTC    11395       Giant Field
SCHLUMBERGER    SPE    97889        Heavy Oil
SCHLUMBERGER    SPE   117682        Heavy Oil
SCHLUMBERGER   IPTC    12536        Heavy Oil
SCHLUMBERGER    SPE   117689        Heavy Oil
SCHLUMBERGER    SPE   103841        Heavy Oil
SCHLUMBERGER    SPE   120423        Heavy Oil
SCHLUMBERGER    SPE   102460        Heavy Oil
SCHLUMBERGER    SPE   104163        Heavy Oil
SCHLUMBERGER    SPE   104520        Heavy Oil
SCHLUMBERGER    SPE   116746           Heavy Oil
SCHLUMBERGER    SPE   105327           Heavy Oil
SCHLUMBERGER    SPE   104046           Heavy Oil
SCHLUMBERGER    SPE   117285           Heavy Oil
SCHLUMBERGER    SPE   117562           Heavy Oil
SCHLUMBERGER    SPE   107636            HP/HT
SCHLUMBERGER    SPE   115609            HP/HT
SCHLUMBERGER    SPE   103997            HP/HT
SCHLUMBERGER    SPE   116243            HP/HT
SCHLUMBERGER    SPE   121755            HP/HT
SCHLUMBERGER    SPE   121759            HP/HT
SCHLUMBERGER    SPE   106054            HP/HT
SCHLUMBERGER    SPE   107108            HP/HT
SCHLUMBERGER    SPE   120817            HP/HT
SCHLUMBERGER    SPE   106712            HP/HT
SCHLUMBERGER    SPE    98318            HP/HT
SCHLUMBERGER    SPE    93805            HP/HT
SCHLUMBERGER    SPE   107277            HP/HT
SCHLUMBERGER    SPE   100182            HP/HT
SCHLUMBERGER    SPE   121695            HP/HT
SCHLUMBERGER    SPE   122197          Lab Testing
SCHLUMBERGER    SPE   113487   Low Permeability Reservoirs
SCHLUMBERGER    SPE   108075   Low Permeability Reservoirs
SCHLUMBERGER    SPE   120161   Low Permeability Reservoirs
SCHLUMBERGER    SPE   117570   Low Permeability Reservoirs
SCHLUMBERGER    SPE   120749   Low Permeability Reservoirs
SCHLUMBERGER    SPE   125237   Low Permeability Reservoirs
SCHLUMBERGER    SPE   126160   Low Permeability Reservoirs
SCHLUMBERGER    SPE   102956   Low Permeability Reservoirs
SCHLUMBERGER    SPE   119481   Low Permeability Reservoirs
SCHLUMBERGER    SPE   119140   Low Permeability Reservoirs
SCHLUMBERGER    SPE   119927   Low Permeability Reservoirs
SCHLUMBERGER    SPE   103865   Low Permeability Reservoirs
SCHLUMBERGER    SPE   123296   Low Permeability Reservoirs
SCHLUMBERGER    SPE   103250   Low Permeability Reservoirs
SCHLUMBERGER    SPE    90630   Low Permeability Reservoirs
SCHLUMBERGER    SPE   105681   Low Permeability Reservoirs
SCHLUMBERGER    SPE    90690   Low Permeability Reservoirs
SCHLUMBERGER    SPE   120424   Low Permeability Reservoirs
SCHLUMBERGER   IPTC    11528   Low Permeability Reservoirs
SCHLUMBERGER    SPE   112303   Low Permeability Reservoirs
SCHLUMBERGER   IPTC    11545   Low Permeability Reservoirs
SCHLUMBERGER    SPE   109565   Low Permeability Reservoirs
SCHLUMBERGER    SPE   115825   Low Permeability Reservoirs
SCHLUMBERGER    SPE   103987   Low Permeability Reservoirs
SCHLUMBERGER    SPE   110067   Low Permeability Reservoirs
SCHLUMBERGER    SPE   102569   Low Permeability Reservoirs
SCHLUMBERGER   IPTC    12328   Low Permeability Reservoirs
SCHLUMBERGER    SPE   121223   Low Permeability Reservoirs
SCHLUMBERGER    SPE   101257   Low Permeability Reservoirs
SCHLUMBERGER    SPE   105262   Low Permeability Reservoirs
SCHLUMBERGER    SPE   101129        Minor Reservoirs
SCHLUMBERGER   IPTC    11537     Minor Reservoirs
SCHLUMBERGER   IPTC    11765   Project Management
SCHLUMBERGER   IPTC    12502   Project Management
SCHLUMBERGER    SPE   106100   Reservoir Description
SCHLUMBERGER    SPE   101897   Reservoir Description
SCHLUMBERGER    SPE   116328   Reservoir Description
SCHLUMBERGER   IPTC    11622   Reservoir Description
SCHLUMBERGER   IPTC    12253   Reservoir Description
SCHLUMBERGER    SPE   121945   Reservoir Description
SCHLUMBERGER    SPE   108566   Reservoir Description
SCHLUMBERGER    SPE   108925   Reservoir Description
SCHLUMBERGER    SPE   105014   Reservoir Description
SCHLUMBERGER    SPE   120407   Reservoir Description
SCHLUMBERGER    SPE    97224   Reservoir Description
SCHLUMBERGER    SPE   100351   Reservoir Description
SCHLUMBERGER    SPE   101718   Reservoir Description
SCHLUMBERGER    SPE   116591   Reservoir Description
SCHLUMBERGER    SPE   119690   Reservoir Description
SCHLUMBERGER    SPE   118380   Reservoir Description
SCHLUMBERGER    SPE   110277   Reservoir Description
SCHLUMBERGER    SPE   102888   Reservoir Description
SCHLUMBERGER    SPE   110223   Reservoir Description
SCHLUMBERGER    SPE   102256   Reservoir Description
SCHLUMBERGER    SPE   110752   Reservoir Description
SCHLUMBERGER    SPE   109848   Reservoir Description
SCHLUMBERGER    SPE   102572   Reservoir Description
SCHLUMBERGER    SPE   121923   Reservoir Description
SCHLUMBERGER    SPE   120443   Reservoir Description
SCHLUMBERGER    SPE   101343   Reservoir Description
SCHLUMBERGER    SPE   101286   Reservoir Description
SCHLUMBERGER    SPE   101913   Reservoir Description
SCHLUMBERGER    SPE   115836   Reservoir Description
SCHLUMBERGER    SPE   101126   Reservoir Description
SCHLUMBERGER    SPE   102435   Reservoir Description
SCHLUMBERGER    SPE   122585   Reservoir Description
SCHLUMBERGER    SPE   109972   Reservoir Description
SCHLUMBERGER    SPE   126044   Reservoir Description
SCHLUMBERGER    SPE   116092   Reservoir Description
SCHLUMBERGER    SPE   126094   Reservoir Description
SCHLUMBERGER    SPE    95841   Reservoir Description
SCHLUMBERGER    SPE   101721   Reservoir Description
SCHLUMBERGER    SPE   102588   Reservoir Description
SCHLUMBERGER    SPE   104013   Reservoir Description
SCHLUMBERGER    SPE   105427   Reservoir Description
SCHLUMBERGER    SPE   118895   Reservoir Description
SCHLUMBERGER    SPE   103284   Reservoir Description
SCHLUMBERGER    SPE   105456   Reservoir Description
SCHLUMBERGER    SPE   102562   Reservoir Description
SCHLUMBERGER    SPE   116068   Reservoir Description
SCHLUMBERGER    SPE   117073   Reservoir Description
SCHLUMBERGER    SPE   110304   Reservoir Description
SCHLUMBERGER    SPE   112385   Reservoir Description
SCHLUMBERGER    SPE   107192    Reservoir Description
SCHLUMBERGER    SPE   115822    Reservoir Description
SCHLUMBERGER    SPE   110301    Reservoir Description
SCHLUMBERGER    SPE   110803    Reservoir Description
SCHLUMBERGER    SPE    89177    Reservoir Description
SCHLUMBERGER    SPE   107241    Reservoir Description
SCHLUMBERGER    SPE   120813    Reservoir Description
SCHLUMBERGER    SPE   101176    Reservoir description
SCHLUMBERGER    SPE    93974    Reservoir Description
SCHLUMBERGER    SPE   118152    Reservoir Description
SCHLUMBERGER    SPE   100740    Reservoir Description
SCHLUMBERGER    SPE   109683    Reservoir Description
SCHLUMBERGER   IPTC    11488    Reservoir Description
SCHLUMBERGER    SPE   104018    Reservoir Description
SCHLUMBERGER   IPTC    11350    Reservoir Description
SCHLUMBERGER    SPE   120691    Reservoir Description
SCHLUMBERGER    SPE   100738    Reservoir Description
SCHLUMBERGER    SPE   102456    Reservoir Description
SCHLUMBERGER    SPE   102413    Reservoir Description
SCHLUMBERGER    SPE   101556   Reservoir Development
SCHLUMBERGER    SPE   101151   Reservoir Development
SCHLUMBERGER   IPTC    12029   Reservoir Management
SCHLUMBERGER    SPE   104041   Reservoir Management
SCHLUMBERGER   IPTC    12225   Reservoir Management
SCHLUMBERGER    SPE   126064   Reservoir Management
SCHLUMBERGER    SPE   120803   Reservoir Management
SCHLUMBERGER    SPE    99317   Reservoir management
SCHLUMBERGER    SPE   123711   Reservoir Management
SCHLUMBERGER    SPE   122339   Reservoir Management
SCHLUMBERGER    SPE   122421   Reservoir Management
SCHLUMBERGER    SPE   102557   Reservoir Management
SCHLUMBERGER   IPTC    11594   Reservoir Management
SCHLUMBERGER    SPE   100984   Reservoir Management
SCHLUMBERGER    SPE   101491   Reservoir Management
SCHLUMBERGER    SPE   121489   Reservoir Management
SCHLUMBERGER    SPE   117633   Reservoir Management
SCHLUMBERGER    SPE   112223   Reservoir Management
SCHLUMBERGER    SPE    99469   Reservoir management
SCHLUMBERGER    SPE   109260   Reservoir Management
SCHLUMBERGER    SPE   112209   Reservoir Management
SCHLUMBERGER    SPE   102439   Reservoir Management
SCHLUMBERGER    SPE   116218   Reservoir Management
SCHLUMBERGER    SPE   120664   Reservoir Management
SCHLUMBERGER    SPE   116528   Reservoir Management
SCHLUMBERGER    SPE    99338   Reservoir Management
SCHLUMBERGER    SPE   107702   Reservoir Management
SCHLUMBERGER    SPE   103028   Reservoir Management
SCHLUMBERGER    SPE   108693   Reservoir Management
SCHLUMBERGER    SPE   108737   Reservoir Management
SCHLUMBERGER    SPE    98198   Reservoir Management
SCHLUMBERGER    SPE    93444   Reservoir Management
SCHLUMBERGER    SPE   110927   Reservoir Management
SCHLUMBERGER    SPE   122338   Reservoir Management
SCHLUMBERGER    SPE   105797    Reservoir Modelling
SCHLUMBERGER    SPE   102084    Reservoir Modelling
SCHLUMBERGER    SPE    99288    Reservoir Modelling
SCHLUMBERGER   IPTC    11718    Reservoir Modelling
SCHLUMBERGER    SPE   101779    Reservoir Modelling
SCHLUMBERGER    SPE   120433    Reservoir Modelling
SCHLUMBERGER    SPE    99882    Reservoir Modelling
SCHLUMBERGER   IPTC    12665    Reservoir Modelling
SCHLUMBERGER    SPE   102148    Reservoir Modelling
SCHLUMBERGER    SPE   122768    Reservoir Modelling
SCHLUMBERGER    SPE   119172    Reservoir Modelling
SCHLUMBERGER    SPE   119165    Reservoir Modelling
SCHLUMBERGER    SPE   110412    Reservoir Modelling
SCHLUMBERGER    SPE   105700    Reservoir Modelling
SCHLUMBERGER    SPE   112923    Reservoir Modelling
SCHLUMBERGER    SPE   120050    Reservoir Modelling
SCHLUMBERGER    SPE   126095    Reservoir Modelling
SCHLUMBERGER    SPE   110219    Reservoir Modelling
SCHLUMBERGER    SPE   119732    Reservoir Modelling
SCHLUMBERGER    SPE   111457    Reservoir Modelling
SCHLUMBERGER    SPE    99445    Reservoir Modelling
SCHLUMBERGER    SPE   120552    Reservoir Modelling
SCHLUMBERGER    SPE   102111    Reservoir Modelling
SCHLUMBERGER    SPE   117445    Reservoir Modelling
SCHLUMBERGER    SPE    99575    Reservoir Modelling
SCHLUMBERGER    SPE   107853    Reservoir Modelling
SCHLUMBERGER    SPE   107356    Reservoir Modelling
SCHLUMBERGER    SPE   104015    Reservoir Modelling
SCHLUMBERGER    SPE   106251    Reservoir Modelling
SCHLUMBERGER    SPE   119352    Reservoir Modelling
SCHLUMBERGER    SPE   103188    Reservoir Modelling
SCHLUMBERGER    SPE   121612    Reservoir Modelling
SCHLUMBERGER    SPE   112926    Reservoir Modelling
SCHLUMBERGER    SPE    96260    Reservoir Modelling
SCHLUMBERGER    SPE   123087    Reservoir Modelling
SCHLUMBERGER    SPE   101138    Reservoir Modelling
SCHLUMBERGER    SPE   107907    Reservoir Modelling
SCHLUMBERGER   IPTC    11205    Reservoir Modelling
SCHLUMBERGER    SPE    66365    Reservoir Modelling
SCHLUMBERGER    SPE   118709    Reservoir Modelling
SCHLUMBERGER    SPE   101013    Reservoir Modelling
SCHLUMBERGER    SPE   118979    Reservoir Modelling
SCHLUMBERGER    SPE   117370    Reservoir Modelling
SCHLUMBERGER    SPE   101674    Reservoir Modelling
SCHLUMBERGER    SPE    95498    Reservoir Modelling
SCHLUMBERGER    SPE   115881    Reservoir Modelling
SCHLUMBERGER    SPE   102549    Reservoir Modelling
SCHLUMBERGER    SPE   107471    Reservoir Modelling
SCHLUMBERGER    SPE   119132    Reservoir Modelling
SCHLUMBERGER    SPE   121392    Reservoir Modelling
SCHLUMBERGER    SPE    93324    Reservoir Modelling
SCHLUMBERGER    SPE   100131    Reservoir Modelling
SCHLUMBERGER    SPE   119605    Reservoir Modelling
SCHLUMBERGER    SPE   121275    Reservoir Modelling
SCHLUMBERGER    SPE   121488    Reservoir Modelling
SCHLUMBERGER    SPE   106181    Reservoir Modelling
SCHLUMBERGER    SPE   107511    Reservoir Modelling
SCHLUMBERGER    SPE   122186    Reservoir Modelling
SCHLUMBERGER    SPE    95750    Reservoir Modelling
SCHLUMBERGER    SPE   100403    Reservoir Modelling
SCHLUMBERGER    SPE   118909    Reservoir Modelling
SCHLUMBERGER    SPE    96571    Reservoir Modelling
SCHLUMBERGER    SPE   118850    Reservoir Modelling
SCHLUMBERGER    SPE   105041   Reservoir Performance
SCHLUMBERGER    SPE   116063   Reservoir Performance
SCHLUMBERGER    SPE   102715   Reservoir Performance
SCHLUMBERGER    SPE    99240   Reservoir Performance
SCHLUMBERGER   IPTC    11772   Reservoir Performance
SCHLUMBERGER    SPE   122478   Reservoir Performance
SCHLUMBERGER    SPE   100024        SPE Forum
SCHLUMBERGER    SPE   115712     State of the Nation
SCHLUMBERGER    SPE   100607     State of the Nation
SCHLUMBERGER    SPE   101310     State of the Nation
SCHLUMBERGER    SPE   101140        Surveillence
SCHLUMBERGER    SPE   114027        Surveillence
SCHLUMBERGER    SPE   117963        Surveillence
SCHLUMBERGER    SPE   107119        Surveillence
SCHLUMBERGER    SPE   100992        Surveillence
SCHLUMBERGER    SPE   103589        Surveillence
SCHLUMBERGER    SPE   105362        Surveillence
SCHLUMBERGER   IPTC    12108        Surveillence
SCHLUMBERGER    SPE   115504        Surveillence
SCHLUMBERGER    SPE   126158        Surveillence
SCHLUMBERGER    SPE    93057        Surveillence
SCHLUMBERGER    SPE   112429        Surveillence
SCHLUMBERGER    SPE   110813        Surveillence
SCHLUMBERGER   IPTC    11262        Surveillence
SCHLUMBERGER   IPTC    11745        Surveillence
SCHLUMBERGER    SPE   102159        Surveillence
SCHLUMBERGER    SPE   104017        Surveillence
SCHLUMBERGER    SPE   104021        Surveillence
SCHLUMBERGER    SPE   115816        Surveillence
SCHLUMBERGER    SPE   116914        Surveillence
SCHLUMBERGER    SPE    90024        Surveillence
SCHLUMBERGER   IPTC    11971        Surveillence
SCHLUMBERGER    SPE   122604        Surveillence
SCHLUMBERGER    SPE   112221        Surveillence
SCHLUMBERGER   IPTC    11171        Surveillence
SCHLUMBERGER    SPE   115976        Surveillence
SCHLUMBERGER    SPE   121696        Surveillence
SCHLUMBERGER    SPE   119361        Surveillence
SCHLUMBERGER    SPE    94708        Surveillence
SCHLUMBERGER    SPE   101886        Surveillence
SCHLUMBERGER    SPE   110634         Surveillence
SCHLUMBERGER    SPE   110064         Surveillence
SCHLUMBERGER    SPE   116474         Surveillence
SCHLUMBERGER    SPE   116286         Surveillence
SCHLUMBERGER    SPE   102351         Surveillence
SCHLUMBERGER    SPE   103757         Surveillence
SCHLUMBERGER   IPTC    11433         Surveillence
SCHLUMBERGER    SPE   105166         Surveillence
SCHLUMBERGER    SPE   114337         Surveillence
SCHLUMBERGER    SPE   117892         Surveillence
SCHLUMBERGER    SPE   111174         Surveillence
SCHLUMBERGER    SPE   120558         Surveillence
SCHLUMBERGER    SPE   102309   Unconventional Reservoirs
SCHLUMBERGER    SPE   113600   Unconventional Reservoirs
SCHLUMBERGER    SPE   107985   Unconventional Reservoirs
SCHLUMBERGER    SPE   103232   Unconventional Reservoirs
SCHLUMBERGER    SPE   103327   Unconventional Reservoirs
SCHLUMBERGER    SPE   114974   Unconventional Reservoirs
SCHLUMBERGER    SPE   103202   Unconventional Reservoirs
SCHLUMBERGER    SPE   122934   Unconventional Reservoirs
SCHLUMBERGER    SPE   117704   Unconventional Reservoirs
SCHLUMBERGER    SPE   103514   Unconventional Reservoirs
SCHLUMBERGER    SPE   119636   Unconventional Reservoirs
SCHLUMBERGER   IPTC    12368      Well Deliverability
SCHLUMBERGER    SPE   126066      Well Deliverability
SCHLUMBERGER    SPE   110103      Well Deliverability
SCHLUMBERGER    SPE   106094      Well Deliverability
SCHLUMBERGER    SPE   102544      Well Deliverability
SCHLUMBERGER   IPTC    12364      Well Deliverability
SCHLUMBERGER    SPE   112476      Well Deliverability
SCHLUMBERGER    SPE   112862      Well Deliverability
SCHLUMBERGER    SPE   101720      Well Deliverability
SCHLUMBERGER    SPE   102583      Well Deliverability
SCHLUMBERGER    SPE   100834      Well Deliverability
SCHLUMBERGER    SPE   110240      Well Deliverability
SCHLUMBERGER   IPTC    11630      Well Deliverability
SCHLUMBERGER    SPE    84219      Well Deliverability
SCHLUMBERGER    SPE   120744      Well Deliverability
SCHLUMBERGER    SPE   126070      Well Deliverability
SCHLUMBERGER    SPE   126061      Well Deliverability
SCHLUMBERGER    SPE   102653      Well Deliverability
SCHLUMBERGER    SPE    96722      Well Deliverability
SCHLUMBERGER   IPTC    12668      Well Deliverability
SCHLUMBERGER    SPE   106050      Well Deliverability
SCHLUMBERGER    SPE   107979      Well Deliverability
SCHLUMBERGER    SPE   112438      Well Deliverability
SCHLUMBERGER    SPE   117061      Well Deliverability
SCHLUMBERGER    SPE   119825      Well Deliverability
SCHLUMBERGER    SPE   122307      Well Deliverability
SCHLUMBERGER    SPE   103822      Well Deliverability
SCHLUMBERGER    SPE   112435      Well Deliverability
SCHLUMBERGER    SPE   125336      Well Deliverability
SCHLUMBERGER    SPE   122514   Well Deliverability
SCHLUMBERGER    SPE   108126   Well Deliverability
SCHLUMBERGER    SPE   107604   Well Deliverability
SCHLUMBERGER    SPE   112171   Well Deliverability
SCHLUMBERGER    SPE    99419   Well Deliverability
SCHLUMBERGER    SPE   118292   Well Deliverability
SCHLUMBERGER    SPE   112442   Well Deliverability
SCHLUMBERGER    SPE   114768   Well Deliverability
SCHLUMBERGER    SPE   121204   Well Deliverability
SCHLUMBERGER    SPE   121415   Well Deliverability
SCHLUMBERGER    SPE   113562   Well Deliverability
SCHLUMBERGER    SPE   101722   Well Deliverability
SCHLUMBERGER    SPE   119300   Well Deliverability
SCHLUMBERGER    SPE   115556   Well Deliverability
SCHLUMBERGER    SPE   119635   Well Deliverability
SCHLUMBERGER    SPE   107730   Well Deliverability
SCHLUMBERGER    SPE   100572   Well Deliverability
SCHLUMBERGER    SPE   105657   Well Deliverability
SCHLUMBERGER    SPE    98338   Well Deliverability
SCHLUMBERGER    SPE   100524   Well Deliverability
SCHLUMBERGER    SPE   102677   Well Deliverability
SCHLUMBERGER    SPE   119586   Well Deliverability
SCHLUMBERGER   IPTC    11150   Well Deliverability
SCHLUMBERGER   IPTC    11347   Well Deliverability
SCHLUMBERGER    SPE   102326   Well Deliverability
SCHLUMBERGER    SPE   110068   Well Deliverability
SCHLUMBERGER    SPE   107662   Well Deliverability
SCHLUMBERGER    SPE   102788   Well Deliverability
SCHLUMBERGER    SPE   100556   Well Deliverability
SCHLUMBERGER    SPE   102167   Well Deliverability
SCHLUMBERGER    SPE   109909   Well Deliverability
SCHLUMBERGER    SPE   109969   Well Deliverability
SCHLUMBERGER    SPE   121888   Well Deliverability
SCHLUMBERGER    SPE    98188   Well Deliverability
SCHLUMBERGER    SPE   100321   Well Deliverability
SCHLUMBERGER    SPE   106225   Well Deliverability
SCHLUMBERGER    SPE   102469   Well Deliverability
SCHLUMBERGER    SPE   106317   Well Deliverability
SCHLUMBERGER    SPE   110696   Well Deliverability
SCHLUMBERGER    SPE   106264   Well Deliverability
SCHLUMBERGER    SPE   106043   Well Deliverability
SCHLUMBERGER    SPE   102570   Well Deliverability
SCHLUMBERGER    SPE   102405   Well Deliverability
SCHLUMBERGER    SPE    98746   Well Deliverability
SCHLUMBERGER    SPE   122018   Well Deliverability
SCHLUMBERGER   IPTC    12183   Well Deliverability
SCHLUMBERGER    SPE   119351   Well Deliverability
SCHLUMBERGER    SPE   104202   Well Deliverability
SCHLUMBERGER    SPE   106854   Well Deliverability
SCHLUMBERGER    SPE   113553   Well Deliverability
SCHLUMBERGER    SPE   114961   Well Deliverability
SCHLUMBERGER    SPE   112077   Well Deliverability
SCHLUMBERGER    SPE   120800   Well Deliverability
SCHLUMBERGER    SPE   123008   Well Deliverability
SCHLUMBERGER    SPE   120799   Well Deliverability
SCHLUMBERGER    SPE   110960   Well Deliverability
SCHLUMBERGER    SPE   113918   Well Deliverability
SCHLUMBERGER    SPE   103617   Well Deliverability
SCHLUMBERGER    SPE   104629   Well Deliverability
SCHLUMBERGER    SPE   116370   Well Deliverability
SCHLUMBERGER    SPE   120049   Well Deliverability
SCHLUMBERGER    SPE   105022   Well Deliverability
SCHLUMBERGER    SPE   106400   Well Deliverability
SCHLUMBERGER    SPE   102241   Well Deliverability
SCHLUMBERGER    SPE   112488   Well Deliverability
SCHLUMBERGER    SPE   104099   Well Deliverability
SCHLUMBERGER    SPE   120508   Well Deliverability
SCHLUMBERGER    SPE   101278   Well Deliverability
SCHLUMBERGER    SPE   112432   Well Deliverability
SCHLUMBERGER    SPE   113698   Well Deliverability
SCHLUMBERGER    SPE   111538   Well Deliverability
SCHLUMBERGER    SPE   119639   Well Deliverability
SCHLUMBERGER    SPE   121931   Well Deliverability
SCHLUMBERGER    SPE   121964   Well Deliverability
SCHLUMBERGER    SPE   110978   Well Deliverability
SCHLUMBERGER    SPE   112491   Well Deliverability
SCHLUMBERGER    SPE   105541   Well Deliverability
SCHLUMBERGER    SPE   117518   Well Deliverability
SCHLUMBERGER    SPE   105542   Well Deliverability
SCHLUMBERGER    SPE   128606   Well Deliverability
SCHLUMBERGER    SPE   112456   Well Deliverability
SCHLUMBERGER    SPE   105758   Well Deliverability
SCHLUMBERGER    SPE   107297   Well Deliverability
SCHLUMBERGER    SPE   121093   Well Deliverability
SCHLUMBERGER    SPE   121834   Well Deliverability
SCHLUMBERGER    SPE   121912   Well Deliverability
SCHLUMBERGER   IPTC    12448   Well Deliverability
SCHLUMBERGER    SPE    98151   Well Deliverability
SCHLUMBERGER   IPTC    12581   Well Deliverability
SCHLUMBERGER    SPE   123495   Well Deliverability
SCHLUMBERGER    SPE   112050   Well Deliverability
SCHLUMBERGER   IPTC    12385   Well Deliverability
SCHLUMBERGER    SPE   107440   Well Deliverability
SCHLUMBERGER    SPE   102185   Well Deliverability
SCHLUMBERGER    SPE   112904   Well Deliverability
SCHLUMBERGER    SPE   100944   Well Deliverability
SCHLUMBERGER    SPE   104239   Well Deliverability
SCHLUMBERGER    SPE    92715   Well Deliverability
SCHLUMBERGER    SPE   102242   Well Deliverability
SCHLUMBERGER    SPE    98315   Well Deliverability
SCHLUMBERGER    SPE   101087   Well Deliverability
SCHLUMBERGER    SPE    90383   Well Deliverability
SCHLUMBERGER    SPE   106272   Well Deliverability
SCHLUMBERGER    SPE   107978   Well Deliverability
SCHLUMBERGER   SPE   115525   Well Deliverability
SCHLUMBERGER   SPE   115528   Well Deliverability
SCHLUMBERGER   SPE    98221   Well Deliverability
SCHLUMBERGER   SPE    98357   Well Deliverability
SCHLUMBERGER   SPE   105127   Well Deliverability
SCHLUMBERGER   SPE   106321   Well Deliverability
SCHLUMBERGER   SPE   106442   Well Deliverability
SCHLUMBERGER   SPE   112419   Well Deliverability
SCHLUMBERGER   SPE   116601   Well Deliverability
SCHLUMBERGER   SPE   116775   Well Deliverability
SCHLUMBERGER   SPE   109911   Well Deliverability
SCHLUMBERGER   SPE   104610   Well Deliverability
SCHLUMBERGER   SPE   106444   Well Deliverability
SCHLUMBERGER   SPE   115558   Well Deliverability
SCHLUMBERGER   SPE   104627   Well Deliverability
SCHLUMBERGER   SPE   102681   Well Deliverability
SCHLUMBERGER   SPE   107966   Well Deliverability
SCHLUMBERGER   SPE   111431   Well Deliverability
SCHLUMBERGER   SPE    98055   Well Deliverability
SCHLUMBERGER   SPE   105367   Well Deliverability
SCHLUMBERGER   SPE   112176   Well Deliverability
SCHLUMBERGER   SPE   101420   Well Deliverability
SCHLUMBERGER   SPE   109860    Well Testing
SCHLUMBERGER   SPE   105134    Well Testing
SCHLUMBERGER   SPE   110576    Well Testing
SCHLUMBERGER   SPE   116969    Well Testing
SCHLUMBERGER   SPE   104059    Well Testing
SCHLUMBERGER   SPE   120515    Well Testing
SCHLUMBERGER   SPE   123115    Well Testing
SCHLUMBERGER   SPE   102575    Well Testing
SCHLUMBERGER   SPE   123555    Well Testing
SCHLUMBERGER   SPE   114594    Well Testing
SCHLUMBERGER   SPE   109279    Well Testing
SCHLUMBERGER   SPE   113650    Well Testing
SCHLUMBERGER   SPE   118148    Well Testing
SCHLUMBERGER   SPE   110873    Well Testing
SCHLUMBERGER   SPE   116003    Well Testing
SCHLUMBERGER   SPE   114127    Well Testing
SCHLUMBERGER   SPE   115478    Well Testing
SCHLUMBERGER   SPE    90992    Well Testing
SCHLUMBERGER   SPE   101475    Well Testing
SCHLUMBERGER   SPE   103223    Well Testing
SCHLUMBERGER   SPE   105271    Well Testing
SCHLUMBERGER   SPE   107967    Well Testing
SCHLUMBERGER   SPE   103040    Well Testing
SCHLUMBERGER   SPE   102106    Well Testing
        Section                         Subject
           Integrity
           Integrity
           Integrity
        Management                 Modelling - Integrated
    Modelling - Injection            Compositional
   Reservoir Description               Field Study
           Storage
           Storage
      Workshop Paper                 Capture/Storage
          PRODML                 Production Data Standards
             ERD                      World Record
   Field Re-development              Dumbarton Field
      Horizontal Well                Longest in World
       CO2 Injection
        CO2 Source
       Heterogeneity           Oligocene Vicksburg Formation
   Multilateral Sidetracks            Gas Condensate
    SAGD Optimisation                Easterm Venezuela
      Well Intervention                  Gas Shut-off
      Well Intervention            Undeveloped Reservoirs
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
      Well Intervention                 Water Shut-off
   Asphaltene Deposition               Risk Assurance
         Lab Testing                   Horizontal Pipes
         Lab Testing                    Inclined Pipes
Modelling - Integrated Asset        Production Alllocation
 Modelling - Well/Network             San Manuel Asset
     Wax/Asphaltenes                   Risk Reduction
       Waxy Crudes                        Deepwater
       CO2 Detection                         WFT
       CO2 Detection                         WFT
        Core Testing                Asphaltene Deposition
        Correlations                  Gas Condensate
        Correlations                  Gas Condensate
  Downhole Fluid Analysis                Asphaltenes
  Downhole Fluid Analysis                Case Study
  Downhole Fluid Analysis              Continuous Log
  Downhole Fluid Analysis         Neural Network Modelling
  Downhole Fluid Analysis              OBM Clean-up
  Downhole Fluid Analysis           Reservoir Architecture
  Downhole Fluid Analysis          Reservoir management
  Downhole Fluid Analysis          Reservoir management
Hydrogen Sulphide Detection                  WFT
   Insitu PVT Variations           Downhole Fluid Analysis
       Insitu PVT Variations                     Gas Condensate
       Insitu PVT Variations                     Integrated Data
       Insitu PVT Variations                     Integrated Data
       Insitu PVT Variations                  Optical Spectroscopy
       Insitu PVT Variations                Pressure Measurements
       Insitu PVT Variations           Pressure/insitu Fluid measurements
        Methane Detection                   Downhole Measurement
Modelling - Asphaltene Precipitation          Development Impact
   Modelling - Compositional                Downhole Fluid Analysis
          Modelling - EOS                     Insitu PVT Variations
    Modelling - Fluid Analysis             Fluid comparison Algorithm
  Modelling - Neural - Network              Downhole Fluid Analysis
       Optical Fluid Analysis               Downhole Fluid Samples
  Phase Envelope Construction                    Non-Isothermal
       Production Chemistry                          Heavy-oil
            PVT Analysis                              Onsite
              PVT Data                         Downhole Analysis
              PVT Data                                 WFT
              Sampling                        Carbonate Reservoir
              Sampling                      Contamination Detection
              Sampling                          Gas Condensate
              Sampling                              Multiphase
              Sampling                          Multiphase Meter
          Acid Treatments                          Deep Wells
       Chelating Technology                         Algyo Field
            Core Testing                         Acid Treatment
          Halite Inhibition
      Injection Water Quality              Horizontal Well Injectivitvity
 Modelling - Formation Damage                Naphthenate Induced
        Perforation Induced
      Performation Damage                           Removal
           Scale Control                       Stimulated Wells
        Scale Management                          Case Study
        Scale Management                        Intelligent Well
        Scale Management                       Strontium Sulfate
          Sulfate Stripping                        Gyda Field
  Modelling - History Matching             Identifying Flow Regions
      Modelling - Streamline               Fracture Characterisation
      Modelling - Streamline                    Sabiriyah field
     Reservoir Performance                 Modelling - Heterogeneity
            Surveillence                          Automation
            Surveillence                           Waterflood
    Waterflood Management                         Surveillence
             Artificial Lift                     Cavity Pumps
             Artificial Lift                  Downhole Heaters
              EOR/IOR                      Assisted Gravity drainage
              EOR/IOR                                  SAG
         Minor Reservoirs                        Development
       Reservoir Description                 Carbonate Reservoir
       Reservoir Description                          WFT
     Reservoir Development                      Horizontal wells
     Reservoir Development                      Steam Injection
             Stimulation                  Chemical Treatment
            Surveillence                  Production Logging
         Thermal Recovery                    Development
            Well Testing                   Multiphase Meter
            Well Testing                   Multiphase Meter
          Acid Treatments
          Data Acquisition                  Gas Condensate
        Exploration Process                       India
          Fluid Description               Insitu PVT Variations
          Fracturing Fluid
          Fracturing Fluid
            Lab Testing                      Acid Fracturing
        Perforation Methods             Coiled-Tubing-Conveyed
Permanent DH Pressure Monitoring                Gas Well
        Propped Fracturing                      Vietnam
             Stimulation                     Acid treatment
             Stimulation
       Surfactant Fracturing
     Water Block Prevention
     Water PH measurement               Laboratory Determination
     Asphatene Precipitation                   Capillary Flow
            Completion                        Horizontal wells
     Completion/Stimulation                   Horizontal wells
    Development Optimisation                    Challenges
       Fracture Diagnostics                     Case study
       Fracture Diagnostics           Impact of Pressure Depletion
       Fracture Diagnostics                Microseismic Data
             Fracturing                     Hybrid Fracturing
             Fracturing                       Fiber Assisted
   Horizontal Well Stimulation                Acid treatment
   Horizontal Well Stimulation                  Case Study
   Horizontal Well Stimulation             Propped Fracturing
          Horizontal Wells                Carbonate Reservoir
Modelling - Reservoir Performance        Production Forecasting
Modelling - Single well Performance      Optimised Completions
      Modelling - Streamline                Fluvial Reservoir
     Production Optimisation                   Heterogeneity
       Reservoir Description              Formation Evaluation
       Reservoir Description            Fracture Characterisation
       Reservoir Description                 Integrated Study
       Reservoir Description          Naturally Fractured Reservoirs
       Reservoir Description            Pressure Measurements
       Reservoir Description            Pressure Measurements
       Reservoir Description                       WFT
     Reservoir Development                     Heterogeneity
     Reservoir Management                     Horizontal wells
     Reservoir Performance               Reservoir Architecture
            Surveillence                  Formation Evaluation
            Surveillence                          Logging
          Transition Zones                Carbonate Reservoir
          Well Intervention                   Water Shut-off
      Development Strategy                     Heterogeneity
                 Stimulation                           Mini Fracturing
              Decision Making
              Decision Making
       Borehole Image Interpretation                     Case Study
             Capillary Pressure                     Carbonate Reservoir
        Deep Electromagnetic Data                       Heterogeneity
         Depositional Environment                     Borehole Images
         Depositional Environment                     Borehole Images
         Depositional Environment                   Integrated Well Data
          Downhole Fluid Analysis                 Reservoir Characterisation
          Downhole Fluid Analysis                 Reservoir Characterisation
        Flow Unit Characterisation                  Carbonate Reservoir
        Flow Unit Characterisation                    Deltaic Reservoir
           Formation Evaluation                             LWD
           Formation Evaluation                             LWD
           Formation Evaluation                     LWD vs Gamma Ray
           Formation Evaluation                     Shaly Sand Analysis
           Formation Evaluation                     Shaly Sand Analysis
           Formation Evaluation                           Workflow
Formation Evaluation - Enhanced description    Carbonate and Clastic Reservoirs
    Formation Evaluation - Heterogeneity            Carbonate Reservoir
    Formation Evaluation - Heterogeneity                 Deepwater
    Formation Evaluation - Heterogeneity            Perforation Selection
    Formation Evaluation - Heterogeneity                  Turbidites
    Formation Evaluation - Heterogeneity
 Formation Evaluation - Horizontal Injectors           LWD Modelling
Formation Evaluation - Integrated Well Data         Cambrian Reservoirs
   Formation Evaluation - Unconsolidated                 Deepwater
              Geomechanical                         Carbonate Reservoirs
               Geo-Modelling                         Channel Deposition
                Geostatistics                           Kharaib Field
                Geostatistics
               Heterogeneity                    Formation Evaluation Methods
               Heterogeneity                                NMR
             LWD Interpretation                   Mediterranean Reservoirs
             LWD Interpretation
             LWD Interpretation
      Mechanism - Stress Orientation                   Horizontal Wells
   Modelling - Geomechanical Properties                    Prediction
      Modelling - Near Wellbore Stress                     Algorithm
          Multi-Layered Reservoir                     PLT Interpretation
          Multi-Layered Reservoir                     PLT Interpretation
          Multi-Layered Reservoir                     PLT Interpretation
     Natural Fracture Characterisation                Borehole Seismic
     Natural Fracture Characterisation              Formation Evaluation
     Natural Fracture Characterisation                 Integrated Study
  Natural Fracture/Fault Characterisation             Borehole Images
       Naturally Fractured Reservoirs                    Maloichskoe
       Near Wellbore Flow Properties                Downhole Monitoring
       Near Wellbore Flow Properties                Downhole Monitoring
       Near Wellbore Flow Properties                Integrated Well Data
           Near Wellbore Stress
             NMR Interpretation                     Fractured Clastics
             NMR Interpretation                  Optimised WFT Sampling
             NMR Interpretation
             NMR Interpretation
                 NMR Logging
            Oil Interval Detection                 Formation Evalustion
              PLT Interpretation                       Horizontal Wells
        Porosity/Permeability Analysis             Carbonate Reservoirs
          Productivity Interpretation                        UBD
            Reservoir Architecture                    Fracture Fairways
            Reservoir Architecture                  Integrated Well Data
            Reservoir Architecture                  Integrated Well Data
            Reservoir Connectivity                Downhole Fluid Analysis
             Reservoir Properties                     PLT Interpretation
           Residual Oil Saturation                 Pulsed Neutron Decay
                      WFT                             Deltaic Reservoir
                      WFT                           Optimised Sampling
                      WFT                     Stress/Permeability Measurment
                      WFT                               Supercharging
               Integrated Study                           Betty Field
          Uncertainty Management                        Heterogeneity
                  Artificial Lift                     Selection Criteria
                   EOR/IOR                              Mature Fields
            Gas Lift Optimisation                        Surveillence
                Heterogeneity                          Well Placement
                Heterogeneity                  Well Placement Optimisation
              Low Pressure Gas                     Wellsite Compression
                 Methodology                             Life of Field
Modelling - Coupled Surface/Reservoir Model       Production Optimisation
Modelling - Coupled Surface/Reservoir Model             SMART wells
         Modelling - Integrated Asset            Development Optimisation
         Modelling - Integrated Asset              Gas Lift Optimisation
         Modelling - Integrated Asset             Production Optimisation
         Modelling - Integrated Asset             Production Optimisation
         Modelling - Integrated Asset                  Steam Injection
         Modelling - Integrated Asset             Uncertainty Management
         Modelling - Integrated Asset                     Workflow
         Modelling - Integrated Asset
         Modelling - Integrated Asset
         Modelling - Integrated Asset
       Produced Water Management                       XJG Fields
       Produced Water Management
           Production Optimisation                Gas Lift Optimisation
           Production Optimisation                    Mature Fields
          Productivity Improvement                  Integrated Study
             Reserves Evaluation                 Lower Vicksburg Sands
             Value of Information                      Framework
        Well Placement Optimisation                LWD Interpretation
        Well Placement Optimisation                LWD Interpretation
        Well Placement Optimisation             Production Potential maps
        Well Placement Optimisation             Real Time Pressure Data
        Well Placement Optimisation                 Selection Criteria
     Well Placement Optimisation                  Thin Oil Rim
        Adjoint Based Simulation         Well Placement Optimisation
            Analytical Model                         SAGD
       Analytical Reservoir Model                 Single Layer
      Analytical Well Performance          Multilayered Reservoirs
               Assisted HM                Adjoint Based Simulation
               Assisted HM                Adjoint Based Simulation
               Assisted HM                   Artificial Intelligence
               Assisted HM               Experimental Design Method
               Assisted HM               Face Recognition Technique
         Compaction Modelling                       Analytical
      Complex Physics Modelling                     Heavy Oil
      Complex Physics Modelling         Phase-Component Partitioning
        Complex Well Modelling                    Thin Oil Rim
        Complex Well Modelling
        Complex Well Modelling
        Complex Well Modelling
Coupled Reservoir/Geomechanical Model
 Coupled Thermal/Composional Model
         Decline Curve analysis
           Fracture Modelling                   3 Phase Model
           Fracture Modelling              3 Phase Clean-up Model
           Fracture Modelling             Fractured Horizontal Wells
           Fracture Modelling                  Gas Condensate
           Fracture Modelling                      Geometry
           Fracture Modelling                  Horizontal Wells
           Fracture Modelling             Non-Darcy/Perforation Flow
           Fracture Modelling                     Probablistic
           Fracture Modelling                  Productivity Index
           Fracture Modelling                Transverse Fractures
           Fracture Modelling
      Fracture Spacing pPediction              Neural Networks
                 Gridding                       Optimisation
        Heterogeneity Modelling
          Inflow Performance                Temperation Prediction
      Injectivity Productivity Index
            Material Balance              Complex Mature Reservoirs
            Material Balance               Uncertainty Management
       Mature Field History Match
                Mechanism                  Diffusion and Convection
   Modelling - Experimental Design                 Experience
              Modelling data                     Capillary data
     Multipoint Flux Approximation                 Upscaling
    Naturally Fractured Reservoirs      Dual Porosity Model Applicability
    Naturally Fractured Reservoirs           Gas Oil Displacement
    Naturally Fractured Reservoirs              History Matching
    Naturally Fractured Reservoirs            Multiple Reservoirs
    Naturally Fractured Reservoirs                Streamlines
    Naturally Fractured Reservoirs                Streamlines
    Naturally Fractured Reservoirs                Streamlines
       Numerical - Conceptional            Production Optimisation
         Prediction Uncertainty               PUNQ-S3 Problem
          Proxy Modeling              Production Optimisation
          Scale Modelling                  Streamlines
     Shared Earth Modelling
      Steamflood Modelling                   PEBI Grid
             Streamline              Adaptive Mesh Refinement
             Streamline                   Multicomponent
     Type Curve Forecasting               Well Placement
    Uncertainty Management          Ensemble based Application
    Uncertainty Management              Ranking GeoModels
           Wellbore Flow              Annuus and Tubing Flow
     Wellstream Composition             Black-Oil Delumping
     Wellstream Composition             Black-Oil Delumping
             Mechanism                  Effect of Wettability
             Mechanism                    Fines Migration
             Mechanism                    Non-Dacy Flow
 Mechanism - Transition zone flow      Carbonate Reservoirs
                UBD                        Margham Field
         Wellbore Stability               Stress Patterns
          Smarter Fields               Change Management
         EOR Techniques                        Russia
      Province Comparison           UKCS vs Alaska North Slope
         Well Intervention                 Zonal Isolation
     By-passed Oil Detection               Mature Fields
     By-passed Oil Detection            Pulse Neutron Logs
     By-passed Oil Detection
          Complex Wells                Downhole Flowrates
          Complex Wells                   Inflow Profiling
          Complex Wells                         PLT
  Condensate Banking Detection        Multiphase Flowmeters
          Data Acquisition            Challenging Conditions
          Data Acquisition            Challenging Conditions
      Downhole Monitoring               Multiple Reservoirs
   Downhole PH Measurement             Optical Spectroscopy
  Formation Damage Detection
      Fracture Diagnostics            Microseismic Monitoring
      Fracture Diagnostics           Temperature Log Analysis
       Gas Entry Detection
       Inflow Performance            SAGD - Horizontal Wells
           Inflow Profiling            Pulse Neutron Logs
           Inflow Profiling            Pulse Neutron Logs
           Inflow Profiling            Temperature Data
           Inflow Profiling                  Tracers
       Multiphase Metering                 Downhole
   Naturally Fracture Detection
   Pemanent Downhole Gauge                   Feasibility
     Performance Prediction                Assessment
        PLT Interpretation            Challenging Conditions
       Pressure Monitoring             Greater Burgan Field
      Production Monitoring             Temperature Data
      Real-Time Monitoring                  Case Study
      Real-Time Monitoring                     WFT
Reservoir Pressure/GOR Monitoring       Tempreture Data
   SAGD Monitoring                  Tiltmeters
    Sand Production           Temperature Sensors
  Sandface Monitoring          Completion Design
 Theif Zone Dectection          Borehole Images
  Value of Information       Opportunistic/Guaranteed
    Virtual Metering
 Water Entry Detection           Horizontal wells
 Water Entry Detection           Horizontal wells
 Water Entry Detection       Resistivity Measurement
 Water Front Tracking                   LWD
       Waterflood            Electromagnetic Surveys
       Waterflood            Electromagnetic Surveys
          Coal                  Perforation Testing
   Coalbed Methane           Completion Optimisation
   Coalbed Methane              Indirect Fracturing
 Completion Strategies           Horizontal Wells
    Fracture Design                Heterogeneity
    Fracture Design
 Reservoir Description    Horizontal Well Characterisation
  Reservoir Modelling
          SAG                     Well Optimisation
   State of the Nation    Petroleum Engineering Advances
       Stimulation                   Refracturing
    Acid Treatments            Production Optimisation
      Artificial Lift                   ESP's
      Artificial Lift                 SAGD ESP
      Artificial Lift             Staircase Lifting
Completion Optimisation           Horizontal Wells
Completion Optimisation           Manati Gas Filed
Completion Optimisation        Multilayered Reservoirs
Completion Optimisation         Near Wellbore Stress
Completion Optimisation
Completion Optimisation
    Complex Wells              Carbonate Reservoir
    Complex Wells               Complex Reservoirs
    Complex Wells            Downhole Control Valves
    Complex Wells            Downhole Control Valves
    Complex Wells            Downhole Control Valves
    Complex Wells                   Intervention
    Complex Wells             Production Performance
          ESP                   Perforation Methods
          ESP                  Performance Analysis
    Fracture Design               Acid Fracturing
    Fracture Design             Candidate selection
    Fracture Design                Fiber Assisted
    Fracture Design                Fiber Assisted
    Fracture Design                Fiber Assisted
    Fracture Design                Fiber Assisted
    Fracture Design                Flowback Aids
    Fracture Design         Formation Modulus Contrast
    Fracture Design                Fracture Fluid
    Fracture Design         Fracture Fluids Optimisation
  Fracture Design           Fracture Geometry
  Fracture Design          Fracture Propagation
  Fracture Design              Height Control
  Fracture Design       Horizontal Well Application
  Fracture Design              Mature Fields
  Fracture Design       Multifrac Horizontal Wells
  Fracture Design                Multistage
  Fracture Design       Multistage Horizontal Wells
  Fracture Design       Multistage Horizontal Wells
  Fracture Design       Multistage Horizontal Wells
  Fracture Design               Optimisation
  Fracture Design          Performance Criteria
  Fracture Design           Proppant Transport
  Fracture Design        Samara Area Reservoirs
  Fracture Design        Simultaneous Fracturing
  Fracture Design       Sliding Sleeve Application
  Fracture Design       Sliding Sleeve Applocation
  Fracture Design             Soft Formations
  Fracture Design          Surfactant Fracturing
  Fracture Design          Surfactant Fracturing
  Fracture Design          Surfactant Fracturing
  Fracture Design          Surfactant Fracturing
  Fracture Design
Fracture Diagnostics          Acid Fracturing
Fracture Diagnostics             Clean-up
Fracture Diagnostics     Completion Optimisation
Fracture Diagnostics         Damage Analysis
Fracture Diagnostics        Deviation Surveys
Fracture Diagnostics          Fiber Assisted
Fracture Diagnostics       Fracture Conductivity
Fracture Diagnostics        Fracture Geometry
Fracture Diagnostics        Fracture Geometry
Fracture Diagnostics        Fracture Geometry
Fracture Diagnostics         Gas Condensate
Fracture Diagnostics         Gas Condensate
Fracture Diagnostics   High Permeability Formations
Fracture Diagnostics     Long-Term Rate Effects
Fracture Diagnostics         Low-Conductivity
Fracture Diagnostics     Microseismic Monitoring
Fracture Diagnostics        Proppant Flowback
Fracture Diagnostics            Refracture
Fracture Diagnostics      Reseridual Saturation
Fracture Diagnostics         Sonic Anisotropy
Fracture Diagnostics        State of the Nation
Fracture Diagnostics     Water Injector Fracturing
Fracture Diagnostics
Fracture Dignostics         Fracture Geometry
  Gas Lift Systems                Theory
  Gas Production              High rate wells
   Horizontal Well           Novel Open hole
   Horizontal Well           Novel Open hole
   Horizontal Well             OBM Effect
        Intelligent Well              Complex Wells
        Intelligent Well          Downhole Control Valves
        Intelligent Well                    ESP's
        Intelligent Well          Production Optimisation
        Intelligent Well          Uncertainty Management
  Lab Testing - Fracturing             Heterogeneity
 Modelling - Flow Assurance       Productivity Improvement
 Modelling - Well Productivity         Heterogeneity
Modellling - Sanding Prediction
    Perforation Methods              Carboate Reservoir
    Perforation Methods                 Case study
    Perforation Methods                Coiled Tubing
    Perforation Methods                 Dynamic UB
    Perforation Methods            Negative Skin Factors
    Perforation Methods                  Orientation
    Perforation Methods           Productivity Improvement
    Perforation Methods           Skin Variation Quantified
    Perforation Methods               UnderBalanced
    Perforation Methods
    Perforation Methods
    Perforation Methods
    Perforation Methods
  Production Optimisation          SMART Completions
         Sand Control                  Albacora Field
         Sand Control             Completion Optimisation
         Sand Control                 Complex Wells
         Sand Control                      Failure
         Sand Control                Failure Mitigation
         Sand Control                     Failures
         Sand Control                   Gravel Pack
         Sand Control                   Gravel Pack
         Sand Control                   Gravel Pack
         Sand Control                   Gravel Pack
         Sand Control                   Gravel Pack
         Sand Control              Gravel Pack Modelling
         Sand Control                 Gravel Packing
         Sand Control                   Optimisation
         Sand Control              Perforate/Gravel Pack
         Sand Control               Perforation Method
         Sand Control               Screen Technology
         Sand Control             Screenless Completions
         Sand Control                     Screens
     Sand Management                     Sarir Field
       Sand Production              Accurate Pediction
       Sand Production                  Case Study
       Sand Production              Effect of water-Cut
       Sand Production                 Mature Fields
       Sand Production               Wellbore Stability
       Sand Production               Wellbore Stability
     State of the Nation               Acid treatment
          Stimulation                 Acid Fracturing
          Stimulation                 Acid Fracturing
               Stimulation                            Acid Fracturing
               Stimulation                            Acid Fracturing
               Stimulation                            Acid treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                           Acid Treatment
               Stimulation                    Chelating Agent Application
               Stimulation                       Combined Treatments
               Stimulation                        Diversion Techniques
               Stimulation                           Foam Fracturing
               Stimulation                            Heterogeneity
               Stimulation                             Restimulation
               Stimulation                        Surfactant Fracturing
               Stimulation                        Surfactant Fracturing
       Stimulation Optimisation                        Mature Fields
            Water Blocking                           Gas Reservoirs
       Water Control/Stimulation                  Sufactant Treatment
             Zonal Isolation                        CBL Interpretation
  Analysis - Closed Chamber Tests
      Analysis - Horizontal Wells                 Carbonate Reservoir
   Analysis - Multi-Fractured Wells                Stacked Reservoirs
    Analysis - Multilayer Reservoir                  Layer Properties
Analysis - Naturally Fractured Reservoir            Partial Penetration
  Analysis - Radius of Investigation               Reserve Estimation
   Analysis - Real Time Evaluation
             Deconvolution
           Exploration Wells                   Design and Interpretation
          Fracture Diagnostics                          Image Log
                Mini-DST                                Deepwater
        MiniDST Interpretation                              Gas
          Multiphase Metering                    Challenging Conditions
          Multiphase Metering                        Gas Condensate
          Multiphase Metering                            Heavy Oil
          Multiphase Metering                            Reliability
          Multiphase Metering                            Validation
          Multiphase Metering
          Multiphase Metering
          Multiphase Metering
          Numerical Modelling                     Full Field Simulations
          Production Analysis                 Integral Derivative Function
           State of the Nation         Advances in Interpretation and Measurement
  Streaming Potential Measurement                Technology Application
                                              Title
Assessing Long-Term CO2 Containment Performance: Cement Evaluation in Otway CRC-1
Stress Estimation at the Otway CO2 Storage Site, Australia
CO2 Storage - Managing the Risk Associated With Well Leakage over Long Timescales
Optimizing CO2 Injection and Storage: A New Approach Using Integrated Asset Modeling
Simulations for CO2 Injection Projects With Compositional Simulator
Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Research Storage and Verific
CO2 Sequestration - A Safe Transition Technology
CO2 Storage Geomechanics for Performance and Risk Management
Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop (ATW) on Carbon Sequestr
Production Data Standards: The PRODML Business Case and Evolution
World-Record ERD Well Drilled From a Floating Installation in the North Sea
Dumbarton Field, UKCS: Rapid Redevelopment of a Complex, Mature North Sea Asset Using New Rotary-Steerable and Geos
How Continuous Improvement Lead to the Longest Horizontal Well in the World
EOR Potential of the Michigan Silurian Reefs Using CO2
Quebrache--A Natural CO2 Reservoir: A New Source for EOR Projects in Mexico
Oligocene Vicksburg Thin-Bed Production Optimization Derived From Oil-Based Mud Imaging: A Case Study
Simulation Study of Re-Entry Drilling for Gas/Condensate Reservoir Development
Applicability and Optimization of SAGD in Eastern Venezuela Reservoirs
Challenging Chemical Gas Shut Off In a Fractured Carbonate Reservoir—Case Studies
Recovery of Bypassed Reserves Above Top Packer Using Innovative Cement Packer and Through Tubing Add Perforation
Production Improvement Water Shut-Off for White Tiger Field
Case Study in Water Shutoff Fluid Placement Using Straddled Through-Tubing Inflatable-Packers Technique
Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields)
Successful Water Shut-off in Open Hole Horizontal Well Using Inflatables
Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone Reservoir
Horizontal Water Shut-Off for Better Production Optimization and Reservoir Sweep Efficiency (Case Study)
Successful Utilization of Fiber Optic Telemetry Enabled Coiled Tubing for Water Shut-off on a Horizontal Oil Well in Ghawar Fie
A Holistic Approach to Production Assurance
Characterization of Oil/Water Flows in Horizontal Pipes
Characterization of Oil/Water Flows in Inclined Pipes
A Rigorous Well Model To Optimize Production From Intelligent Wells and Establish the Back-Allocation Algorithm
Integration of Production and Process Facility Models in a Single Simulation Tool - PEMEX E&P San Manuel Asset
Impact of Flow Assurance in the Development of a Deepwater Prospect
Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils
Quantification of Carbon Dioxide Using Downhole Wireline Formation Tester Measurements
First Field Application of Downhole CO2 Measurement in Asia Pacific
Core Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East Kuwait
Tools To Manage Gas/Condensate Reservoirs; Novel Fluid-Property Correlations on the Basis of�Commonly Available Field
New Modified Black-Oil Correlations for Gas Condensate and Volatile Oil Fluids
Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid Analysis
Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia
Continuous Downhole Fluid Log Powered by an Integrated Approach Reveals Reservoir Fluid Complexities and Minimizes Unc
Application of Artificial Neural Networks to Downhole Fluid Analysis
Compositional Modeling of Oil-Based Mud-Filtrate Cleanup During Wireline Formation Tester Sampling
New Downhole Fluid Analysis (DFA) Technologies Supporting Improved Reservoir Management
Applying Downhole Fluid Analysis and Wireline-Formation-Testing Techniques in Reservoir Management and Well Completion
Advanced Formation Testing in OBM Using Focused Fluid Sampling for Producibility Evaluation in Mature Fields
Low-Level Hydrogen Sulphide Detection Using Wireline Formation Tester
Integration of Fluid Log Predictions and Downhole Fluid Analysis
How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs?
Integration of Geochemical, Mud-Gas, and Downhole-Fluid Analyses for the Assessment of Compositional Grading—Case Stu
Fluid Identification Challenges in the Near Critical Fluids: Case Studies in Malaysia
Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy
Pressure Measurement and Pressure Gradient Analysis: How Reliable For Determining Fluid Density and Compositional Gradi
Integration of In-Situ Fluid Measurements for Pressure Gradients Calculations
Downhole Measurement of Methane Content and GOR in Formation Fluid Samples
Modeling the Effect of Asphaltene on the Development of the Marrat Field
EOS-Based Downhole Fluid Characterization
Advanced Compositional Gradient Analysis
Downhole Fluid Analysis and Fluid-Comparison Algorithm as Aid to Reservoir Characterization
Application of Artificial Neural Networks to Downhole Fluid Analysis
Enhanced Characterization of Multi-Phase Downhole Fluid Samples Using a Full Spectrum Weighted Regression Analysis
Practical and Robust Isenthalpic/Isothermal Flashes for Thermal Fluids
Rheology of Heavy-Oil Emulsions
Reservoir Fluid Analysis Using PVT Express
Downhole Fluid Analysis Integrating Insitu Density and Viscosity Measurements - Field Test from an Oman Sandstone Formati
In-Situ Density and Viscosity Measured by Wireline Formation Testers
Fluid Sampling in Carbonates-Challenges and Best Practices
Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination
Wireline Gas-Condensate Sampling: A Unique, Proven Solution
An Innovative Multiphase Sampling Solution at the Well Site to Improve Multiphase Flow Measurements and Phase Behavior C
Sampling With Multiphase Flowmeter in Northern Siberia—Condensate Field Experience and Sensitivities
Reaction of Simple Organic Acids and Chelating Agents With Calcite
Novel Chelating-Based Technology Application in Complex and Heterogeneous Injector Wells in the Algyo Field, Hungary
Sandstone Cores as Reaction Vessels: Synthesis of Calcium Carbonate Particles for Artificial Formation Damage in the Qualifi
Mechanistic Study of Chemicals Providing Improved Halite Inhibition
Taking Advantage of Injectivity Decline for Sweep Enhancing during Waterflood with Horizontal Injectors
Mechanisms, Parameters, and Modeling of Naphthenate-Soap-Induced Formation Damage
New Fundamental Insights into Perforation-Induced Formation Damage
Perforation Damage Removal by Underbalance Surge Flow
First Application of Scale Inhibitor During Hydraulic Fracturing Treatments in Western Siberia
Optimization of a Scale Treatment in the Uinta Basin—A Case History
Impact of Intelligent Wells on Oilfield Scale Management
Techniques Used To Monitor and Remove Strontium Sulfate Scale in UZ Producing Wells
Impact of In-Situ Sulfate Stripping on Scale Management in the Gyda Field
Optimal Region Delineation in a Reservoir for Efficient History Matching
Fracture Lineament Validation using Streamline Simulation in a Giant Middle East Field: An Innovative Approach
Streamline Simulation for Reservoir Management of a Super Giant: Sabiriyah Field North Kuwait Case Study
Managing Water and Gas Production Problems in Cantarell: A Giant Carbonate Reservoir in Gulf of Mexico
Automatic Surveillance System for Large Gas Fields With Multifrequency Measurements
Tracking Interwell Water Saturation in Pattern Flood Pilots in a Giant Gulf Oil field
Pattern Balancing and Waterflood Optimization of a Super Giant: Sabiriyah Field, North Kuwait, a Case Study
Producing Extra-Heavy Oil from the Orinoco Belt, Cerro Negro Area, Venezuela, Using Bottom-Drive Progressive Cavity Pump
Feasibility of using Electrical Downhole Heaters in Faja Heavy Oil Reservoirs
Microwave Assisted Gravity Drainage of Heavy Oils
Horizontal Alternating Steam Drive Process for the Orinoco Heavy Oil Belt in Eastern Venezuela
Development of Small Size-Heavy-Oil Field With Innovative Technology
Characterization of Complex Carbonate Heavy Oil Reservoir—A Case Study
A Technique for Measuring Permeability Anisotropy and Recovering PVT Samples in a Heavy Oil Reservoir in North West Sibe
Developing Heavy Oil Field By Well Placement - A Case Study
Optimizing Horizontal-Well Steam-Stimulation Strategy for Heavy-Oil Development
Smart Chemical Systems for the Stimulation of High-Water-Cut Heavy Oil Wells
Horizontal-Well-Production Logging Experience in Heavy-Oil Environment With Sand Screen: A Case Study From Kuwait
Thermal Simulation and Economic Evaluation of Heavy-Oil Projects
Case Study in Venezuela: Performance of Multiphase Meter in Extra Heavy Oil
Methodology of Calibration for Nucleonic Multiphase Meter Technology for SAGD Extra Heavy Oil
Investigation of a New Single-Stage Sandstone Acidizing Fluid for High-Temperature Formations
Formation Testing and PVT Sampling in Low-Permeability, High-Pressure Gas Condensate Reservoirs by Example of Achimov
Successful Application of Exploration Lessons Learnt To Deliver Stretch HT/HP Well Delivery Objectives (Krishna Godavari Ba
Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data
A New Shear-Tolerant High-Temperature Fracturing Fluid
New Fracturing Fluid for High Temperature Reservoirs
Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs
Coiled-Tubing-Conveyed Perforating for High-Pressure/High-Temperature Environment in Mexico Marine
First High Pressure and High Temperature Digital Electric Intellitite Welded Permanent Down Hole Monitoring System for Gas W
Case Study from 12 Successful Years of High Temperature Fracturing in Bach Ho Field Offshore Vietnam
Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sandstone-Acidizing System
Stimulation of High-Temperature Sandstone Formations From West Africa With Chelating Agent-Based Fluids
Successful Application of High-Temperature Viscoelastic Surfactant (VES) Fracturing Fluids Under Extreme Conditions in Pata
Wettability Alteration for Water-Block Prevention in High-Temperature Gas Wells
Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures
Recent Developments in the Deposition of Colloidal Asphaltene in Capillary Flow: Experiments and Mesoscopic Simulation
Optimizing Horizontal Completions in the Cleveland Tight Gas Sand
Horizontal Well Completion and Stimulation Techniques--A Review With Emphasis on Low-Permeability Carbonates
The key challenges for Optimization of a Tight Gas Field Developments Using a Multi-Domain Integrated Process- Application
Observations From Tight Gas Reservoir Stimulations in the Rocky Mountain Region
Reservoir Pressure Depletion and Water Flooding Influencing Hydraulic Fracture Orientation in Low-Permeability Oilfields
Characterization of Hydraulically-Induced Fracture Network Using Treatment and Microseismic Data in a Tight-Gas Formation:
Application of Hybrid Fracture Treatment to Tight Gas Sands in East Texas Cotton Valley Sands
Benefits of the Novel Fiber-Laden Low-Viscosity Fluid System in Fracturing Low-Permeability Tight Gas Formations
Increasing Reservoir Contact by Combining Mechanical Diversion and Unique Stimulation Chemistry
Multiple Transverse Fracturing in Horizontal Open Hole Allows Development of a Low-Permeability Reservoir in the Foukanda F
Multiple Proppant Fracturing Treatments Unleashed High Gas Rate From an Openhole Horizontal Tight Gas Reservoir in Centr
Horizontal Drilling Application To Recover Incremental Oil in Low-Permeability Carbonate Reservoirs, Partitioned Neutral Zone
Well Production Forecast in a Tight Gas Reservoir—Closing the Loop With Model-Based Predictions in Jonah Field, Wyoming
Uinta Basin Single-Well Model to Optimize Tight Gas Completions
Numerical Simulation of Thick, Tight Fluvial Sands
Fracturing Previously Bypassed Highly Laminated Tight Gas Sands, A Production Optimization Case Study in South Texas
A New Formation-Evaluation Technique for the Lower Tertiary in South Texas--Predicting Production in Low-Permeability, Fine
Fracture and Sub-Seismic Fault Characterization for Tight Carbonates in Challenging Oil-Based Mud Environment—Case Stu
Multidisciplinary Approach and New Technology Improve Carbonate Reservoir Evaluation
Applied Natural Fracture Characterization Using Combination of Imagery and Transient Information: Case Studies From Camb
A Case Study: Using Wireline Pressure Measurements to Improve Reservoir Characterization in Tight Formation Gas – Wam
A Case Study: Using Wireline Pressure Measurements To Improve Reservoir Characterization in Tight Formation Gas—Wam
Best Practices for Formation Testing in Low Permeability Reservoirs
Field-Development Case Study: Production Optimization Through Continuous Multidisciplinary Reservoir and Production Monit
Horizontal Wells in Tight Gas Sands--A Method for Risk Management To Maximize Success
Low Porosity Fractured Reservoir Characterization For Exploration and Horizontal Drilling
Data Acquisition and Formation Evaluation Strategies in Anisotropic, Tight Gas Reservoirs of the Sultanate of Oman
Optimum Logging Programs in Tight Sands
Identification and Characterization of Transition Zones in Tight Carbonates by Downhole Fluid Analysis
Successful Innovative Water-Shutoff Operations in Low-Permeability Gas Wells
Stepping on Development of Small and Medium Size Oilfields through Horizontal Wells—The Way Ahead
Mini Fracturing: A New Horizon of Breakthrough Integrated Technology for Small Fields
Analysis of Multicriteria Decision-Making Methodologies for the Petroleum Industry
Judgment Elicitation Process for Decision-Making in the Oil and Gas Industry
The Importance of Hole Quality for Effective Image Log Interpretation Clearly Demonstrated in an Eight Well Program in Kuwai
Application of NMR T2 Relaxation for Drainage Capillary Pressure in Vuggy Carbonate Reservoirs
Characterization of Reservoir Heterogeneity Through Fluid Movement Monitoring With Deep Electromagnetic and Pressure Me
Integration of borehole image log enhances conventional electrofacies analysis in dual porosity carbonate reservoirs
Reconstructing Sedimentary Depositional Environment With Borehole Imaging and Core: A Case Study From Eastern Offshore
Sedimentary Facies Computation and Stratigraphic Analyses Using Well Logs, Borehole Images and Cores in Triassic Fluvial S
New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization
Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia
Porosity Partitioning and Flow Unit Characterization From an Integration of Magnetic-Resonance and Borehole-Image Measure
Flow Unit Characterization and Geo-modeling of a Structurally Complex Fluvio-deltaic Reservoir using an Integrated Approach
A New-Generation LWD Tool With Colocated Sensors Opens New Opportunities for Formation Evaluation
New Developments in Sourceless Logging-While-Drilling Formation Evaluation: A Case Study From Southern Italy
Why the LWD and Wireline Gamma Ray Measurements May Read Different Values in the Same Well
Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertainty Quantification of Volum
Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertainty Quantification of Volum
A New Workflow for Comprehensive Petrophysical Characterization of Carbonate Reservoirs Drilled with Water-Base Muds
Enhanced Reservoir Description in Carbonate and Clastic Reservoirs
Case Study of Permeability, Vug Quantification, and Rock Typing in a Complex Carbonate
Applications of NMR Logs and Borehole Images to the Evaluation of Laminated Deepwater Reservoirs
Integration of Borehole Imaging, Open Hole Logs, Nuclear Magnetic Resonance/Modular Dynamic Tester, and Advanced Prod
Evaluation of Low-Resistivity-Pay Deepwater Turbidites Using Constrained Thin-Bed Petrophysical Analysis
Formation Evaluation in Thin Sand/Shale Laminations
Formation Evaluation of Horizontal Water Injectors Drilled in Thick Carbonate Reservoirs: Behind-Casing-Analysis and LWD R
Integration of Production, Pressure Transient and Borehole Images in Horizontal Wells Drilled in Cambrian Sandstone Reservo
Specialized Techniques for Formation Testing and Fluid Sampling in Unconsolidated Formations in Deepwater Reservoirs
Geomechanics Insight Into Discrepancies of Core to Image Log Discontinuities and Implications for a Lower Cretaceous Carbo
Exploration Potential of Sinuous (Channellike) Events in Late Cretaceous of Al-Khafji Field, Middle East
Understanding a Reservoir: 3D Geological Modelling Using Scenario-Based Approach and Conventional Geostatistics, Onshor
Frequentist Meets Spatialist: A Marriage Made in Reservoir Characterization and Modeling
Methods for Real-Time and High-Resolution Formation Evaluation and Formation Testing of Thinly Bedded Reservoirs in Explo
NMR Petrophysics in Thin Sand/Shale Laminations
Successful Application of New LWD Platform Provides Integrated Real-Time Formation Evaluation in the Mediterranean Reser
Improving LWD Image and Formation Evaluation by Utilizing Dynamically Corrected Drilling-Derived LWD Depth and Continuou
From Issues to Solutions – Introducing the Multi Function Logging While Drilling Tool for Reservoir Characterization in the Gr
Stress Reorientation Around Horizontal Wells
Prediction of Rock Mechanical Parameters for Hydrocarbon Reservoirs Using Different Artificial Intelligence Techniques
Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data
Characterization of Multilayer Reservoir Properties Using Production Logs
Characterization of Commingled Reservoir Properties With Production Logs
Evaluation of Commingled Reservoir Properties Using Production Logs
An Approach to Fracture Characterization Using Borehole Seismic Data
Integrated Fracture Study using Formation Micro Imager, Stoneley Waves and Formation Evaluation Results in Carbonate Res
Continuous Fracture Modeling of a Carbonate Reservoir in West Siberia
Characterization of Fractures and Faults From High-Resolution Image Logs To Optimize the Geological Model of a Fractured C
Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir in the West Siberian Baseme
Determination of In-Situ Two-Phase Flow Properties Through Downhole Fluid Movement Monitoring
The Impact of the Downhole Formation Tester with Comprehensive Data Integration in Pre-Khuff Hydrocarbon Exploration
An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Pressure Transient Testin
Radial Profiling for Completion Effectiveness With New Sonic Measurement in the Gulf of Thailand
Porosity With Nuclear Magnetic Resonance in Naturally Fractured Clastics Reservoirs in the Devonian of the Bolivian Sub-And
Using the Continuous NMR Fluid Properties Scan to Optimize Sampling with Wireline Formation Testers
The Application of NMR Logs for the Evaluation of Gas Reservoirs With Low Salinity Formation Waters
Porosity Determination From NMR Log Data: The Effects of Acquisition Parameters, Noise, and Inversion
Advances in NMR Logging
Optimization of the Prediction of Hydrocarbon-Producing Zones Through Integration of Petrophysical Evaluation Methodologies
Comprehensive Reservoir Characterization with Multiphase Production Logging
A New Porosity Partitioning-Based Methodology for Permeability and Texture Analysis in Abu Dhabi Carbonates
Simulation of Inflow While Underbalanced Drilling With Automatic Identification of Formation Parameters and Assessment of U
Utilizing Real Time Logging While Drilling Resistivity Imaging to Identify Fracture Corridors in a highly fractured Carbonate Rese
Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for an Improved Understan
Improved Interpretation of Reservoir Architecture and Fluid Contacts Through the Integration of Downhole Fluid Analysis With G
Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity
Characterization of Reservoir Properties Using Production Logs
Remaining Oil Investigation in a High Recovery Oilfield
Development and Use of Improved Wireline Formation Tester Technologies in the Challenging Deltaic Reservoirs
Enhancing Formation Testing and Sampling Operations Through the Use of Log-Derived High-Resolution Mineral-Based Lithof
Direct Measurements of Minimum Horizontal Stress, Permeability, and Permeability Anisotropy in a Siberian Oil Field Using a W
A Method for Analysis of Pressure Response With a Formation Tester Influenced By Supercharging
Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints and Uncertainties
Reducing Uncertainty Through Downhole Fluid Analysis: A Field Case Study
Selection Criteria for Artificial Lift Technique in Bokor Field
New Life for a Mature Oil Province via the Integration of Improved Recovery Methods
An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Field, East Malaysia
Differentiating Well Placement Expectations in Saudi Arabia with Production from Stringer Sand Reservoirs
Implementing the Optimum Well Placement Strategy for Horizontal Injectors Drilled in Highly Heterogeneous Reservoirs of Cen
Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors
An Integrated Computer Based Method to Maximize Infill Drilling, Sidetracking, and Workover Potential in Multiple Stacked Hyd
Flaring, Gas Injection and Reservoir Management Optimization: Preserving Reservoir Energy Maximizes Recovery and Prolong
Coupling a Reservoir Simulator With a Network Model to Evaluate the Implementation of Smart Wells on the Moporo Field in V
Integrated Optimization of Field Development, Planning, and Operation
A New Approach to Gas Lift Optimization Using an Integrated Asset Model
Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore Malaysia
An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan
Energy Balance in Steam Injection Projects Integrating Surface-Reservoir Systems
A Successful Process for Embracing Uncertainty and Mitigating Risk - From Geological Understanding to Development Plan O
Breaking the Barriers-The Integrated Asset Model
From Reservoir Through Process, From Today to Tomorrow—The Integrated Asset Model
Integration of Production and Process Facility Models in a Single Simulation Tool
Integrated Studies on a Conveyor Belt—A New Concept of Study Workflows Based on Stochastic Principles
Production Diagnostics and Water Control for the XJG Fields, South China Sea
The Integrated Approach to Formation Water Management: From Reservoir Management to Protection of the Environment
Production Enhancement for Khafji Field Using Advanced Optimization Techniques
Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea
Transforming Data Into Decisions To Optimize the Recovery of the Saih Rawl Field in Oman
A Unique Workflow for Reserves Evaluation in Lower Vicksburg Sands
Better Valuation of Future Information Under Uncertainty
Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water Turbidite Reservoirs
Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservoir Drainage
Closing the Loop Between Reservoir Modeling and Well Placement and Positioning
Using Real-Time Pressure Data for Well Placement Planning
Unlocking the Potential of Mature Fields - An Innovative Filtering and Analysis Approach to Identify Sidetracking Candidates in
Optimizing Horizontal Well Placement and Reservoir Inflow in Thin Oil Rim Improves Recovery and Extends the Life of an Agin
Adjoint-Based Well-Placement Optimization Under Production Constraints
A New Analytical Model for the SAGD Production Phase
Generalized Analytical Solution for Reservoir Problems With Multiple Wells and Boundary Conditions
Semi-analytical Solution for Multiple Layer Reservoir Problems with Multiple Vertical, Horizontal, Deviated and Fractured Wells
3D Field-Scale Automatic History Matching Using Adjoint Sensitivities and Generalized Travel-Time Inversion
Fast and Efficient Sensitivity Calculation Using Adjoint Method for 3 Phase Field-Scale History Matching
Innovative Approach to Assist History Matching Using Artificial Intelligence
Experimental Design and Response Surface Models as a Basis for Stochastic History Match—A Niger Delta Experience
History Matching Using Face-Recognition Technique Based on Principal Component Analysis
Analytical Solutions for the Radial Flow Equation With Constant-Rate and Constant-Pressure Boundary Conditions in Reservoir
A General Unstructured Grid, Parallel, Fully Implicit Thermal Simulator and Its Application for Large Scale Thermal Models
Efficient General Formulation Approach For Modeling Complex Physics
Using Production Logs to Calibrate Horizontal Wells in Reservoir Simulation
Integrating Advanced Production Logging and Near-Wellbore Modeling in a Maximum- Reservoir-Contact (MRC) Well
Using a Discritized Well Model to Simulate Production Behavior in Horizontal or Multi-Lateral Wells
Complex Well Modeling Workflow Enabling Full Field Optimization and Forward Decisions
3D Reservoir Geomechanical Modeling in Oil/Gas Field Production
A New Thermal-Compositional Reservoir Simulator with a Novel Equation Line-Up" Method"
Effective Use of Production Surveillance Tool in Forecasting Future Production
Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D Model
Numerical Investigation on Hydraulic Fracture Cleanup and Its Impact on the Productivity of a Gas Well With a Non-Newtonian
Numerical Modeling of Multiple Hydraulically Fractured Horizontal Wells (MHFHW)
New Approach to Simulating Multicomponent Fluids Flow to Hydraulic Fractured Well
Hydraulic-Fracture Modeling With Bedding Plane Interfacial Slip
Explicit Simulation of Multiple Hydraulic Fractures in Horizontal Wells
Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells
A Bayesian Production Analysis Technique for Multistage Hydraulically Fractured Wells
Design Criteria for Improved Performance of Fractured Wells
Modelling of Transverse Hydraulic Fracturing
2D Modeling of Hydraulic Fracture Initiating at a Wellbore With or Without Microannulus
The Application of Artificial Neural Networks With Small Data Sets: An Example for Analysis of Fracture Spacing in the Lisburn
Incorporation of Static and Dynamic Constraints in Optimum Upscaling: A Field Case Study
Unconventional Reservoir Modeling of a Gas Field in the Nile Delta of Egypt
Prediction of Temperature Propagation Along a Horizontal Well During Injection Period
IPI Method: A Subsurface Approach to Understand and Manage Unfavorable Mobility Waterfloods
Material Balance Analysis in Complex Mature Reservoirs - Experience in Samarang Field, Malaysia
Pressure and PVT Uncertainty in Material-Balance Calculations
History Match of an Old Waterflood: Dealing Wth Decades Worth of Data From Hundreds of Wells
Two-Phase Multicomponent Diffusion and Convection for Reservoir Initialization
The Pains and Gains of Experimental Design and Response Surface Applications in Reservoir Simulation Studies
A Systematic Approach to Incorporate Capillary Pressure-Saturation Data Into Reservoir Simulation
Multipoint Flux Approximations via Upscaling
Why Dual Porosity Models are not Applicable for Simulation of the Near-Wellbore Zone of Gas Condensate Well for Naturally F
Simulation of Gas/Oil Displacements in Vuggy and Fractured Reservoirs
History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method
Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwait Jurassic Complex
A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation
Implicit 1-D Transport Solvers For a Streamline Simulator For Fractured Reservoirs
Multiscale Mimetic Solvers for Efficient Streamline Simulation of Fractured Reservoirs
Conceptual Models for Fast Tracking Decision Making in the Reservoir Management
Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF
Proxy Modeling in Production Optimization
The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale
Real Time Integration of Reservoir Modeling and Formation Testing
Simulation Study of Steamflooding With Horizontal Producers Using PEBI Grids
Acceleration of Streamline Simulation Using Adaptive Mesh Refinement Along Streamlines
Thermodynamically Consistent Analytical Approach for Streamline Simulations of Multicomponent Hydrocarbon Reservoirs
Selection of Infill Drilling Locations Using Customized Type Curves
Assessing the Uncertainty in Reservoir Description and Performance Predictions With the Ensemble Kalman Filter
Ranking of Geostatistical Reservoir Models and Uncertainty Assessment Using Real-Time Pressure Data
Modeling Well Inflow Control With Flow in Both Annulus and Tubing
Black-Oil Delumping Techniques Based on Compositional Information from Depletion Processes
Black Oil Delumping: Running Black Oil Reservoir Simulations and Getting Compositional Wellstreams in the North Kuwait Jura
A Quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks
Fines Migration Evaluation in a Mature Field in Libya
Applicability of the Forchheimer Equation for Non-Darcy Flow in Porous Media
Understanding the Pressure Gradients Improves Production From Oil/Water Transition Carbonate Zones
Reservoir Focused Underbalanced Applications in the Margham Field
In Situ Stress Pattern and Its Impact in Drilling High- Angle Wells in Gulf of Suez, Egypt
Making Our Mature Fields Smarter—An Industrywide Position Paper From the 2005 SPE Forum
Current Status of Enhanced Recovery Techniques in the Fields of Russia
U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces
Zonal Isolation Modeling and Measurements—Past Myths and Today's Realities
Practical Steps for Successful Identification and Production of Remaining Hydrocarbons Reserves in a Mature Field - Case stu
The Use of Pulsed Neutron Measurements for Determination of Bypassed Pay: A Multi-Well Study
Using the Optimal Through-Casing Measurement to Maximize Oil Recovery: A Case Study From The Western Desert, Egypt
Permanent Real-Time Downhole Flowrate Measurements in Multilateral Wells Improve Reservoir Monitoring and Control
A Novel Solution to Flow Profiling With an Improved Production-Logging Tool In Short String Section of Dual String Completion
Pushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo Field, Sakhalin, Russia – New C
The Identification of Condensate Banking With Multiphase Flowmeters—A Case Study
Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate Environment
Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate Environment
An Innovative Multi-Reservoir Permanent Downhole Monitoring System Through A Single Well
Real-Time Downhole pH Measurement Using Optical Spectroscopy
Surveillance and Diagnostics of Permanent Bottomhole Gauge Data Coupled With Geomechanical Modeling to Identify Source
New Analytical Techniques To Help Improve Our Understanding of Hydraulically Induced Microseismicity and Fracture Propaga
“Don't Let the Temperature Log Fool You: False Indications of Height Containment From Case Studies in a Tectonically Str
Real Time Diagnostics of Gas Entries and Remedial Shut-off in Barefoot Horizontal Wells
Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing Wells Using Permanently In
Inflow Profiles Obtained With Pulsed Neutron Logs in Subcritical-Velocity Wells
Determination of Reservoir Inflow With Pulsed Neutron Logs Under Subcritical Flow Conditions
Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fiber Optic Distributed Tempera
Using Chemical Tracers for Flow Profiling a Subsea Horizontal Well with an Open Hole Gravel Pack Lower Completion: Field R
Well Surveillance With a Permanent Downhole Multiphase Flowmeter
Characterization of Fracture Dynamic Parameters to Simulate Naturally Fractured Reservoirs
Permanent Downhole Gauge: A Need or A Luxury?
From Data Monitoring to Performance Monitoring
Production Logging Low Flow Rate Wells with High Water Cut
Observations from a Fieldwide Pressure Data Acquisition Campaign in the Wara Formation of the Greater Burgan Field, Kuwai
A Successful Application of Fiber-Optic-Enabled Coiled Tubing With Distributed Temperature Sensing (DTS) Along With Press
Real Time Production Monitoring Uncovers Potential for Recovery Optimization, Field Case Study, Western Desert, Egypt
The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testing—Case Studies
Monitoring Multilayered Reservoir Pressures and Gas/Oil Ratio Changes Over Time Using Permanently Installed Distributed Te
Monitoring SAGD Steam Injection Using Microseismicity and Tiltmeters
Monitoring Production From Gravel-Packed Sand-Screen Completions on BP’s Azeri Field Wells Using Permanently Instal
Completion Design for Sandface Monitoring of Subsea Wells
Detecting Thief Zones in Carbonate Reservoirs by Integrating Borehole Images With Dynamic Measurements
Real-Time Production--A Virtual Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters
Production Performance Monitoring Workflow
A Reduced Risk Alternative for Water Entry Detection in High Water Producing Horizontal Wells
Determination of Water-Producing Zones While Underbalanced Drilling Horizontal Wells—Integration of Sigma Log and Real-
Resistivity Through Casing Measurement Successfully Applied To Improve Oil Recovery And Water Shut Off: A Case Study Fr
An Innovative Approach in Tracking Injected Water Front in Carbonate Reservoir off Shore Abu Dhabi
Imaging Injected Water flood Fronts Between Wells in a Complex Carbonate Reservoir: Designing Completions to Optimize Im
Constraining Interwell Water Flood Imaging With Geology and Petrophysics: An Example From the Middle East
First Laboratory Perforating Tests in Coal Show Lower-Than-Expected Penetration
Cleat Characterization in CBM Wells for Completion Optimization
Application of Indirect Fracturing for Efficient Stimulation of Coalbed Methane
A Field Study in Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal Wells
Effect of Layered Heterogeneity on Fracture Initiation in Tight Gas Shales
Maximizing Energy at Coalface for Coalbed Methane Fracturing Operations
Use of Horizontal Well Image Tools to Optimize Barnett Shale Reservoir Exploitation
A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation
Effects of Well Placement and Intelligent Completions on SAGD in a Full-Field Thermal-Numerical Model for Athabasca Oil San
Coalbed- and Shale-Gas Reservoirs
Barnett Shale Refracture Stimulations Using a Novel Diversion Technique
Optimizing Well Productivity by Controlling Acid Dissolution Pattern During Matrix Acidizing of Carbonate Reservoirs
Case Study: First Successful Offshore ESP Project in Saudi Arabia
Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations at Suncor Energy, Canada
Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique
Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of Horizontal Drilling in t
The Challenges and Advantages of Openhole Completions in the Manati Gas Field
Multiple-Layer Completions for Efficient Treatment of Multilayer Reservoirs
Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Productivity in a Matured Field
Production Tubing String Design for Optimum Gas Recovery
Optimized Tubing-String Design Modeling for Improved Recovery
Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait
Succeeding With Multilateral Wells in Complex Channel Sands
Using Down-Hole Control Valves to Sustain Oil Production From the First Maximum Reservoir Contact, Multilateral and Smart W
On Reservoir Fluid-Flow Control With Smart Completions
Case Study: The Use of Downhole Control Valves to Sustain Oil Production from the First Maximum Reservoir Contact, Multila
Horizontal Open Hole, Dual-Lateral Stimulation, Using a Multilateral Entry with High Jetting Tool
Experimental and Numerical Study on Production Performance: Case of Horizontal and Dual-Lateral Wells
Development of an Integrated Solution for Perforation, Production and Reservoir Evaluation
Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump System Performance
Long Term Evaluation of an Innovative Acid System for Fracture Stimulation of Carbonate Reservoirs in Saudi Arabia
Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska
Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multi-Lateral Play
Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia
Field Trials of Fiber Assisted Stimulation in Saudi Arabia: An Innovative Non-Damaging Technique for Achieving Effective Zona
Fiber-Laden Fluid: Applied Solution for Addressing Multiple Challenges of Hydraulic Fracturing in Western Siberia
Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
Effect of Formation Modulus Contrast on Hydraulic Fracture Height Containment
A Faster Cleanup, Produced Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studies
Optimizing Fracturing Fluids From Flowback Water
Maximizing Effective Fracture Half-Length to Influence Well Spacing
Novel Frac-and-Pack Technique for Selective Fracture Propagation
A Novel Approach to Fracturing Height Control Enlarges the Candidate Pool in the Ryabchyk Formation of West Siberia’s M
Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells
Stimulating High-Water-Cut Wells: Results From Field Applications
Efficient Multifractured Horizontal Completions Change the Economic Equation in Latin America Through Improved Reservoir C
Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field, Offshore Congo, West Africa
Successful Multistage Horizontal Well Fracturing in the Deep Gas Reservoirs of Saudi Arabia: Field Testing of a Promising Inno
Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Fluid System Executed From a
Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Fluid System, Executed from
Optimized Hydrualic Fracturing for the Gandhar Field
Production Performance Design Criteria for Hydraulic Fractures
Quantifying Proppant Transport for Complex Fractures in Unconventional Formations
Particularities of Hydraulic Fracturing in Dome-Type Reservoirs of Samara Area in the Volga-Urals Basin
Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the Woodford Shale
Novel Technology Replaces Perforating and Improves Efficiency During Multiple Layer Fracturing Operations
A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations
Semiphenomenological Model of Hydraulic Fracturing in Granular Media
Optimization of a Visco-Elastic Surfactant (VES) Fracturing Fluid for Application in High-Permeability Formations
Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Production From Bypassed Pay in
Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Southeast New Mexico
Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Reservoirs Using a New-Gen
Fracturing Technology for 4% Porosity Libya’s Reservoir: Application of Correct Diagnostic and Methodology to Optimize th
An Integrated Evaluation of Successful Acid Fracturing Treatment in a Deep Carbonate Reservoir Having High Asphaltene Con
New Results Improve Fracture Cleanup Characterization and Damage Mitigation
Optimizing the Completion of a Multilayer Cotton Valley Sand Using Hydraulic-Fracture Monitoring and Integrated Engineering
Comparative Analysis of Damage Mechanisms in Fractured Gas Wells
Borehole Deviation Surveys are Necessary for Hydraulic Fracture Monitoring
Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for Low-Permeability Formatio
The Texture of Acidized Fracture Surfaces: Implications for Acid Fracture Conductivity
Complex Fracture Geometry Investigations Conducted on Western-Siberian Oilfields at Rosneft Company
A New Environmentally Acceptable Technique for Determination of Fracture Height and Width
Hydraulic Fracture Geometry Investigation for Successful Optimization of Fracture Modeling and Overall Development of Juras
Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgskoe Arctic Gas/Condensate
Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variations in Hydraulically Fracture
Fracture Propagation in High-Permeability Rocks: The Key Influence of Fracture Tip Behavior
Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Production Rate
Evaluation and Optimization of Low-Conductivity Fractures
Evidence of a Horizontal Hydraulic Fracture From Stress Rotations Across a Thrust Fault
Prediction of Long-Term Proppant Flowback in Weak Rocks
Effect of Production Induced Stress Field on Refracture Propagation and Pressure Response
Hydraulic Fracturing and Filtration in Porous Medium
Differential Cased Hole Sonic Anisotropy for Evaluation of Propped Fracture Geometry in Western Siberia, Russia
New Findings in Fracture Cleanup Change Common Industry Perceptions
Eliminating the Poroelastic Problems Associated with Water Injection in the Kikeh Deep Water Development
Using Open and Cased Hole Sonic Anisotropy and Geomechanics Modeling for Hydraulic Fracturing Evaluation: A Case Study
Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Long-Recognized Process
Auto, Natural, or In-Situ Gas-Lift Systems Explained
A Critical Review of Completion Techniques for High-Rate Gas Wells Offshore Trinidad
Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
Successful Case History of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia
A Case Study of Oil-Based Mud Effect on Horizontal-Well Productivity
Slim Intelligent Completions Technology Optimize Production in Maximum Contact, Expandable Liner and Quad Laterals Comp
First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador
Integrating ESPs with Intelligent Completions: Options, Benefits and Risks
Intelligent Completions Technology Offers Solutions to Optimize Production and Improve Recovery in Quad–Lateral Wells in
Insurance Value of Intelligent Well Technology Against Reservoir Uncertainty
Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities
Managing Production in Maturing Assets: Increasing Intervention Success by Combining Production Logging With Nodal Analy
Forecasting the Productivity of Thinly Laminated Sands with a Single Well Predictive Model
Geomechanical Characterization of a Sandstone Reservoir in Middle East—Analysis of Sanding Prediction and Completion St
Effective Matrix Acidizing in Carbonate Reservoir—Does Perforating Matter?
Productivity Increase Using the Combination of Formation Isolation Valve and Dynamic Underbalanced Perforation
Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions
Dynamic Underbalanced Perforating Application Increases Productivity in the Mature High-Permeability Gas Reservoirs of San
Overbalanced Perforating Yields Negative Skins in Layered Reservoir
Oriented Perforation in Dual Completion Wells: A Real Case in East Texas
New Perforating Technique Improves Well Productivity and Operational Efficiency
Quantifying Skin Variation for Underbalanced Perforating
Improved Method for Underbalanced Perforating With Coiled Tubing in the South China Sea
Modeling Air and Water Perforator Swell for Better Risk Management
Novel Perforating Job Design Triples Well Productivity
Flow Performance of Perforation Tunnels Created With Shaped Charges Using Reactive Liner Technology
Overcoming Near Wellbore Damage Induced Flow Impairment with Improved Perforation Job Design and Execution Methods
Reduced Water Production and Increased Oil Production Using Smart Completions and MPFM Case Study""
Sand Control Completions for the Development of Albacora Leste Field
Magnolia Deepwater Experience--Frac Packing Long, Perforated Intervals in Unconsolidated Silt Reservoirs
TAML Level 3 tri-lateral with Sand Control application for Saudi Aramco
Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Development
Novel Through Tubing Sand Control Solution for Failed Gravel Pack - Alpha Well - 4L Case Study
Sand Control Completion Failures: Can We Talk the Same Language?
A Step Change in Openhole Gravelpacking Methodology: Drilling-Fluid Design and Filter-Cake Removal Method
Greater Plutonio Openhole Gravel-Pack Completions: Fluid Design and Field Applications
Complex Through-Tubing Gravel-Pack Operation Increases Production on a Well in the Heidrun Field: A Case Study
Openhole Gravel Packing With Exposed Shales: Waterpack Case Histories From Underground Gas Storage Wells in Italy
Gravel Packing Long Openhole Intervals With Viscous Fluids Utilizing High Gravel Concentrations: Toe-to-Heel Packing Witho
Integrated Approach to Modeling Gravel Packs in Horizontal Wells
Openhole Gravel Packing With Oil-Based Fluids: Implementation of the Lessons Learned From Past Experiences Leads to the
Effective Perforating and Gravel Placement: Key to Low Skin, Sand Free Production in Gravel Packs
Effective Perforating and Gravel Placement: Key to Low Skin, Sand-Free Production in Gravel Packs
Determination of Optimum Perforation Design and Sanding Propensity in Long Horizontal Wells Based on Modified RP 19B Se
ICD Screen Technology in Stag Field to Control Sand and Increase Recovery by Avoiding Wormhole Effect
Screenless Completions as a Viable Through-Tubing Sand Control Completion
The Search for Alternative to Screen: Is Permeable Cement a Viable Option?
Case Study: The Application of a Sand Management Solution for the Sarir Field in Libya
Practical Approach to Achieve Accuracy in Sanding Prediction
Sanding—Not As It First Appeared
Effect of Water Cut on Sand Production—An Experimental Study
Bokor--A New Look at Sand Production in a Mature Field
Influence of Rock Failure Characteristics on Sanding Behavior: Analysis of Reservoir Sandstones from the Norwegian Sea
An Integrated Wellbore Stability and Sand-Production Prediction Study for a Multifield Gas Development
Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation
Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids
Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas
Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage during Acid Fracturing in a
Successful Application of Innovative Fiber-Diverting Technology Achieved Effective Diversion in Acid Stimulation Treatments in
Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field
Optimization of Acid Stimulation for a Loosely Consolidated Brazilian Carbonate Formation--Multidisciplinary Laboratory Asses
A Novel Stimulation Technique for Horizontal Openhole Wells in Carbonate Reservoirs--A Case Study in Kuwait
Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Procedures Are Correct
Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water Injectors
Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan
Matrix Acidizing of Carbonate Reservoirs Using Organic Acids and Mixture of HCl and Organic Acids
An Innovative Acid Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabia - A Holistic Approach
An Alternative Solution to Sandstone Acidizing Using a Nonacid Based Fluid System With Fines-Migration Control
Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Orito Formation
Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Histories
Foam Fracturing: New Stimulation Edge in Western Siberia
The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments
Restimulation: Candidate Selection Methodologies and Treatment Optimization
Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the Frontier Formation, Big Hor
New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Production in Rockies
Optimized Stimulation Solutions for a Mature Field in Kazakhstan
Preventive Treatment for Enhancing Water Removal from Gas Reservoirs by Wettability Alteration
High-Water-Cut Wells Stimulation Combined Viscoelastic Surfactant
Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between Formations
A New Approach for Interpreting Pressure Data To Estimate Key Reservoir Parameters From Closed-Chamber Tests
Challenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin, Carbonate Reservoir of the Gr
A Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Commingled Production and R
Identifying Layer Permeabilities and Skin Using a Multi-Layer Transient Testing Approach in a Complex Reservoir Environment
Pressure Transient Analysis of Partially Penetrating Wells in a Naturally Fractured Reservoir
Radius of Investigation for Reserve Estimation From Pressure Transient Well Tests
Real-Time Evaluation of Pressure Transients: Advances in Dynamic Reservoir Monitoring
An Investigation of Recent Deconvolution Methods for Well-Test Data Analysis
Advanced Methods to Design and Interpret Exploration Well Tests---Two Case Studies
Estimating Fracture Permeability and Shape Factor by Use of Image Log Data in Welltest Analysis
Mini-DST Applications for Shell Deepwater Malaysia
A New Method for Gas Well Deliverability Potential Estimation Using MiniDST and Single Well Modeling: Theory and Examples
Extending the Range of Multiphase Metering to Challenging High Water Cut Gas-Lifted Wells: TOTAL ABK Field Application
Testing Gas Condensate Wells in Northern Siberia With Multiphase Flowmeters
Improving Reservoir Characterization Using Accurate Flow-Rate History
Reliability of Multiphase Flowmeters and Test Separators at High Water Cut
Field Validation Processes for Multiphase Wet Gas Surface Well Testing Solutions: Example From the Yamburgskoe Arctic Ga
High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering
Production Well Testing Optimization Using Multiphase Flow Meters (MPFM)
Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of Venturi and Gamma Ray Fraction Meter
Linking Well-Test Interpretations to Full Field Simulations
Application of the β-Integral Derivative Function to Production Analysis
A Digital Pressure Derivative Technique for Pressure Transient Well Testing and Reservoir Characterization
Streaming Potential Applications in Oil Fields
                                 Author                                       Abstract
Matteo Loizzo, SPE, Schlumberger Carbon Services and Sandeep Sharma, Abstract CO2 geological storage is about pumping
                                                                             SPE, CRC, and Schlumberger Carbon Services
                                                                             Abstract We present an estimation of the full Tech
T. B�rard, B. K. Sinha, SPE, Schlumberger; P. van Ruth, T. Dance, Cooperative Research Centre for Greenhouse Gas stres
                                                                             Abstract One of the major challenges Jammes, Sc
Y. Le Guen, J. Le Gouevec, R. Chammas, B. Gerard, and O. Poupard, Oxand S.A., and A. Van Der Beken and L. associated w
A. Primera, W. Sifuentes, and N. Rodr�guez; SPE, Schlumberger              Abstract The reduction of greenhouse gas emissio
S. Hurter, SPE, D. Labregere, and J. Berge, Schlumberger Carbon ServicesAbstract The need for CO2 emissions reduction a
                                                                             Abstract The storage of carbon dioxide (CO2) in sa
B. Norden and A. F�rster, GFZ German Research Centre for Geosciences, D. Vu-Hoang, Schlumberger Riboud Product Ce
M. Sengul, Schlumberger Carbon Services                                      Abstract Fossil fuel fired plants are responsible fo
                                                                              SPE, Schlumberger
T. B�rard, L. Jammes, B. Lecampion, SPE, C. Vivalda, and J. Desroches,Abstract Controlling the trapping of CO2 in the sub
                                                                             Abstract Carbon dioxide capture and storage (CC
S. Imbus, Chevron Energy Technology Co.; F.M. Orr, Stanford U.; V.A. Kuuskraa, Advanced Resources Intl. Inc.; H. Kheshgi, E
                                                                             Abstract PRODMLâ„¢ is a set of production data s
Dave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.; Alan Doniger, SPE, Energistics; Hans Eric Klumpen, SP
                                                                             Abstract The well 34/8-A-6 AHT2 was drilled from
A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hernes, SPE, Statoil, and Y. Huelvan, Schlumberger
                                                                             Abstract The Dumbarton Field operated by Maers
Ukpe John, SPE, Schlumberger; Ian Tribe, SPE, Schlumberger; Jim Manson, SPE, MaerskOil UK; Andy Stewart, SPE, Maersk
                                                                             Abstract Maersk Oil Qatar AS Erhan completed d
Kumud Sonowal and Bjarne Bennetzen, Maersk Oil Qatar AS; Patrick Wong, K&M Technology Group; and (MOQ)Isevcan, Sch
                                                                             Abstract The Guelph Formation historically Harris
Brian Toelle and Larry Pekot, Schlumberger Data & Consulting Services, and David Barnes, Mike Grammer, and William known
                                                                             Abstract E&P, and Jos� A. Rodr�guez Pime
Heron Gachuz Muro, Sergio Berumen Campos, and Luis O. Alcazar Cancino, Pemex CO2 injection is one of the most efficient
                                                                             Abstract The Oligocene Vicksburg formation
D.L. Fairhurst, B.W. Reynolds, S. Indriati, and M.D. Morris, SPE, Schlumberger, and E.G. Hanson, Abaco Operating LLC in S
S. Luo, SPE, Schlumberger, and M.A. Barrufet, SPE, Texas A&M U.              Abstract Gas-condensate reservoirs usually exhib
                                                                             Abstract The work
Jos� Antonio Pi�a R., Jos� Luis Bashbush, Edgar Alexander Fernandez, Schlumbergerpresented in this paper describe
                                                                             Abstract Neyaei, and Tarek Shaheen, Schlumberg
Hamed Al-Sharji, Ali Ehtesham, Bela Kosztin, and Clement Edwards, PDO; Fardin AliThis paper discusses the gas shut-off trea
                                                                             Abstract West Lutong is a Services Malaysia; and
Wong Chun Seng and Suhaila Wahib, Petronas Carigali; Choo Der Jiun and�Ronald Ramnarine, BJ mature field with 8 roun
                                                                             Abstract Oil production from some of wells in the S
Keng Seng Chan, Schlumberger Well Services; Duong Danh Lam and Aleksey Ivanov, VietSovPetrol; Kiam P. Apisitsareekul,W
                                                                             Abstract Most of Rasool Al-Khamees, and Abdula
Redha Kelkouli, SPE, and Maen Razouqi, SPE, Schlumberger, and Saeed Al-Shaheen, Abdulthe wells in Sabriya Field (Northe
                                                                             Abstract Due to the stacked Nigeria
Victor E. Uadiale, Schlumberger; Otaru G.Oghie, Shell E&P, U.K.; and Vincent O. Nwabueze, Shell E&P,nature of reservoirs in
                                                                             and Tashfeen Sarfraz, Schlumberger
Faisal F. Al-Shahrani, Zulfiqar A. Baluch, Nashi M. Al-Otaibi, Saudi Aramco, Abstract Water shut-off treatment (WSOT) using t
                                                                             Abstract Company; and Belkis Gonz�lez, Salah
Goran Andersson, SPE, PetroBoscan; Gregg Molesworth, SPE, Chevron Technology With the discovery of new fields becomin
                                                                             Abstract Al-Sarakbi and Khzam Al Shaharani, Sch
Alaa A. Dashash, Ibrahim Al-Arnaout, Saad M. Al-Driweesh, Saudi Aramco; Samer A. Water production is a major problem for
                                                                             Abstract Water control is the key to prolong well lif
Ahmed Al-Zain, Jorge Duarte, Surajit Haldar, Saad Driweesh, Ahmed Al-Jandal and Faleh Shammeri, Saudi Aramco; Vsevolod
D. Gonzalez and A. Jamaluddin, Schlumberger                                  Abstract Due to the large potential reserves incre
                                                                             Summary         dynamic characteristics of oil/water
M. Vielma, SPE, Schlumberger; S. Atmaca, SPE, C. Sarica, SPE, and H. Zhang, SPE, The University of Tulsa
                                                                             Summary Oil/water flow is a common occurrence
S. Atmaca, SPE, C. Sarica, SPE, H.-Q. Zhang, SPE, and A.S. Al-Sarkhi, University of Tulsa
                                                                             Abstract The
T. Graf, SPE, S.P. Graf, SPE, P. Evbomoen, SPE, and C. Umadia, SPE, Schlumberger installation of intelligent wells to imp
                                                                             Aar�n Garrido Hern�ndez/PEMEX
Fernando L. Morales/Schlumberger; Juan Cruz Vel�zquez/Schlumberger,Abstract Traditionally in the upstream business op
                                                                             Abstract Gulf of Mexico; and George J. Hirasaki a
Doris L. Gonzalez and Abul K.M. Jamaluddin, Schlumberger; Trond Solbakken, HydroIn deepwater production systems extrem
                                                                             Abstract Development of deep offshore fields is co
H. Alboudwarej, SPE, Schlumberger; Z. Huo, SPE, Shell Global Solutions (US) Inc.; and E. Kempton, SPE, Multiphase Solution
                                                                             Abstract Carbon dioxide Schlumberger Oilfield Se
N. M�ller, Schlumberger Oilfield Services; H. Elshahawi, Shell Intl. E&P; C. Dong and O.C. Mullins, (CO2) occurrence in hydr
                                                                             Abstract The inherent uncertainty M Wakif Sukah
Saifon Daungkaew, SPE, Jack Harfoushian, SPE, and Boon Cheong, SPE Schlumberger Oilfield Services, andin establishing r
                                                                              S. Bou-Mikael, SPE, Chevron Corp.; have profou
N.H.G. Rahmani, SPE, J. Gao, SPE, and M.N. Ibrahim, SPE, Schlumberger;Abstract Asphaltene precipitation canand B.S. Al-M
                                                                             McCain Jr., Texas A&M University
Adriana P. Ovalle, M-I Swaco; Chris P. Lenn, Schlumberger; and William D. Summary Certain fluid properties are required for
A.H. El-Banbi, Schlumberger, and K.A. Fattah and M.H. Sayyouh, Cairo U. Abstract Several authors have shown the applicab
                                                                             Abstract The fluids in large reservoirs can be in eq
Oliver C. Mullins and Soraya S. Betancourt, Schlumberger-Doll Research; Myrt E. Cribbs and Jefferson L. Creek,Chevron Ener
                                                                             Abstract Fluid identification is an important objectiv
Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Ayan, Schlumberger
                                                                             Abstract Fluid characterization quantifies the rese
Moyosore Okuyig and Ahmed Berrim, ADMA-OPCO, and ChengGang Xian and Sammy Haddad, Schlumberger
                                                                             Summary Reservoir characterization and asset m
Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger; and Nikos Varotsis, SPE, and Vassilis Gaganis, SPE, Technica
                                                                             and O. Mullins, SPE, Schlumberger Oilfield Servic
F.O. Alpak, SPE, H. Elshahawi, SPE, and M. Hashem, SPE, Shell Intl. E&P, Abstract Miscible oil-based mud (OBM) filtrate con
                                                                             Abstract This Colacelli, Schlumberger
Jes�s A. Ca�as, Evie Freitas, A. Ballard Andrews, Oliver C. Mullins, and Santiago E. paper describes a new Downhole Flu
                                                                             Jackson The Gharif and Al Khlata Formations form
                                                                                                      Case Studies
M. Khalil and K.K. Maamari, SPE, Petroleum Development Oman, and R.R. Abstract and K. Cig, SPE, Schlumberger
                                                                             Abstract Wireline formation testing A. Amin and S
T. Beaiji, Saudi Aramco; M. Zeybek, Schlumberger; A. Crowell, R. Akkurt, and S. Al-Dossari, Saudi Aramco; andprovides forma
                                                                             Abstract Michael O’Keefe, Schlumberger; an
Mohamed Hashem and Hani Elshahaw, Shell; Ryan Parasram, Peter Weinheber, andMany development projects will rely on p
                                                                             SPE, Michael O’Keefe, SPE, Francois X. Dub
Julian Y. Zuo, SPE, Oliver C. Mullins, SPE, Chengli Dong, SPE, Dan Zhang, Abstract Reservoir fluids frequently reveal comple
C.S. Kabir, SPE, Chevron ETC and J.J. Pop, SPE, Schlumberger                Summary Collection and analysis of gas/condensa
                                                                            Venkataramanan, compartmentalization quantify
Hani Elshahawi, SPE, Shell; Melton Hows, SPE, Chengli Dong, SPE, LalithaAbstract IdentifyingSPE, and Oliver C. Mullins, SPE
                                                                            Abstract Reservoir fluid identification plays a Moh
Ko Ko Kyi and�Norfadilah Yahaya, PETRONAS Carigali; Saifon Daungkaew, Noor Rohaellizza Hademi, Boon Cheong, cruci
                                                                            Summary This O'Keefe, Toru a case study of a N
Go Fujisawa, SPE, Soraya S. Betancourt, SPE, Oliver C. Mullins, Torleif Torgersen, Michael paper presents Terabayashi, and C
R.R. Jackson, A. Carnegie, and F.X. Dubost, SPE, Schlumberger               Abstract Pressure-depth plots have been used for
                                                                            Abstract Reservoir fluids often Eriksen, Statoil AS
F.X. Dubost, A.J. Carnegie, O.C. Mullins, M.O. Keefe, S. Betancourt, and J.Y. Zuo, Schlumberger; and K.O.show complex com
                                                                            Summary Formation fluid sampling early in the
Chengli Dong, SPE, Peter S. Hegeman, SPE, and Andrew Carnegie, SPE, Schlumberger, and Hani Elshahawi, SPE, Shell life
                                                                            Abstract This
T. Yi, A. Fadili, M. Ibrahim, SPE, Schlumberger; B.S. Al-Matar, SPE, Kuwait Oil Company paper describes the study of the effe
                                                                            Oliver C. Mullins, SPE, analysis (DFA) together w
Julian Y. Zuo, SPE, Dan Zhang, Francois Dubost, SPE, Chengli Dong, SPE,Abstract Downhole fluid Michael O’Keefe, SPE
                                                                            Abstract Steep gradients are common in gas cond
Jes�s Ca�as, SPE, Julian Pop, SPE, Francois Dubost, SPE, Schlumberger; Hani Elshahawi, SPE, Shell International E&P
                                                                            McKinney, Matthew Flannery, and Mohammed Ha
Lalitha Venkataramanan, SPE, Schlumberger; Hani Elshahawi, SPE, Daniel Summary In recent years formation-sampling and
                                                                            Abstract Reservoir characterization and Technica
Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger, and Nikos Varotsis, SPE, and Vassilis Gaganis, SPE,asset man
R.J. Butsch, SPE, C.W. Morris, SPE, and K.T. Pinto, SPE, Schlumberger Abstract Formation testers are commonly used to
Terry W. Stone, Schlumberger, and James S. Nolen, Consultant                Abstract This paper describes in detail computatio
                                                                            Summary Water Loek Vreenegoor, Shell Global S
Hussein Alboudwarej, Moin Muhammad, and Ardi Shahraki, Schlumberger; Sheila Dubey and is invariably produced with crude
                                                                            and H.B. Chetri, Kuwait Oil Co.
I.A. Khan, K. McAndrews, J.P. Jose, and A.K.M. Jamaluddin, Schlumberger,Abstract Representative reservoir fluid sampling &
                                                                            Abstract The new generation of wireline formation
Mosleh Khalil, Huda Rumhi, SPE, Petroleum Development Oman, Mahaly Randrianavony, Koksal Cig, Oliver C. Mullins, Sophi
                                                                            Abstract Weinheber, SPE, Richard Jackson, SPE
Michael O'Keefe, SPE, Sophie Godefroy, Ricardo Vasques, Anne Agenes, SPE, PeterA downhole density-viscosity (D-V) senso
                                                                            Abstract A Schlumberger
Ahmed Dawoud, ADCO, John Zaggas, SPE, Schlumberger, and Sammy Haddad, SPE,heterogeneous carbonate reservoir can
                                                                            Summary A new generation of sampling Stenslan
Michael O’Keefe, SPE, Schlumberger; K�re Otto Eriksen, SPE, and Stephen Williams, SPE, StatoilHydro; Dag technolog
A. Paul, SPE, Schlumberger                                                  Abstract Wireline pressure testers and reservoir fl
                                                                            Abstract Representative reservoir fluid
F. Hollaender, SPE, J.J. Zhang, B. Pinguet, SPE, V. Bastos, SPE, E. Delvaux, SPE; Schlumberger Testing Servicessampling a
                                                                            Abstract Multiphase well SPE, has been acknow
Vitaliy Afanasyev, Bertrand Theuveny, SPE, Sylvain Jayawardane, Alexander Zhandin, Vlamir Bastos,testingPaul�Guieze, S
                                                                            Abstract and stimulation of deep wells is a difficult
L. Li, SPE, and H.A. Nasr-El-Din, SPE, Texas A&M University, and F.F. Chang, SPE, Acid T. Lindvig, SPE, Schlumberger
Martin Urraca, SPE, Schlumberger, and Ferenc Udvari, MOL                    Abstract The geologically complex Algyo field disc
Michael J. Fuller, Schlumberger                                             Abstract Generally matrix acidizing fluids for sand
                                                                            Abstract This paper investigates the application of
Hua Guan, SPE, M-I SWACO Production Technologies; Richard Keatch, OMS Limited; Charles Benson, SPE, and Neil Graing
                                                                            Abstract Injectivity formation damage with waterflo
Bedrikovetsky, P. and Muhammad A. W., U of Adelaide; Chang G., Schlumberger; de Souza A.L.S. and Furtado C., Petrobras
S. Sarac, SPE, F. Civan, SPE, The University of Oklahoma                    Summary Naphthenate-soap deposition and the re
                                                                            Abstract Shaped charge perforating subjects the fo
Juliane Heiland, Brenden Grove, Jeremy Harvey, Ian Walton and Andrew Martin, Schlumberger
                                                                            Abstract In Reservoir Completions
P. Bolchover, Schlumberger Cambridge Research, and I.C. Walton, SPE, Schlumbergercased completions perforations provi
                                                                            Abstract Albert Gaifullin, SPE, Ildar Faizullin, SPE,
K. Cheremisov, SPE, D. Oussoltsev, SPE, and K.K. Butula, SPE, Schlumberger, and Problems related to inorganic scale precip
                                                                            Abstract The precipitation and accumulation of sca
Leonardo Maschio, Bilu Cherian, Bernhard Lungwitz, Michael Tyndall, and Marieliz Garcia, Schlumberger, and John Longwell,
V. Kavle, S. Elmsallati, E. Mackay, and D. Davies, Heriot-Watt U.           Abstract The main challenge facing the oil industr
                                                                            Abstract Scale
Jamal Al-Ashhab and Hassouneh Al-Matar, ZADCO, and Shahril Mokhtar, Schlumberger deposition in completion strings is b
                                                                            Abstract While barium stripping is and M. Jordan
E. Mackay, K. Sorbie, and V. Kavle, Heriot-Watt U.; E. S�rhaug and K. Melvin, Talisma; and K. Sjurs�ther commonly obs
                                                                            Abstract In a large field history matching and Ed
S. Yadav, Marathon Oil Company; R. Heim, Schlumberger; S. Bryant, UT Austin; Rohit Sinha, Marathon Oil Company;is genera
                                                                            Abstract With the advancement in streamline simu
Abdullah A. Al-Najem, Jamil S. Al-Thuwaini, and Abdulatif Al-Omair, Saudi Aramco; and Syed Z. Jilani, Schlumberger
                                                                            A. Jr., SPE, BP; and Al-Matar, the incorporation o
Ibrahim, Muhammad N., SPE, Schlumberger Oilfield Services; Clark, RobertAbstract This paper discusses Bader S., SPE, Kuw
                                                                            Abstract Located F. Marcos of Mexico Cantarell F
T.S. Daltaban, Schlumberger Consultant, and A. Miguel Lozada, P. Antonio Villavicencio, and in the Gulf Torres, Pemex Explor
                                                                            Abstract This paper presents
M. Mota, SPE, O.M. Campos, SPE, H. Escalona, and L.D. Teran, Schlumberger, and G. Sandoval, Pemexthe results of an aut
                                                                            Abstract Peripheral water flooding has been the pr
Zahid Bhatti, SPE, Yousof Al Mansoori, PSE, Saber El Sembawy, Volker Vahrenkamp (ADCO), Nicolas Clerc, Michael Wilt, SP
                                                                            Abstract This paper outlines the successful integra
Clark, Robert A. Jr., SPE, BP; Lantz, James, AAPG, BP; Karami, Hossein, SPE, Schlumberger; Al-Ajmi, Moudi, SPE, Kuwait O
                                                                            Summary The traditional means of artificial lift
M.A. Ramos and J.C. Brown, Petr�leos de Venezuela S.A.; M. Rojas, O. Kuyucu, and J.G. Flores, SPE, Schlumberger pro
                                                                            Abstract The
Ra�l Rodr�guez, Jos� Luis Bashbush and Adafel Rinc�n, SPE, Schlumberger Orinoco Belt (Faja) in Venezuela con
                                                                            Abstract Akin, METU
Berna Hascakir, METU; Cagdas Acar, Schlumberger; Birol Demiral, UTP; and Serhat Conventional EOR methods like steam-in
Edgar A. Fernandez R. and Jos� Luis Bashbush, Schlumberger                Abstract The Orinoco Heavy Oil Belt (Faja) has be
                                                                            Abstract and Sivaraman Naganathan of Heavy oil
Raj Deo Tewari and Mirghani Malik, GNPOC; Mohamed Ahmed Hassan Idris, OEPA;Exploration and development and Dmitry P
                                                                            Abstract The Paleocene/Eocene age Meddaugh,
Afzal Iqbal, John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al-Yami, Saudi Arabian Chevron; W. Scott1st Eocene R
                                                                            Abstract
Achourov V., SPE, Schlumberger, and Khamitov I. and Yatsenko V., SPE, Rosneft Wireline formation testers provide the me
                                                                            Abstract Fula is a heavy oil field
Pan You li, Luo Hui Hong, and Abdel Mageed Sharara, CNPCIS, and Sivaraman Naganathan, Schlumberger located in Muglad
Shanqiang Luo, SPE, and Andy Baker, SPE, Schlumberger                                   Oil Development
                                                                            Abstract The world still contains tremendous heav
                                                                             and Mohamed Jemmali, SPE, in the Gulf of
Mohamed Ahmed Samir and Islam Elnashar, Scimitar, and Mathew Samuel Abstract The Nukhul formation SchlumbergerSuez
                                                                            Abstract Murat Gok, Murat With Sand Screen: Aa
                                                                                        Oil Environment Zeybek, Koksal Cig,
Ricardo U. Oosthuizen, Ahmed Al Naqi, and Khalaf Al-Anzi, Kuwait Oil Co., and Ihsan Because flow regimes in highly deviated C
                                                                              Energy, Mexico; S. recent hydrocarbon discoverie
E.R. Rangel-German, SPE, Natl. Autonomous U. of Mexico and Secretary of� Abstract Many Camacho-Romero, SPE, and
Ana Marin, PDVSA, Onerazan Bornia, and Bruno Pinguet, Schlumberger          Abstract The objective is to present accurately the
                                                                             Vincent ARENDO, Mark SHAFFER, Jose Steam-
Bruno PINGUET, Philippe PECHARD, Elsie GUERRA - SCHLUMBERGER, Abstract: Metering of bitumen produced byCONTR
                                                                            Abstract Sandstone acidizing is very challenging b
H.A. Nasr-El-Din, M. Al-Anazi, and A. Al-Zahrani, Saudi Aramco, and Mathew Samuel and S.K. Kelkar, Schlumberger
                                                                            Abstract Formation Wintershal; and Konstantin R
Vladislav Achourov, SPE, Schlumberger; German I. Kaledin, SPE, Achimgaz; Erwin Kroell, SPE, and fluids evaluation of hetero
Suresh Kumar, Gujarat State Petroleum Co., and Sami Affes, IPM Schlumberger Abstract Much work has already been undertaken
                                                                            Abstract Fluid properties descriptions are required
P.D. Ting, SPE, and B. Dindoruk, SPE, Shell International E&P Inc., and J. Ratulowski, SPE, Schlumberger
                                                                            Abstract The extent
Mike Parris, Andrey Mirakyan, Carlos Abad, Yiyan Chen, and Fred Mueller, SPE, Schlumberger of crosslinking a polymeric fra
C. Abad, A. Mirakyan, M. Parris, Y. Chen, and F. Mueller, Schlumberger      Abstract The extent of crosslinking a polymeric fra
                                                                            Abstract Acid fracturing is
H.A. Nasr-El-Din and A. Al-Zahrani, Saudi Aramco, and J. Still, T. Lesko, and S. Kelkar, Schlumberger the commonly applied s
                                                                            Abstract In Pressure/High Pemex Environment i
                                                                                        and Ulises Solis,
                                                                                                    Temperature
Nestor Molero, Sergio Garcia, and Eduardo Zavala, Schlumberger, and Javier Cordova the Bay of Campeche Mexico Marine o
                                                                            Abstract This H. Al-Malki, Saudi innovative and r
Muhammad Shafiq, SPE, Schlumberger; Omar Al-Faraj, Adnan A. Al-Kanaan, and Bandar paper describes anAramco
                                                                            Abstract This paper presents the results of proppe
S. Jain, A. Prestridge, P. Dellorusso, and N.C. Nghi, Schlumberger, and D.D. Lam and V.Q. Hung, Vietsovpetro
                                                                            Abstract The wells in an oil field Boucher, SPE, S
S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and Z. Xiao, SPE, F. Tuedor, SPE, A.in East Venezuel
                                                                            Summary Fluids B. Malone, SPE, Schlumberger
S. Ali, SPE, E. Ermel, SPE, and J. Clarke, SPE, Chevron; M.J. Fuller, SPE, Z. Xiao, SPE, and based on chelating agents have
                                                                            Abstract The San Jorge Basin is characterized by m
Cristian Fontana and Enrique Muruaga, Tecpetrol S.A., and Daniel Perez, Gustavo Cavazzoli, SPE, and Angeles Krenz, Schlum
                                                                            Abstract This paper presents the development of
M.K.R. Panga and Y.S. Ooi, Schlumberger Well Services; P.L. Koh, U. Teknologi Petronas; K.S. Chan and�P. Enkababian,
                                                                            Abstract This paper describes a H.A. Rehman, fo
S.G. Mathews and B. Raghuraman, Schlumberger; D.W. Rosiere and W. Wei, Chevron; and S. Colacelli and new technique Sc
                                                                            Abstract The aggregation and deposition of asphal
Alexander D. Wilson, SPE, Edo S. Boek, SPE, Hemant K. Ladva, SPE, and John Crawshaw, Schlumberger Cambridge Resea
                                                                            Abstract This paper describes an efficient multista
M.L. Samuelson, SPE, T. Akinwande, SPE, and R. Connell, SPE, Schlumberger; R. Grossman, SPE, Panther Energy; and B. S
                                                                            Abstract This paperHalliburton Energy Services; C
                                                                                         Torres, presents a brief
Valdo Ferreira Rodrigues and Luis Fernando Neumann, Petroleo Brasileiro S.A.; Daniel Permeability Carbonates review of the a
                                                                            Abstract As
Ahmed Aly, American University in Cairo-Schlumberger and Lee Ramsey, Schlumbergergas demand rises and operators turn t
Erik Borchardt, Schlumberger; Jessica Cavens and Craig Wieland, EnCana Introduction Unconventional tight gas reservoirs ar
                                                                            Oil and Gas, Brian Pluemer, Don Graham, Abdunn
                                                                            Abstract Hydraulic fracture azimuthal orientation de
S. Kuzmina, SPE, Rosneft, K.K. Butula, SPE, Schlumberger and A. Nikitin, SPE, Rosneft
Wenyue Xu, Jo�l Le Calvez, Marc Thiercelin, Schlumberger                  Abstract Large amount of gas are being produced
                                                                            Abstract J. Brown, SPE, Schlumberger
Abu M. Sani, Sergey V. Nadezhdin, Ruben Villarreal, Thierry Chabernaud, and Ernest Hydraulic fracture treatments are necess
                                                                            � Abstract Most of the low-permeability tight
M. Bulova, SPE, K. Nosova, SPE, D. Willberg, SPE, and J. Lassek, SPE, SchlumbergerPermeability Tight Gas Formations ga
                                                                            Abstract The Edwards Limestone in Malaver, Bay
Christian P. Veillette and Jerome J. Cuzella, Enduring Resources, and Fred A. Mueller, Michael P. Loayza, RafaelSouth Texas
                                                                            Abstract SPE, the past Antonio Ciuca, SPE, EN
Alberto Casero, SPE, ENI US; Loris Tealdi, SPE, ENI Congo; Roberto Luis Ceccarelli,DuringENI E&P;decade multiple transver
                                                                            Abstract Guang'an Li, field Ye He, SPE, Jinli Yan
Khay Kok Lee, SPE, Schlumberger, and�Chunchun Xu, SPE, Gang Chen, SPE, ChangzhonggasSPE, in Sichuan Province
                                                                            Abstract The Ratawi Oolite carbonate reservoir in t
Thanh Tran, CACT, China; David Barge, Saudi Arabian Texaco; and Stan Ingham, Anadrill Schlumberger
F.O. Iwere, SPE, H. Gao, SPE, and B. Luneau, Schlumberger                   Abstract This paper presents a closed-loop reserv
                                                                            Abstract In this paper we will and J. Longwell, SP
B. Cherian, SPE, A. Aly, SPE, S. Denoo, SPE, L. Maschio, SPE, and D. Sobernheim, SPE, Schlumberger, present an integrate
F.O. Iwere and J.E. Moreno, Schlumberger, and O.G. Apaydin, EOG Resources   Summary This paper presents several workflows
                                                                            Abstract Highly laminated tight gas sand sequence
D.L. Fairhurst, SPE, Schlumberger; M.E. Semmelbeck, SPE, Escondido Resources; B.W. Reynolds, SPE, S. Indriati, SPE, and
                                                                            Summary The lower Tertiary WilcoxFine
                                                                                        Predicting Production in Low
                                                                                                    Permeability, Yegua and
John C. Rasmus, SPE, John P. Horkowitz, SPE, Thierry Chabernaud, SPE, and Peter Graham, Schlumberger, and Malcolm SV
                                                                            Abstract and�Mohammed AL-Khabbaz, carbo
Bingjian Li, Schlumberger; Mishari Al-Awadi, Kuwait Oil Company;�Christian Perrin Evaluating natural fractures in tightSchlum
                                                                            Abstract Wireline formation testing in Lawi, Schlu
Moyosore Okuyiga, Ahmed Berrim, Ragab Shehab, ADMA-OPCO; Sammy Haddad, ChengGang Xian, Majed Abulow permeab
                                                                            Abstract A majority of the world’s oil and gas
Noureddine Bounoua, Sonatrach DP, and George Dozier, Philippe Montaggioni, and Arnaud Etchecopar, Schlumberger NorthrA
                                                                            Abstract McKay, BP America
R. A. Schrooten, BP America; E.C. Boratko, H. Singh, D.L. Hallford, Schlumberger; J.Improving recovery in tight gas reservoirs
                                                                            Abstract Improving recovery America
R.A. Schrooten, BP America; E.C. Boratko, H. Singh, and D.L. Hallford, Schlumberger; and J. McKay, BPin tight gas reservoirs
                                                                            Abstract Francisco Van-Dunem, Sonangol P&P; R
Peter Weinheber and Edward Boratko, Schlumberger; Kilamba Diogo Contreiras and The data provided by wireline formation te
                                                                            Summary IRDC; Vladimir Igoshkin, Geoseis; Inna
Hector Ruiz, SPE and Phil Poettmann, SPE, Schlumberger; Tatiana Kryuchkova, SPE, This paper presents a field-developmen
Jason Baihly, Dee Grant, Li Fan, and Suhas Bodwadkar, Schlumberger          Summary In general successful applications of ho
E. Sokolov, JSC Russneft, and G. Makarytchev and E. Troitskaya, SchlumbergerAbstract Yurubcheno-Takhomskaya oil and gas ac
                                                                             Oman, and B. Herold, SPE, and K. Cig, SPE, incr
H.J. de Koningh, SPE, and S.H. Al-Mahrooqi, SPE, Petroleum Development Abstract In a time of declining production and Sch
M.Tchambaz, SPE, Schlumberger                                               Abstract High potential of tight sands (quartzitic sa
                                                                            Abstract In tight Ahmed El reservoirs several facto
Chenggang Xian, Schlumberger; Ahmed Dawoud, ADCO; Andrew Carnegie, Schlumberger; carbonate Mahdi, Salma Al Hajeri,
                                                                             SPE, Schlumberger, and Pascal Cheneviere, SPE
Hassan Chaabouni, SPE, Philippe Enkababian, SPE, and Keng Seng Chan, Abstract Water production from gas producing we
                                                                            Abstract Maximization of recovery from anisotropi
R.D. Tewari, SPE, and M. Malik, SPE, GNPOC, and S. Naganathan, SPE, Schlumberger
                                                                            Abstract This paper presents a case history of
C.H. Sia, SPE, Azhar M. Ali, SPE, and N. Ezalina Hamzah, SPE, PETRONAS Carigali; and S. Jumaat, SPE, Schlumbergera sl
Lev Virine SPE, and Derek Murphy SPE, Schlumberger Ltd.                     Abstract Decision-making within the petroleum ind
Lev Virine, SPE, Schlumberger                                               Abstract Decision-making related to oil and gas ex
                                                                            Abstract The objective of supplying Halliburton
Saud Jumah, Khaled Saleh, and Haitham I. Al-Mayyan, Kuwait Oil Co., and Mike Turner, Sperry Drilling Servicesreal time LWD
                                                                            Abstract Capillary pressure curves
J. Ouzzane, M. Okuyiga, N. Gomaa, Adma Opco; R. Ramamoorthy, D. Rose, A. Boyd, D.F. Allen, Schlumbergerare a fundame
                                                                            Abstract Cores open hole logs Aramco; testers
Lang Zhan, SPE, and Fikri Kuchuk, SPE, Schlumberger; S. Mark Ma, SPE, and Ali M. Al-Shahri, SPE, Saudiformation T.S. Ram
                                                                            Abstract Electrofacies based on conventional
Christian Perrin/Schlumberger, Mohamad Rafiq Wani/KGOC, Mahmood Akbar/Schlumberger, Samir Jain/Schlumberger logs
                                                                            Abstract Establishing the depositional sedimentary
Chandramani Shrivastva and Sanchita Ganguly, Schlumberger, and Zuber Khan, GSPC
                                                                            Abstract The Triassic reservoirs of the eastern Sah
Taofeek Ogunyemi, Philippe Montaggioni, SPE, and Ibtissam Boubakeur, Schlumberger North Africa, and Mario�Junguito a
                                                                            Summary Downhole fluid S. Williams, SPE, Stato
C. Dong, SPE, and M. O'Keefe, SPE, Schlumberger; H. Elshahawi, SPE, and M. Hashem, SPE, Shell; analysis (DFA) has eme
                                                                            Abstract Fluid identification is an important objecti
Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Ayan, Schlumberger
                                                                            Abstract ONGC Ltd.
Aditi Pal, Kapil Seth, and Udit Guru, Schlumberger, and R.R. Tiwari and D. Dasgupta, The petrophysical evaluation of carbonat
                                                                            Abstract The Mumbai, India, and Indrajit Barua of
Varun Sharma, Sagnik Dasgupta, Arathi. L. Mahesh, and Sachin Sharma, Schlumberger, Lower Tipam sandstone reservoir and
                                                                            Summary A new logging-while-drilling (LWD) tool
Thomas J. Neville, SPE, Schlumberger; Geoff Weller, SPE, and Ollivier Faivre, SPE, Schlumberger Riboud Product Center; an
                                                                            Abstract F. Allioli, SPE, and M. Evans, SPE, Sch
E. Mirto, SPE, G. Weller, SPE, T. el-Halawani, SPE, J. Grau, SPE, M. Berheide, SPE,Radioactive chemical logging sources ha
                                                                            Abstract J.C. concerns have been expressed re
A. Mendoza, SPE, U. of Texas at Austin; D.V. Ellis, Schlumberger Doll-Research; andManyRasmus, SPE, Schlumberger Suga
                                                                            Abstract Quantifying the uncertainty in the volume
Samiha S. El-Sayed, SPE, and Ahmed M. Daoud, Schlumberger, and El-Sayed A. El-Tayeb, Cairo University
Samiha S. El-Sayed, SPE, Cairo University                                   Abstract � Quantifying the uncertainty in the vo
                                                                            Abstract One Boyd, Raghu Ramamoorthy, Steve N
Asbjorn Gyllensten, Mohamed Ibrahim Al-Hammadi, Emhemed Abousrafa, ADCO; Austin of the top concerns for carbonate res
Zohreh Movahed, Shahid Beheshti University                                  Abstract The reservoir is composed of a mixture o
                                                                             and D. This D. Rose, R. Ramamoorthy, and me
N. Gomaa, A. Al-Alyak, D. Ouzzane, O. Saif, and M. Okuyiga, ADMA OPCO,AbstractAllen, case study demonstrates a new E.ï¿
                                                                            Abstract and Olumide Akinsanmi and are Pillai,
Michel Claverie, Steve Hansen, Saifon Daungkaew, and Zane Prickett, Schlumberger,Deepwater turbidite reservoirsPaul compo
                                                                            Abstract Specifying the perforation intervals SPE
A.M. Daoud, SPE, M. Eisa, SPE, R. El-Mahdy, SPE, and M. Emam, Schlumberger, and A.H. Hashem and A.S. Elhawary,and e
                                                                            Abstract ABed Alderman, and S. Bahuguna, Schl
                                                                                         novel methodology has been
R. Bastia, A. Tyagi, and K. Saxena, Reliance Industries Ltd. and T. Klimentos, R. Altman, S. Petrophysical Analysis develope
                                                                            Abstract Formation evaluation in thin Chevron
Chanh Cao Minh and Isabel Joao, Schlumberger, and Jean-Baptiste Clavaud and Padmanabhan Sundararaman, sand-shale la
                                                                            ABSTRACT Formation evaluation (FE) of horizont
S.M. Ma and A.A. Al-Hajari, Saudi Aramco, and P. Butt and S. Crary, Schlumberger
                                                                            Abstract The economical viability of the Cambrian
Taofeek Ogunyemi, Philippe Montaggioni, SPE, Atmane Azzougen, SPE, and Mourad Kourta, Schlumberger North Africa, and
                                                                            Abstract Wireline formation testing (WFT) and fluid
Richard R Jackson, Ilaria De Santo, Peter Weinheber, SPE, Schlumberger, Emilio Guadagnini, SPE, Nigerian Agip Exploration
                                                                            Abstract Renewed interest Zakum Development in
Jiang YiMing, Sandeep Chakravorty, and�J. Robert Marsden, Schlumberger, and H. Ewart Edwards, in fractures and faults C
                                                                            Abstract Stratigraphic trapping mechanism
Kalyan Chakraborty and Mubarak Al-Hajeri, Kuwait Gulf Oil Co., and Jayanta Ray, Schlumberger Information Solutions plays a
                                                                            Abstract A Geological Model was Gregorio Rodrig
Layla Saleh Al Muhairi, Maria Teresa Ribeiro, Agung Dharmawan, and Mohamed Al Neaimi, ADCO, and Jose built and an Unce
                                                                            Abstract As a branch of spatial statistics geostatis
Y. Z. Ma, SPE, Schlumberger; A. Seto, SPE, Pengrowth Corp.; and E. Gomez, Schlumberger
                                                                            Abstract Thinly bedded reservoirs are increasingly
M. Claverie, Schlumberger; S. Aboel-Abbas, C.S. Mutiara; and H. Harfoushian, S. Hansen, and R. Leech, Schlumberger
C.C. Minh, Schlumberger, and P. Sundararaman, Chevron                       Abstract We use nuclear magnetic resonance (NM
                                                                            Abstract As the Petrobel
Aristides Orlandi Neto, SPE, and Dhruba Dutta, SPE, Schlumberger, and Saad Hassan, SPE,global power scenario changes w
                                                                            Summary SPE, StatoilHydro; and improvements
G.A. Bordakov, A.V. Kostin, J. Rasmus, D. Heliot, SPE, Schlumberger;and H. Laastad, The paper illustrates theE.J. Stockhause
                                                                            Abstract The Greater Kuwait Field consists of thre
Khalid H. Al-Azmi, SPE, Hamdah Al-Enezi, SPE, Rohitkumar Kotecha, and Salem Al-Sabea, SPE, Burgan Oil Company; Ekpo A
                                                                            Abstract The Texas at Austin
Vasudev Singh, SPE, Nicolas P. Roussel, SPE, and Mukul M. Sharma, SPE, University ofproduction and injection of fluids in a
                                                                            Abstract Rock mechanical parameters of reservoi
A. Abdulraheem, KFUPM, M. Ahmed and A. Vantala, Schlumberger, and T. Parvez, KFUPM
                                                                            Summary Highly depleted reservoirs exhibit sharp
Bikash Sinha, SPE, Tom Bratton, SPE, Jesse Cryer, Steve Nieting, Schlumberger OFS, Gustavo Ugueto, Andrey Bakulin, SPE
B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inve
                                                                            Schlumberger
B.D. Poe Jr., SPE, W.K. Atwood, SPE, J. Kohring, SPE, and K. Brook, SPE, Abstract This paper presents the results of an inve
B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inve
                                                                            Summary The Akhtar Sargelu and Akbar, Schl
Pradyumna Dutta, Sunil Kumar Singh, and Jarrah Al-Genai, Kuwait Oil Company; and AzharNajmah and MahmoodMarrat reser
                                                                            Abstract The carbonate reservoirs in Aziza Suez
Essam A.E.A. Bassim and Kaoru Yamaguchi, Arabian Oil Company, Ltd., and Dedi Juandi, Mahmoud Emam, andGulf ofAli, Sc
                                                                            Abstract The field is located in the southeastern pa
O. Pinous, Schlumberger; Abdel M. Zellou, Gary Robinson, and Ted Royer, Prism Seismic; and N. Svikhnushin, D. Borisenok,
                                                                             Xavier Poirier-Coutansais, and Jurassic Arab rese
Sandeep Chakravorty, Schlumberger Middle East S.A.; Jean-Louis Lesueur,Abstract The oil-bearing Upper Jean-Yves Gory, T
                                                                            Abstract The Maloichskoe field is located in the so
O. Pinous, Schlumberger; E.P.Sokolov and S.Y.Bahir, Russneft; Abdel M. Zellou, Gary Robinson, and Ted Royer, Prism Seism
                                                                            Abstract In this paper we Saudi Aramco; method
Fikri Kuchuk, SPE, and Lang Zhan, SPE, Schlumberger; S. Mark Ma, SPE, and Ali M. Al-Shahri, SPE, present a novel and T.S.
                                                                            Abstract
Hussain A. Al-Jeshi, Charles Bradford, Saudi Aramco; Murat Zeybek, Schlumberger The process of defining the fluid and rese
                                                                            Abstract Total Indonesie
Cosan Ayan and Mario Petricola, Schlumberger, and Philip Knight and Bruno Lalanne,Wireline Formation Tester (WFT) pretest
                                                                             (Thailand) Ltd.
Long Jiang and Keith Schilling, Schlumberger; Jim Logan, Chevron OffshoreAbstract Acoustic measurements have long been u
                                                                               Abstract We have Mengual, Schlumberger
Omar Aguirre and Juan Carlos Glorioso, Repsol YPF, Jeannette Morales and Jean Fran�oisvalidated with superior results th
                                                                               Abstract One of the most important objectives and
Chanh Cao Minh, Peter Weinheber, Wich Wichers, and Adriaan Gisolf, Schlumberger; Emmanuel Caroli, Francois Jaffuel, of fl
                                                                               Abstract Hess
M. Claverie, D. Maggs, and M. Van Steene, Schlumberger, and D. Westacott, CarigaliThe analysis of shaly sand gas reservoirs
                                                                               Abstract An R. Akkurt, SPE, Saudi Aramco
H.N. Bachman, SPE, S. Crary, SPE, R. Heidler, and J. LaVigne, SPE, Schlumberger, andongoing challenge for nuclear magne
Robert Freedman, Schlumberger Oilfield Services                                Distinguished Author Series articles are general d
                                                                               Abstract Up to now
Franco Vittore and Javier Pompei, Repsol YPF, and Oscar Ortiz and Anthony Pol, Schlumberger different petrophysical method
                                                                               SPE, and Shauket many of the producers are
Ahmed S. Al-Muthana, SPE, and S.M. Ma, SPE, Saudi Aramco; M. Zeybek, Abstract Currently Malik, SPE, Schlumberger hor
S. Al Arfi, ADCO, and D. Heliot, J. Li, X. Zhan, and D. Allen, Schlumberger Abstract A new methodology for porosity and perm
                                                                               Summary Underbalanced Mining and Technology
Torsten Friedel, George Mtchedlishvili, Hans-Dieter Voigt, and Frieder H�fner, Freiberg University of drilling (UBD) is defined
                                                                               Abstract The Minagish structure in southwest corn
Taher El Gezeery, SPE, Kuwait Oil Company, Fawaz Al Saqran, Kuwait Oil Company, Ekpo Ita Archibong, SPE, Schlumberger
                                                                               Summary Identifying compartmentalization Mullin
Hani Elshahawi, Shell; Lalitha Venkataramanan, Schlumberger; Daniel McKinney and Matthew Flannery, Shell; Oliver C.and un
                                                                               Abstract Understanding reservoir architecture is c
Chengli Dong, SPE, Schlumberger; Hani Elshahawi, SPE, Shell; Oliver C. Mullins, SPE, and Lalitha Venkataramanan, SPE, Sc
                                                                               Abstract Compartmentalization is perhaps the sing
Soraya S. Betancourt, Francois X. Dubost, and Oliver C. Mullins, Schlumberger Oilfield Services; Myrt E. Cribbs and�Jeffers
B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, Schlumberger              Abstract This paper presents the results of an inve
                                                                               Abstract Residual oil estimations are mainly based
Mike Burke, SPE, and M. Bremeier, SPE, Wintershall Libya; Mohamed Shebani, Libyan National Oil Corp.; ChengGang�Xia
Nicolas Orban, Cosan Ayan, and Mario Ardila, Schlumberger                      Abstract Many sedimentary features of gas fields
                                                                               and G.R. Kear, A. Lithofacies Ardila, D. being routi
                                                                                           Based Kumar, M. Mapping
H. Elshahawi, Shell Intl. E&P Inc.; E. Donaghy and C. Guillory, Shell Oil Co.; Abstract Wireline formation testers are Williamson
                                                                               Abstract Diyashev I., SPE
Ayan C. and Achourov V., SPE, Schlumberger, Alpatov A., SPE, Sibneft-Khantos and Waterflood management requires the op
                                                                               Abstract Interpretation of
R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J. Spath, SPE, Schlumberger Oilfield Services pressure transient tests
                                                                               Abstract A revised Field Development Cuauro, Sc
E. Kasap, Schlumberger; G.J. Sanza, and M.I. Ali, Petronas Carigali; T. Friedel, A. Waheed, A.Y. Sukmana, and A.Plan (FDP)
J.M. Muruais, SPE, Schlumberger, and A.A. Young, SPE, Anzon Australia Ltd.     Abstract One of the challenges that operating com
                                                                               Abstract As production Sdn Bhd, and Patrick von
Mahmoud A. Wahba, Maharon Jadid, Ibrahim B. Subari, and M. Nazli B. Abu Talib, Petronas Carigalideclines and watercut incr
                                                                               Abstract Breathing A. Presser, a mature Energia
W. Gaviria, SPE, and J.G. Flores, SPE, Schlumberger, and J. Lorenzon, SPE, J.L. Alvarez, and new life intoPetrobras oil field is
                                                                               and G. Bakar, SPE, Petronas Carigali; and J. Liew
G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance
                                                                               Abstract Saudi Arabia is blessed with the world’
Phil Warran, SPE, Nidal Mishrafi, SPE, and Saleh M. Dossari, SPE, Saudi Aramco; Parvez J. Butt, SPE, Mohan Javalagi, and W
                                                                               Abstract Targeting thin sand bodies while drilling a
Abdel Nasser Abitrabi B., Ali Rabba, Waleed Amoudi, and Abdallah M. Behair, Saudi Aramco; M. Javalagi, W. Al-alqum, P. But
N. Behl, K.E. Kiser, and J. Ryan, Schlumberger IPM                             Abstract Production from low-pressure gas wells
                                                                               Abstract A novel workflow methodology and Faus
Torsten Friedel, Ramiro Trebolle, Stephen Flew, William Belfield, Juergen Meyer, Charles Curteis, Nalom Syaifullah, that cover
                                                                               Abstract Reservoir Schlumberger a standard ind
J. Moreno, A. Badawy*, G. Kartoatmodjo, H. AlShuraiqi, F. Zulkhifly, L. Tan, and T. Friedel, SPE,management is * PETRONAS
                                                                               Abstract Pursuing new alternatives to develop and
A. Alvarez, E. Guerra, A. Gammiero, C. Velasquez, J. Perdomo, and R. Hernandez, PDVSA, and�N. Rodriguez and�M. In
B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger               Abstract Field management (FM) is the simulation
                                                                               Abstract
Fernando Gutierrez, Aron Hallquist, Mack Shippen and Kashif Rashid, Schlumberger One of the most common methods of incr
                                                                               Abstract A reservoir Bhd.; andE. Kasap*, S. Yuso
T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Petronas Carigali Sdn simulation model calibrated w
                                                                               Abstract Betty is an oil field discovered in Kasap a
Antonio Cuauro, SPE, Schlumberger, Mohd Izat Ali, Maharon Bin Jadid, SPE, Petronas Carigali Sdn. Bhd.; and Ekrem 1968 an
E. Valbuena, J.L. Bashbush, and A. Rincon, Schlumberger                        Abstract Steam injection projects consume consid
                                                                               Abstract Schlumberger and studies aim at synerg
Emad Elrafie, Isabelle Zabalza-Mezghani, Tariq Abbas, Saudi Aramco, Yakov Kozlov,Integrated reservoir Roderick Craghill, Pa
                                                                               Abstract The objective Al-Kinani, Richard Torren
�ystein Tesaker, Alf Midtb� �verland, and Dag Arnesen, StatoilHydro; Georg Zangl, Andreasof this paper is to highlight
                                                                               Abstract Simulation technology from Information
A. Howell, Schlumberger Information Solutions; M. Szatny, Aspen Technology Inc.; and R. Torrens, Schlumbergerreservoir thr
                                                                               Abstract Traditionally in PEMEX
Fernando L. Morales and Juan Cruz Vel�zquez, Schlumberger, and Aar�n Garrido Hernandez, the upstream business op
T. Graf, R. Dandekar, and C. Amudo, SPE, Schlumberger                          Abstract With multi-processor cluster computing m
                                                                               Abstract The China National Offshore Oil Corporat
Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Chee Kin and Robert North, Schlumberger China Inc.
                                                                               Abstract Pablo Espinel, AGIP Oil Ecuador, water
Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco Lopez andThe production of large volumes of an EN
                                                                               Abstract The
M.A. Al-Khaldi and E.O. Ghoniem, Al-Khafji Joint Operations, and A.A. Jama, Schlumbergergas lift by limited capacity of 25 MM
                                                                               Abstract The Huizhou 6S and 3S oil fields in Liu Ya
You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh Tran, Yoseph J. Partono : CACT, Jeffrey Kok, the Pe
                                                                               Abstract This
G.C. Dozier, SPE, Schlumberger, and P. Giacon, SPE, Petroleum Development of Oman paper will illustrate the collaborative
                                                                               Abstract Palacio, Schlumberger Data workflow fo
Li Fan, Ronald B. Martin, Baljit Sehbi, Keith W. Owen, W.K. Atwood, and Juan Carlos This paper presents a uniqueand Consult
                                                                               Abstract In conditions of high Bailey, SPE, B. and
M. Prange, SPE, Schlumberger-Doll Research; M. Armstrong, SPE, Cerna, Ecole des Mines de Paris; W. demand for rigs Coue
Raphael Altman, Paolo Ferraris, and Fabricio Filardi, Schlumberger             Abstract This account describes how advanced w
                                                                               Abstract Skinner, SchlumbergerData & Consulting
Ken Halward, Joe Emery, and Rod Christensen, Oilexco; Daniel Bourgeois and Grant In 2006 Oilexco North Sea Limited deve
N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger                          Abstract We present a methodology of converting
                                                                               Abstract C.L. placement decisions are routinely m
M. Parker, Kerr McGee; R.N. Bradford, Callon Petroleum; and C. Corbett, R.N. Heim, Well Isakson, S.S. Broome, and E. Proa
                                                                               Abstract
Patrick W. von Pattay, SPE, Jeff Hamer, SPE, and Ralf Strasser, SPE, Schlumberger This paper presents an innovative filterin
                                                                              Abstract Magna Bela,* H. AlShuraiqi,** J.C. Moren
G. Kartoatmodjo, C. Bahri,* A. Badawy,* N. Ahmad, J. Moreno, B. Wu, F. Zulkhifly, S. Planning of infill drilling in oil rim reservoi
                                                                              Summary Determining the optimal location of well
M.J. Zandvliet, SPE, M. Handels, SPE, G.M. van Essen, SPE, Delft University of Technology; D.R. Brouwer, SPE, Shell Interna
M. Nukhaev, V. Pimenov, A. Shandrygin, and V. Tertychnyi, Schlumberger Abstract Steam chamber (SC) control during stea
                                                                               Spath, We present a set Oilfield Services
G. Busswell, SPE, R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J. AbstractSPE, Schlumbergerof new analytical soluti
                                                                              Abstract We present
J. Phillip Gilchrist, Geoff Busswell, Raj Banerjee, Jeff Spath and R.K. Michael Thambynayagam new semi-analytical solutions
A.M. Daoud, SPE, and L. Vega, SPE, Texas A&M U.                               Abstract Conditioning geologic models to producti
                                                                              Abstract Adjoint Cairo University
Ramez Azmy, SPE, Ahmed M. Daoud, SPE, Khaled A. Fattah, SPE, and M.H. Sayyouh, SPE,method-based sensitivity for field-
                                                                              Abstract The
J.S. Al-Thuwaini, Saudi Aramco; G. Zangl, Schlumberger; and R. Phelps, Saudi Aramco study objective is to investigate the u
                                                                              Abstract With the increasing acceptance Amor, S
C. Amudo, Chevron Australia Pty. Ltd.; T. Graf, Schlumberger; N.R. Harris, Chevron Nigeria Ltd.; R. Dandekar, F. Benof stocha
S. Yadav, Schlumberger                                                        Abstract This paper presents a novel methodology
                                                                              Abstract Sensitive Permeability
Torsten Friedel, SPE, Schlumberger, and Hans-Dieter Voigt, SPE, Freiberg UniversityThe transient pressure response in stres
                                                                              Abstract Inc.; and Kok-Thye Lim, Chevron
Xundan Shi and Yih-Bor Chang, Chevron; Mathieu Muller and Eguono Obi, Total USAWe describe the construction of a genera
                                                                              Abstract This Company
H. Cao and P.I. Crumpton, Schlumberger, and M.L. Schrader, Chevron Energy Technologypaper describes a general formulatio
Y. Wang, SPE, J. Moreno, SPE, and J.H. Harfoushian, SPE, Schlumberger Abstract Horizontal wells often present a substant
                                                                              Abstract This paper(MRC) Well
                                                                                          Contact presents a
S. Mubarak, N.I. Al-Afaleg, and T.R. Pham, Saudi Aramco, and M. Zeybek and A. Soleimani, Schlumberger methodology for m
Yuandong Wang, SPE, Dan Shan, SPE, and Robin N. Heim, SPE, Schlumberger       Abstract Horizontal and multi-lateral wells have be
                                                                              Abstract The application of Complex Wells (CW) a
Ghazi D. Al-Qahtani, Emad A. Elrafie, Raja T. Abbas, Clara E. Ikuku, and Martin F. Hogg, Saudi Aramco, and�Alexander Rin
                                                                              Abstract The Centre of Excellence
Nick Koutsabeloulis, SPE, and Xing Zhang, SPE, Schlumberger Reservoir Geomechanics pore pressure stress state and geol
C.K. Huang, Y.K. Yang*, M.D. Deo, University of Utah                          Abstract In a thermal-compositional reservoir simu
                                                                              Abstract Decline curve analysis is a graphical proc
Samuel Aderemi, SPE, and Kingsley Akpara, SPE, Schlumberger Information Solutions
                                                                              Summary SPE, M. Dessinges, SPE, and K.W. En
R. Barati, SPE, University of Kansas; R.D. Hutchins, SPE, T. Friedel, SPE, J.A. Ayoub, The fracture-propagation process perfo
T. Friedel, Schlumberger Data & Consulting Services                           Abstract To exploit the substantial tight-gas resou
                                                                              Yahya Ghuwaidi and Steve Dyer, SPE, Schlumber
Arash Soleimani, SPE, Schlumberger; Byung Lee, SPE, Saudi Aramco; and Abstract Horizontal wells with multiple fractures ar
                                                                              Abstract Schlumberger; N. Evseev, IFZ RAS; requ
O. Dinariev, IFZ RAS; A. Shandrygin, SPE, D. Rudenko, SPE, and V. Tertychyi, SPE, High accurate reservoir simulation is and
H. Gu, SPE, E. Siebrits, SPE, and A. Sabourov, SPE, Schlumberger              Abstract Interfacial slip is one of the mechanisms t
                                                                               U.K. plc
H. Sadrpanah, SPE, Schlumberger, and T. Charles and J. Fulton, Total E&PAbstract This paper presents explicit simulation o
H. Huang, Georgia Inst. of Technology, and J.A. Ayoub, Schlumberger           Abstract Non-Darcy flow reduces the productivity o
Leonardo Vega, Schlumberger, DCS                                              Abstract Wells in tight gas reservoirs are often com
B.D. Poe Jr., SPE, Schlumberger                                               Abstract This paper presents the results of an inve
                                                                              Abstract
Olivier Li�tard, Consultant, and Jerome Mani�re and Mark Norris, SchlumbergerThe expansion of horizontal well technolo
                                                                              Abstract The goal of this paper is to investigate S
S.G. Cherny, V.N. Lapin, and D.V. Chirkov, Institute of Computational Technologies, Siberian Branch of Russian Academy ofth
                                                                              Summary Artificial neural C.L. Hanks, U. of Alaska
D. Kaviani, SPE, Texas A&M U.; T.D. Bui, SPE, Schlumberger; J.L. Jensen*, SPE, Texas A&M U; and networks (ANNs) have b
                                                                              Abstract SPE, Kelkar & Associates, Inc., Xavier B
Majid Mohammadpour Faskhoodi*, SPE, Harun Ates, SPE, and Tono Soeriawinata**,To predict future reservoir performance a
                                                                              Abstract and Sami Bustami, Nile Delta of Schlum
Ahmed Daoud, SPE, Osama Hegazy, Yasser Hazem, Mohamed Lotfy, Samir Yousef,Gas reservoirs in theAramco, SPE,Egypt a
Guohua Gao, SPE, Chevron Corp.; and Younes Jalali, SPE, Schlumberger Summary This paper presents a mathematical mo
                                                                              Abstract Oil
J.J. Elphick, SPE, and L.J. Marquez, SPE, Schlumberger, and�M. Amaya, Ecopetrol viscosities of about 2 cP and above (u
                                                                              Abstract In this SPE, we present the results of a m
T. Bui, SPE, Schlumberger; M. Bandal, SPE, and N. Hutamin, SPE, Petronas; and A. Gajraj,paper Golden Eagle Intl.
Carlos A. Garcia and Jose R. Villa, U. Central de Venezuela                   Abstract Original Oil In Place (OOIP) calculations b
N. Belova and L. Berul, Schlumberger, and A. Sentyuriyev, NOVA Technologies   Introduction The main objective of the mature field
                                                                              Summary We present formulation and numerical s
Hadi Nasrabadi, Imperial College London, and Kassem Ghorayeb and Abbas Firoozabadi, Reservoir Engineering Research Ins
                                                                              SPE, Schlumberger; and J.M. Randle, SPE, Chevr
C. Amudo, SPE, Chevron Australia Pty Ltd; T. Graf, SPE, and R. Dandekar, Abstract With the dearth of easy oil in the industry
                                                                              Abstract The and M.Z. Sakdilah, Petronas
Y. Wang, SPE, Schlumberger; M. Bandal, SPE, Petronas; J. Moreno, SPE, Schlumberger;Capillary-saturation function plays an
R. Potsepaev, C.L. Farmer, and A.J. Fitzpatrick, Schlumberger                 Abstract This paper investigates the control volum
D.Rudenko, A.Shandrygin and A.Zyryanova, SPE, Schlumberger                    Abstract The peculiarities of retrograde condensati
C.A. Kossack, SPE, Schlumberger                                               Abstract The presence of vugs in a naturally fractu
                                                                              Summary The U.; and Dietmar Mueller, SPE, Sh
Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers, SPE, Stanfordapplication of elastic stress simulat
                                                                              Abstract The North Kuwait Jurassic Complex cons
Kassem Ghorayeb, SPE, Manoch Limsukhon, SPE, Schlumberger, Qasem Dashti, SPE, Rafi Mohammad Aziz, SPE, Kuwait O
                                                                              Abstract Streamline methods as a reservoir simula
A. Kozlova, Schlumberger Moscow Research; F. Bratvedt, Schlumberger Information Solutions, Oslo; and K. Bratvedt and A. M
Nikolay Andrianov, Kyrre Bratvedt, and Artyom Myasnikov, Schlumberger Abstract Naturally fractured reservoirs can be seen
                                                                              Abstract Advances Lie, SINTEF ICT; and V. Lapt
J.R. Natvig and B. Skaflestad, SINTEF�ICT; F. Bratvedt and K. Bratvedt, Schlumberger; K.-A.in reservoir characterization an
                                                                              Abstract Conceptual models Schlumberger
David O. Ogbe, SPE, Fabian O. Iwere, SPE, Linda Boukhelifa, SPE, Ernie Gomez, and Ekeng Henshaw, are used to solve spe
                                                                               and Albert C. Reynolds, SPE, U. of Tulsa
Guohua Gao, SPE, Chevron Corp.; Mohammad Zafari, SPE, Schlumberger;Summary The well known PUNQ-S3 reservoir mo
                                                                             Abstract Proxy
G. Zangl, SPE, and T. Graf, SPE, Schlumberger, and A. Al-Kinani, SPE, Mining U. Leoben models are becoming more widely
Tharwat Fawzy, Schlumberger, and Eric Mackay, Heriot-Watt University         Abstract Inorganic scales precipitate in oilfield syst
                                                                             Abstract The increasing complexities KRISTOFFE
Adriaan GISOLF, Francois DUBOST Julian ZUO, Schlumberger, Stephen WILLIAMS, StatoilHydro ASA, Julianne of newly disc
K. Gonzalez, J.L. Bashbush, and A. Rincon, Schlumberger                      Abstract Steamflood with conventional vertical we
Nikolay Andrianov and Kyrre Bratvedt, Schlumberger                           Abstract Streamline methods have become an effi
                                                                             Abstract KIAM the most challenging problems Al
Olga Podgornova, Artyom Myasnikov, and Kyrre Bratvedt, Schlumberger; Yuri Rykov,One of RAS; Elena Koldoba, MSU; andfor
                                                                             Abstract and�T. discusses a new workflow to
A. Al-Kinani, G. Nunez, M. Stundner, G. Zangl, and O. Iskandar, SPE, Schlumberger, This paperMata, S. Cottone, and J. Caves
                                                                             Tulsa
Mohammad Zafari, SPE, Schlumberger; and Albert C. Reynolds, SPE, U. of Summary Recently the ensemble Kalman Filter (E
                                                                             Abstract This paper presents a novel approach to
S. Yadav, Schlumberger, and S.L. Bryant and S. Srinivasan, U. of Texas at Austin
                                                                             Abstract We present a model for well inflow contro
K. Neylon, SPE, Schlumberger; E. Reiso, StatoilHydro ASA; J.A. Holmes, SPE, Schlumberger; and O.B. Nesse, StatoilHydro A
Kassem Ghorayeb, SPE, and Jonathan Holmes, SPE, Schlumberger                 Summary Black-oil reservoir simulation still has w
                                                                             Qasem The North Kuwait Jurassic Complex (NK
Kassem Ghorayeb, SPE, and Manoch Limsukhon, SPE, Schlumberger, and AbstractDashti, SPE, and Rafi Mohammad Aziz, S
Bernard Montaron, SPE, Schlumberger                                          Abstract Reservoir rock wettability is an important
                                                                             Abstract and John Fuller, SPE, and conducted on
Kaibin Qiu, Schlumberger; Yousef Gherryo and Mohamed Shatwan, AGOCO (Libya);An experimental study was Wesley Martin
H. Huang, SPE, and J. Ayoub, SPE, Schlumberger                               Abstract The subject of non-Darcy flow in hydrauli
A.J.G. Carnegie, Schlumberger                                                Abstract Worldwide carbonate oil-water transition
                                                                             Abstract The Margham gas field discovered in the
J. Capps and R. Khamatdinov, Margham Dubai Establishment; and S. Shayegi and S. Saeed, Halliburton
Dhruba J. Dutta, SPE, Ahmed Abu El Fotoh, and Dedi Juandi, SchlumbergerAbstract Borehole instability in most of the cases
R. Murray, SPE, BP Exploration; C. Edwards, SPE, Shell; K. Gibbons, SPE, Abstract This paper summarizes the findings of th
                                                                              Helix-RDS; S. Jakeman, SPE, Shell;�G. de Jon
                                                                             Abstract “SCR Rosnedra
A.N. Shandrygin, SPE, Schlumberger, and A. Lutfullin, State Commission Resources Russia is one of the main oil producing co
                                                                             Abstract Consulting Services; and T. the SPE,
J.A. Walker, SPE, ConocoPhillips Alaska Inc.; D.O. Ogbe, SPE, Schlumberger Data &Alaska’s North Slope andZhu, United
Simon James, SPE, and Linda Boukhelifa, SPE, Schlumberger                    Summary Over the past 10 years several papers
                                                                             Abstract After more than 20
M. Claverie, SPE, Schlumberger; N.A. Malek, SPE, Petronas Carigali; and K.F. Goh, SPE, Schlumberger years of exploitation
Jeffrey Grant, Dale May and Keith Pinto, Schlumberger                        Abstract Pulsed neutron measurements have bee
                                                                             Abstract Accurate time-lapse SPE, I. Mahgoub, SP
M. Van Steene, SPE, B. Herold, SPE, D. J. Dutta, SPE, Y. Abugren, S. Hosny, Schlumberger, A. B. Badr, saturation informatio
                                                                             Abstract During the last decade intelligent well com
M. Zakharov, Schlumberger; S.H. Eriksen, Hydro Oil & Energy; and I. Raw, S. Pride, and�A.�Ridez, Schlumberger
Koksal Cig and Ihsan Gok, Schlumberger                                       Abstract The new production logging tool string an
                                                                             Abstract Exploration Co.; and Ram Sunder, Matt
D.E. Fitz, ExxonMobil Upstream Research Co.; Angel Guzm�n-Garcia, ExxonMobilProduction logging and flow profile interp
                                                                             Abstract The identification of condensate banking
B.C. Theuveny, P.D. Maizeret, N.S. Hopman, and S. Perez, Schlumberger Oilfield Services
                                                                             Abstract The combination of low permeability oil b
K.D. CONTREIRAS and F. VAN-D�NEM, Sonangol P & P; P. WEINHEBER, A. GISOLF and M. RUEDA, SPE, Schlumberge
                                                                             Abstract The combination of low permeability Serv
K.D. Contreiras and F. Van-Duinem, Sonangol P & P; P. Weinheber, A. Gisolf, and M. Rueda, SPE, Schlumberger Oilfield oil b
                                                                             Abstract This paper describes an innovative Down
Abdullatif Al-Omair, SPE, Orji O. Ukaegbu, SPE, and Muhammed Alshafie, SPE, Saudi Aramco; Muhammad Shafiq, SPE, and
                                                                             Summary A new downhole pH sensor has been d
B. Raghuraman, SPE, and M. O'Keefe, SPE, Schlumberger; K.O. Eriksen, SPE, L.A. Tau, SPE, and O. Vikane, SPE, Statoil; a
                                                                             Abstract With increasing availability of real-time do
R.A. Holicek, J. Adachi, L.A. Viloria, A.I. Mese, and Y. Traore, Schlumberger, and A.P. Singh and R. Hanssen, TOTAL
                                                                             Abstract A multistage hydraulic fracture Sciences
Leo Eisner, Schlumberger Cambridge Research; Tomas Fischer and Zuzana Jechumt�lov�, Czech Academy oftreatment
George C. Dozier, Schlumberger                                               Abstract Fracture height prediction and evaluation
                                                                             Abstract S. Lyngra, Saudi Aramco
A. Al-Behair, Saudi Aramco, S. Malik and M. Zeybek, Schlumberger, A. Al-Hajari and Accurate diagnostics of wellbore fluid entr
                                                                             Abstract During the start-up and early operation of
P. Krawchuk, SPE, and M.A. Beshry, Total E&P Canada, and G.A. Brown, SPE, and B. Brough, SPE, Schlumberger
B.D. Poe Jr., SPE, and R.J. Butsch, SPE, Schlumberger                        Abstract This paper addresses some recent devel
B.D. Poe Jr. and R.J. Butsch, Schlumberger                                   Abstract This paper presents some recent develop
                                                                             Abstract Fiber-optic systems are
H. Huebsch, M. Moss, and T. Trilsbeck, EnCana, and G. Brown, S. Rogers, and T. Bouchard, Schlumberger able to generate a
                                                                             Abstract Schlumberger
Ali Bakhshi, SPE, Woodside Energy Ltd; Peter Scaife, Tracerco; and Ian Mickelburgh,This paper presents the first case study o
                                                                             Summary Flow Riboud fluid type (phase) are two
M. Webster, SPE, and S. Richardson, SPE, BP Exploration; C. Gabard-Cuoq, Schlumberger rate andProduct Center; J.B. Fitzg
                                                                             Abstract Fractures identification Soodabeh during
Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Energy Canada; Hadi Parvizi, WSI; is essential Esma
                                                                                       0
Chen Jiun Horng @ Chris; Norbashinatun Salmi Nordin; M Azrul Nuriyadi; Noren Samsudin; Abdullah Kasim; Petronas Carigali
                                                                             Abstract The availability of accurate performance
Michael Stundner and Gustavo Nunez, Schlumberger, and Frank M�ller Nielsen, StatoilHydro
                                                                             Abstract Production Chang, Schlumberger
K. I. Ojukwu, M.I. Khalil, J. Clark, H. Sharji, Petroleum Development Oman, and J. Edwards, T. K.logging low flow rate wells is d
                                                                             Abstract The Wara reservoir has been producing f
Anil Ambastha, SPE, Chevron; Qasem Dashti, SPE, Kuwait Oil Company; Pierre-David Maizeret, SPE; Farhan Al-Farhan, SPE
                                                                             Abstract In this paper we present a Rae, S.K. Foo
P.E. Parta, SPE, A. Parapat, R. Burgos, SPE, J. Christian, SPE, and A. Jamaluddin, SPE, Schlumberger, and G. field example
K.M. Hanafy, SPE, GUPCO, and T.A. Elsherif, SPE, Schlumberger                Abstract With the dramatic increase in oil prices o
                                                                             Summary Modern SPE, and C. Ayan, SPE, (WFT
H. Elshahawi, SPE, M. Hashem, SPE, and D. McKinney, Shell International E&P, and M. Ardila,wireline formation testers Schlu
G.A. Brown, SPE, Schlumberger                                                Abstract Early identification of differential depletion
                                                                           Summary Technologies
S.C. Maxwell , J. Du, J. Shemeta, U. Zimmer, N. Boroumand, and L.G. Griffin, PinnacleA combination of microseismic and surf
                                                                           Abstract BP is developing
I.D. Pinzon, SPE, J.E. Davies, SPE, BP, F. Mammadkhan, SPE, and G.A. Brown, SPE, Schlumberger its Azeri field using devi
                                                                           Abstract The expense of
S. Mackay, SPE, J. Lovell, SPE, D. Patel, SPE, F. Cens, SPE, and S. Escanero, SPE, Schlumberger subsea well intervention o
                                                                            Gok5, Mohammed key issues in creating a good r
Bingjian Li1, Hamad Najeh2, Jim Lantz3, Mansoor Ali Rampurawala4, Ihsan Abstract One of the Al-Khabbaz6 1 ,4,5,6Schlumbe
                                                                           Abstract A Anumber Dream or Reality? The Case o
B. Theuveny, A. Kosmala, P.-D. Maizeret, and R.K. Sagar, Schlumberger Oilfield ServicesVirtualof real time enablements of pro
M. Stundner, SPE, and G. Nunez, SPE, Schlumberger                          Abstract The availability of accurate production vo
                                                                           Abstract Maximising the potential of a producing w
O. Ojonah, SPE, Shell Production and Development Co., and J.J. Kohring, SPE, Schlumberger Nigeria
                                                                           Abstract The paper presents a novel and B. appr
P.J. Gauthier and H. Hussain, Petroleum Development Oman; J. Bowling, Blade Energy Partners; and J. Edwardslogging Hero
                                                                           Abstract Improvement of oil recovery and reduction
Dhruba J Dutta, SPE, Schlumberger and Abdallah B Badr, SPE, Agiba Petroleum Company
                                                                           Abstract For pressure maintenance
M. M. Amer, O. Al-Farisi,T. Hiraiwa, M. Attia, A. Al-Habshi, SPE, ADMA-OPCO, A. Madjidi, SPE, Schlumberger purpose periph
                                                                           Abstract Abu paper we will
Zahid Bhatti, Mohamed Shuaib, ADCO, Michael Wilt, Cyrille Levesque, Schlumberger,In theDhabi, UAE briefly review the pilo
                                                                           Abstract Lynn Reeder, Schlumberger-Doll Resea
Malalla Al Ali, Volker Vahrenkamp, Saber Elsembawy, and Zahid Bhatti, ADCO; StacyTime-lapse cross-well electromagnetic (E
                                                                           Summary Worldwide Coal Bed Methane (CBM) re
P.M. Snider, SPE, Marathon Oil Co.; I.C. Walton, SPE, Schlumberger; T.K. Skinner, Marathon Oil Co.; and D.C. Atwood, SPE,
                                                                           Abstract Theodore Klimentos (Schlumberger), In
Mohammad Ali (ONGC), Arpana Sarkar (Schlumberger), Rajiv Sagar (Schlumberger),Fracture systems comprise the primary fl
                                                                           Abstract Propped hydraulic fracture stimulation has
T.N. Olsen, T.R. Bratton, A. Donald, R. Koepsell, and K. Tanner, Schlumberger
                                                                            Schlumberger
A.A. Ketter and J.R. Heinze, Devon Energy, and J.L. Daniels and G. Waters,Summary The Barnett shale is an unconventional
                                                                           Abstract Hydraulic fracturing is the Inc.; and M. B
R. Su�rez-Rivera, SPE, and S.J. Green, SPE, TerraTek Inc.; J. McLennan, SPE, ASRC Energy Services E&Trequisite metho
                                                                           Abstract Nitrogen coiled tubing fracturing is Schlu
Abbas Mahdi, Schlumberger; Mike Yu, EnCana Corp.; and Doug Pipchuk, Craig Wasson, Jim Nguy, and Nathan Kathol, the pr
                                                                           Abstract Horizontal wells and J. Daniels, SPE, an
G. Waters, SPE, Schlumberger; J. Heinze, SPE, R. Jackson, SPE, and A. Ketter, SPE, Devon Energy;represent a growing perc
                                                                           Abstract The Grant, SPE, Barnett Calvez, SPE,
C. Du, SPE, X. Zhang, SPE, B. Melton, D. Fullilove, B. Suliman, SPE, S. Gowelly, SPE, D. Mississippianand J. LeShale reservoi
F. Akram, SPE, Schlumberger Canada Ltd.                                    Abstract Estimated at 2.5 trillion barrels Canada h
                                                                           Distinguished Author Series articles are general d
Creties D. Jenkins, SPE, DeGolyer and MacNaughton, and Charles M. Boyer II, SPE, Schlumberger
                                                                            Gillard, Gas production from the unconventional
D.I. Potapenko, S.K. Tinkham, B. Lecerf, C.N. Fredd, M.L. Samuelson, M.R.Abstract J.H. Le Calvez, and J.L. Daniels, Schlumb
F.F. Chang, SPE, and M. Abbad, Schlumberger                                Abstract The chemical nature of carbonate rocks m
                                                                           Abstract The Electrical Sudhakar Khade, SPE, Sc
Ahmed R. Al Zahrani, SPE, Redha H. Al-Nasser, SPE, and Timothy W. Collen, SPE, Saudi Aramco; Submersible Pump (ESP)
                                                                            SPE, Schlumberger
F. Gaviria, SPE, SUNCOR, and R. Santos, SPE, O. Rivas, SPE, and Y. Luy,Abstract The need for high-temperature electric su
Siddhartha Gupta, Schlumberger                                             Abstract Artificial lift systems are now being consid
                                                                           Abstract SPE, Anna Zubareva, Andrey Vasiliev, Y
Sergey Ryzhov, SPE, Vladimir Malyshev, SPE, Shlumberger, and Tatyana Kruchkova,The Sporyshevskoye oil field developmen
                                                                           Abstract The offshore northeast Brazil Barbedo, S
A. Calderon, SPE, A.F. Arag�o, SPE, and C.M. Chagas, SPE, PETROBRAS, and C. Guimar�es, SPE, and R. Manati field
Gary Rytlewski, Schlumberger                                               Abstract A new method of completing multiple-laye
                                                                           Abstract Cartojani is a mature oil field with deplete
Surej Subbiah/Schlumberger; Wielemaker.E/Schlumberger; Joia P/Petrom SA; Hopper.L/Schlumberger; Fernandez LI/Schlum
B.D. Poe Jr., SPE, Schlumberger                                            Abstract This paper presents the results of an inve
B.D. Poe Jr., SPE, Schlumberger                                            Abstract This paper presents the results of an inve
                                                                           Abstract Mauddud reservoir in the Greater Burgan
M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K. Ambastha, and M. Anderson, Chevron; and B. Rahman, K
                                                                           Abstract The lower Minghuazhen is a shallow-wat
Liu Song, Li Jianping, and Lv Dingyu, CNOOC, and Jeffrey Kok and Shim Yen Han, Schlumberger
                                                                           Shafiq, This paper describes a case-study detaili
S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. AbstractSPE, Schlumberger
T.S. Ramakrishnan, Schlumberger-Doll Research                              Summary Poor displacement efficiency in hydroca
                                                                           Shafiq, SPE, Schlumberger
S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Summary This paper describes a case study that
                                                                           Abstract The number of multilateral Kharrat, SPE
Jose R. Amorocho, J. Ricardo Solares, Abdulmohsin Al-Mulhim, and Ali Al-Saihati, SPE, Saudi Aramco; Wassim gas producers
                                                                           Abstract Current A. Ayyad, SPE, Schlumberger; a
Mohammed M. Amro, SPE, and Mohamed S. Benzagouta, SPE, King Saud University; Hazim drilling technology is moving towa
J. Jaua and O. Rivas, SPE, Schlumberger, and A. Mej�as, Repsol YPF Abstract As a result of the increasing emphasis on
                                                                           Summary A rigorous statistical methodology using
W.J. Bailey, SPE, Schlumberger-Doll Research; I.S. Weir, U. West of England; B. Cou�t, SPE, Schlumberger-Doll Research
                                                                           Abstract Acid Fracturing has been a successful m
F.O. Garzon, H.M. Al-Marri, J.R. Solares, and C.A. Franco Giraldo, SPE, Saudi Aramco, and V. Ramanathan, SPE, Schlumber
                                                                           Abstract The SPE, field located on the North Slop
Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co.; Bob Barree, AlpineBarree�& Assocs.; and Mich
                                                                           Abstract T. Vizurraga, Schlumberger
A. Powell, Headington Oil Co., O. Bustos, W. Kordziel, T. Olsen, D. Sobernheim, and Since the horizontal lateral Bakken dolom
                                                                           and Albert Gayfullin, SPE, Dmitry Senchenko, and
D. Oussoltsev, SPE, K. K. Butula, SPE, and A. Klyubin SPE, Schlumberger, Abstract Successful hydraulic fracturing in various
                                                                           Abstract Saudi Aramco, and Venkateshwaran Ar
Maytham I. Al-Ismail, SPE, Moataz M. Al-Harbi, SPE, and Abdulaziz K. Al-Harbi, SPE,Acid fracturing has been part of Saudi Ra
                                                                           Abstract This paper Oussoltsev, SPE, and K.K. B
S. Sitdikov, SPE, A. Serdyuk, and A. Nikitin, SPE, Rosneft, and A.Yudin, SPE, K. Mullen, SPE, D.describes successful impleme
                                                                           Abstract Flowback aids are usually Dismuke, CES
Paul R. Howard, Sumitra Mukhopadhyay, Nita Moniaga, Laura Schafer, Schlumberger, and Glenn Penny, Keith surfactants or c
Hongren Gu, SPE, and Eduard Siebrits, SPE, Schlumberger                    Summary Much study has been conducted on the
                                                                           Abstract Natural gas reservoir development Shen
Daren Bulat, SPE, Talisman Energy Inc., and Yiyan Chen, Matthew K. Graham, Richard Marcinew, Goke Adeogun, Jackcontin
S.M. Rimassa, SPE, P.R. Howard, SPE, and K.A. Blow, SPE, SchlumbergerAbstract As mature fields produce larger quantities
                                                                               Abstract The key and Tarik Itibrout, tight-gas field
Bilu Cherian, SPE, Schlumberger; Kirk Fields, SPE, and Seth Crissman, SPE, ConocoPhillips; to the success of aSPE, and Mal
                                                                               Abstract Frac-pack is a pervasively used completi
O. Hidalgo, Schlumberger Well Services; O. Gonz�lez and V. Gonz�lez, PDVSA; and A. S�nchez, and A. Pe�a, Sch
                                                                               Abstract
A.V. Yudin and K.K. Butula, Schlumberger, and Y.V. Novikov, OAO Tomskneft VNK The productive pay of the low permeability
                                                                               Abstract In the recent years Liu, SPE, Redha Kelk
Majdi Al Mutawa, SPE, Bader Al Matar, SPE, and Yousef Abdul Rahman, SPE, Kuwait Oil Company; Haihorizontal well technol
                                                                               Abstract A Malonga, SPE, Eni Congo
R. Arangath, SPE, Schlumberger, and J.F. Obamba, SPE, P. Saldungaray, SPE, and H. common scenario in many mature oilf
                                                                               Abstract Apache; Fabio Pe�acorada, YPF; ge
Pedro Saldungaray, Schlumberger; Efrain Huidobro Salas, Pemex; Sebastian Vargas,Latin America hasn’t escaped theJos
                                                                               Abstract Many West Cantaloube, SPE, Schlumber
Alberto Casero, SPE, and Giamberardino Pace, SPE, Eni E&P; Brad Malone, SPE, and Francois Africa offshore fields are matu
                                                                               Abstract One Aramco; strategies in Saudi Aramc
J.R. Solares, SPE, C.A. Franco, SPE, H.M. Al-Marri, SPE, and H.A. Al-Jubran, SPE, Saudi of the keyVenkateshwaran Ramana
                                                                               Alexandru Dragomir, SPE, and Viorel Ghita, Petro
Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Offshore operations are extremely expens
                                                                               Alexandru Dragomir, System, Executed extremely
                                                                                           Free offshore operations are from OM
Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Current FluidSPE, Petrom member ofa Su
                                                                               Rohit Panse, Ikhsan Nugraha, Pankaj Taneja bro
Rajiv Sagar, Schlumberger; A.K. Pandey, Durga Prasad, A.K. Vinod ONGC, Abstract Gandhar is one of ONGC’s majorSch
B.D. Poe Jr., SPE, Schlumberger, and J.F. Marique, SPE, Consultant             Abstract This paper presents the results of an inve
T.N. Olsen, T.R. Bratton, and M.J. Thiercelin, Schlumberger                    Abstract Since the widespread proliferation micro-
                                                                               Abstract The majority of hydraulic fracturing work
A.N. Parfenov, SPE, S.S. Sitdikov, SPE, O.V. Evseev, SPE, and V.A. Shashel, Rosneft, and K.K. Butula, SPE, Schlumberger
                                                                               Abstract Hydraulic fracturing of horizontal wells in
George Waters, Barry Dean, and Robert Downie, Schlumberger, and Ken Kerrihard, Lance Austbo, and Bruce McPherson, Co
G. Rytlewski and J. Lima, Schlumberger, and B. Dolan, Petrogulf                Abstract A new method of completing multiple laye
G.L. Rytlewski and J.M. Cook, Schlumberger                                     Abstract A new method of completing multiple-lay
Olga Alekseenko, Schlumberger                                                  Abstract Petroleum engineers have faced the prob
                                                                               Schlumberger, and D. Surfactant (VES) fluids are
P.F. Sullivan, B. Gadiyar, R.H. Morales, R. Hollicek, D. Sorrells, and J. Lee, Abstract Visco-ElasticFischer, Remington Oil and
                                                                               Abstract A F.A. carbon Y. Chen, J.W. emulsifi
M.E. Semmelbeck, W.E. Deupree, and J.K. von Plonski, SPE, Escondido Resource, andnovel Mueller,dioxide- (CO2-)Lewis, L.
                                                                               Abstract This paper discusses the selection A. Bu
Vibhas J. Pandey and Tarik Itibrout, SPE, Schlumberger; Larry S. Adams, SPE, Chevron; and Tracy L. Cowan and Oscarcriteri
                                                                               Abstract Tip-Screen-Out and M. Mill�n, PDVSA
                                                                                           Permeability Reservoirs Using a of Flu
                                                                                                       Generation Viscoelastic hig
P. Parra, E. Miquilena, A. S�nchez, and A. Pe�a, Schlumberger Well Services, and A. Garc�a(TSO) stimulationsNew
                                                                               Abstract Offshore
Areiyando Makmun, Schlumberger, and Fathi Issa and Gadalla Hameed, Sirte Oil Company A drilling program on North Rag
                                                                               Abstract Kuwait Oil presents the process of candid
Qasem Dashti, SPE, Mir Kabir, SPE, Raju Vagesna, SPE, Feras Al-Ruhaimani, SPE, This paper Company, and Hai Liu, SPE, S
                                                                               Abstract It is well documented in C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SPE, Shell; S. Cobianco, SPE, andthe literature that
                                                                               Abstract Microseismic hydraulic fracture Brook, an
Jason Baihly, Schlumberger; Andrew Coolidge and Steven Dutcher, Devon; and Ruben Villarreal, Mike Craven, Keith monitorin
                                                                               Abstract Productivity impairment in
Torsten Friedel, George Mtchedlishvili, Aron Behr, Hans-Dieter Voigt, and Frieder H�fner, Freiberg Universitytight-gas forma
                                                                               Summary Geophysical Inst. of the Academy azim
P. Bulant, Charles U.; L. Eisner, Schlumberger Cambridge Research; I. PšenĿ�k, Significant errors in the calculated of Sc
                                                                               Abstract To achieve maximum production tight-g
                                                                                           Permeability SPE, Schlumberger
M.N. Bulova, SPE, A.N. Cheremisin Jr., SPE, K.E. Nosova, SPE, J.T. Lassek, SPE, and D. Willberg,Formations
C. Malagon, SPE, M. Pournik, SPE, and A.D. Hill, SPE, Texas A&M University     Summary In an acid-fracturing treatment fracture
A. Nikitin and A. Shirnen, Rosneft, and J. Maniere, Schlumberger               Abstract The generalization of Hydraulic fracturing
                                                                               Abstract For years radioactive tracers have been
R.R. McDaniel, SPE, and J.F. Borges, SPE, Hexion Specialty Chemicals, and S.S. Dakshindas, SPE, Marathon Oil Corporation
                                                                               Abstract The focus of our research is SPE, and G
Alexey Nikitin, SPE, Rosneft-Yuganskneftegaz; Alexey Yudin, SPE, Schlumberger; and Ilyas Latypov, Azat Haidar, on a remote
                                                                               Abstract Though there are many proven ways of p
Y. Shumakov, A.A. Burov, and K.K. Butula, SPE, Schlumberger, and I.A. Zynchenko, Gazprom
A.H. Akram, SPE, and A. Samad, SPE, Schlumberger                               Abstract A study was carried out to forecast the p
                                                                                E.M. Chekhonin, Schlumberger the tip of a hydrau
V.M. Entov, Inst. for Problems in Mechanics, Russian Academy of Sciences;Abstract Pressure distribution at Moscow Researc
                                                                               Abstract H. Al-Ghadban, V. Ramanathan, S. Kelk
H.A. Nasr-El-Din, SPE, S. Al-Driweesh, SPE, and K. Bartko, SPE, Saudi Aramco, and The deep tight carbonate formations in S
                                                                               Abstract This
J.F. Manrique, SPE, Occidental Oil and Gas Corp., and B.D. Poe Jr., SPE, Schlumberger paper presents the results of an inve
S.C. Maxwell, U. Zimmer, R. Gusek, and D. Quirk, Pinnacle Technologies Canada  Summary Microseismic imaging of a hydraulic-fra
                                                                               Abstract Proppant flowback is an extremely import
G.R. Aidagulov and M. Thiercelin, Schlumberger, and V.N. Nikolaevskiy, S.M. Kapustyanskiy, and A.G. Zhilenkov, Inst. of Phys
X. Weng and E. Siebrits, Schlumberger                                          Abstract In this work the propagation of an orthogo
                                                                               Abstract The practical problem arises in enhancin
Smirnov N.N., Kisselev A.B., Nikitin V.F., and Zvyaguin A.V., Moscow M.V. Lomonosov State U.; Thiercelin M. SRE, Schlumbe
                                                                               Abstract Kalyanaraman, and S. Tcherkashnev, S
A. Nikitin and A. Pasynkov, Rosneft YNG, and G. Makarytchev, J. Maniere, R. SunderIn a waterflooded reservoir hydrocarbon
                                                                               Abstract S. Cobianco, SPE, and C.N. Emiliani, S
J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SPE, Shell;This paper summarizes part of the resul
                                                                               Abstract Kikeh Field is a Ivan Munoz, Hugo Morale
Tamara Webb, Jusni Omar, Murphy Oil Corporation, Saifon Daungkaew, Lee Chin Lim, Ray Tibbles, deepwater project located
                                                                               Abstract Hydraulic fracturing plays a
Almeida, C.M.C. de, Schlumberger; Melo, R.L.C., Petrobras; Holzberg, B. B.; Guimaraes, C., SPE, Schlumberger very importan
                                                                                Schlumberger RTC UG
R.G. Jeffrey and X. Zhang, SPE, CSIRO Petroleum, and M. Thiercelin, SPE,Abstract Offsets along the hydraulic fracture path
Adam Vasper, SPE, Schlumberger                                                 Summary The terms auto natural and in-situ gas
                                                                               Abstract BP Trinidad and Tobago B. Lanclos and
S.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morrison, BP; G. Hurst, Consultant; and(bpTT) has been
                                                                               Abstract M. Shaheen, SPE, Z. Al-Jalal, Schlumbe
K. M. Al-Naimi, SPE, B. O. Lee, SPE, K. M. Bartko, Saudi Aramco, S. K. Kelkar, SPE,Horizontal completion technology has pro
                                                                               Abstract Schlumberger, B. Johnston, Packer pro
K. M. Al-Naimi, B. O. Lee, S. M. Shourbagi, Saudi Aramco, S. K. Kelkar, M. Shaheen,Horizontal completion technology hasPlus
                                                                               Abstract Completing horizontal wells with openhole
Hassan Chaabouni, Schlumberger, Pierre Baux, Dasa Manalu, Muhammad Sobirin, Total E&P Indonesie, Philippe Enkababian
                                                                            Abstract This paper describes an innovative comp
Muhammad Shafiq and Athar Ali, SPE, Schlumberger; and Haider Al-Haj, Ibrahim Obaidi, Muhammad Qasim Qazi, and S.M. M
                                                                            Abstract Horizontal wells are superior in productio
E. Davila, R. Almeida, I. Vela, J. Pazos, and K. Coello, Petroamazonas;�F. Chinellato and�O. Humbert, Schlumberger; an
M.A. Ali, SPE, and M. Shafiq, SPE, Schlumberger                             Abstract Intelligent completions have been in com
Mohammed A. Abduldayem, SPE, Saudi Aramco, Muhammad Shafiq, SPE, Abstract This paper describes an innovative comp
                                                                            Schlumberger, Nader D. Al Douhan, SPE, and Zul
                                                                            Abstract Significant challenges remain in London
E.A. Addiego-Guevara, SPE, and M.D. Jackson, SPE, Department of Earth Science and Engineering, Imperial Collegethe deve
                                                                             Green, The design and subsequent results of a h
L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S.Abstract TerraTek
R. North, SPE, C.P. Lenn, SPE, and I. Stowe, SPE, Schlumberger              Abstract A new processing workflow has been eng
                                                                            Abstract As Nor Hisham Mohd Azam, Edna Malim
Saifon Daungkaew, Michel Claverie, Boon Cheong, Steve Hansen, Richard Leech, Mohd the cost of exploration wells continue
                                                                            Abstract Sanding Operations, and C. P. Tan, Schlu
M. A. Mohiuddin, Schlumberger, M. M. Najem, Y. R. Al-Dhaferi, H. A. Bajunaid, Al-Khafji Joint problems are often observed in f
                                                                             Ian C. Walton, Schlumberger
Kirk M. Bartko, Saudi Aramco, and Frank F. Chang, Larry A. Behrmann, andAbstract It is well known that in cased-hole comple
                                                                            Abstract The transition from completion to produc
Achille Tiribelli, Giovanni Luca Minneci, and Ahmed Daoud, Groupement Sonatrach Agip, and Fathi Ghodbane and Ahmed Dah
                                                                            Abstract Coiled tubing has been widely E. Parta, S
M.I. Omar, SPE, A. Md Ali, SPE, and Z. Ali, Petronas Carigali Sdn. Bhd., and A. Parapat, SPE, W. Speck, SPE, and used world
                                                                            Abstract Located in J. Romero, and Y. Gonzalez,
M. Medina, SPE, Helix RDS; G. Morantes, SPE, and J. Morales, PDVSA; and W. Guevara, SPE,Eastern Venezuela the Santa A
                                                                            Abstract China National Khong, Oil Behrmann, (
Italo Pizzolante, Steve Grinham, Tian Xiang, and Jihong Lian, CACT Operators Group, and Chee KinOffshoreL.A. Corporation a
                                                                            Abstract Fracturing Total E&P USA, Inc.
Cesar Gama, David Gerez, and Paul A. Babasick, SPE, Schlumberger, and Jose Piedras, SPE, is an important technique for s
                                                                             and Majed Shaaban Abu Lawi, Schlumberger
Al-Marri Faisal and Hassan Ibrahim Khalil, ADMA-OPCO, and Alan SalsmanAbstract A major challenge identified by ADMA OP
                                                                            Abstract Reliable estimates of post perforation SP
Lang Zhan, SPE, Fikri Kuchuk, SPE, Jim Filas, SPE, Dhani Kannan, SPE, Jawaid Saeedi, SPE, and Charles Van Petegem, dam
                                                                            Abstract In Jock Munro, Schlumberger
Graeme Rae, Mohd. Bakri Yusof, and Juanih Ghani, Talisman, and Shahril Mokhtar andMalaysia coiled tubing (CT) conveyanc
C. Han, Michael H. Du, and Ian C. Walton, SPE, Schlumberger                 Abstract A detonated shaped charge fired from a p
                                                                             and Alan Salsman SPE, is driven by establishing
Hanaey Ibrahim, SPE, and Sameer Balushi, Petroleum Development Oman,Abstract Well productivityAlvaro Javier Nunez, and
                                                                            Abstract We report on a series of
D.C. Atwood, SPE, W. Yang, SPE, B.M. Grove, SPE, L.A. Behrmann, SPE; Schlumberger Technology Corp. laboratory flow e
                                                                            Abstract Optimal well productivity is Situmorang; S
Hanaey Ibrahim SPE, Ali Harrasi, Petroleum Development Oman, Alan Salsman, Alvaro Javier Nunez, Haposan achieved by es
                                                                            Abstract Saudi Aramco's drilling strategy witnesse
Mohammad S. Al-Shenqiti, Alaa A. Dashash, Ibrahim H. Al-Arnaout, Saad M. Al-Driweesh, Saudi Aramco, and Zaki Bakhteyar,
                                                                            Abstract The Campos Basin in Brazil SPE, of the
C.A. Pedroso, SPE, E.M. Sanches, and N.S. Oliveira, Petrobras, and I.J. Mickelburgh, SPE, and C.R Guimaraes, is oneSchlum
                                                                            Summary SPE, Devon Energy Corporation; Kenyo
Luke F. Eaton, SPE, and W. Randall Reinhardt, SPE, ConocoPhillips; J. Scott Bennett, ConocoPhillips is developing the Magno
                                                                            Abstract Schlumberger, Tim O’Rourke, Schlum
Ibrahim Refai, SPE Saudi Aramco, Anwar Assal, SPE Schlumberger, Jeremie Fould, A number of the wells reach there econom
                                                                            Summary ConocoPhillips is developing the Magno
George Colwart, SPE, Robert C. Burton, SPE, Luke F. Eaton, SPE, and Richard M. Hodge, SPE, ConocoPhillips Company, an
                                                                            Abstract Alpha field Udeh, T. in SPDC’s OM
I.O. Yahaya, A. Opusunju, B. Ajaraogu, G. Agbogu, O. Williams, and C. Uchendu, SPDC; and M. is situatedOyetade, and M. Ba
                                                                             and Abraham T. Faga, SPE, and Howard L. McKi
Brian T. Wagg, SPE, and Jonathan L. Heseltine, SPE, C-FER Technologies,Abstract Several operators have recently launched
                                                                            Abstract The major trend and Aziz Ejan, Abdul in
Matthew Law, George W. Chao, Hafeez Ab Alim, and Elsamma Samuel, Schlumberger Well Services, of completion method Ha
                                                                            Abstract and Open Hole Gravel Pack
Kevin Whaley, Colin Price-Smith, Allan Twynam, and David Burt, BP Exploration Ltd.,InitialPhillip Jackson, Baroid (OHGP) co
                                                                            Abstract Well Heidrun Ridene, SPE, and Norweg
Ina H. Stroemsvik, Kjell Tore Nesvik, SPE, Frode Vik, and Karin Stene, StatoilHydro, and MohamedA-45 located in theDaniele
                                                                            Abstract One of the major challenges in undergrou
A. Zanchi, Stogit; G. Ripa, M. Colombo, and G. Ferrara, SPE, Eni E&P; and E. Belleggia, R. Barbedo, R.�Illuminati, J. Rezen
                                                                            Abstract Openhole gravel packing is one of the mo
M. Tolan, BG Group, and R.J. Tibbles, J. Alexander, P. Wassouf, L. Schafer, and M. Parlar, Schlumberger
                                                                            Abstract Gravel packing
Samyak Jain, SPE, Rajesh Chanpura, SPE, Renato Barbedo, and Marcos Moura, SPE, Schlumbergerhas routinely been used
                                                                            Abstract M. Parlar, Schlumberger
E.P. Ofoh and M.E. Wariboko, Nigerian Petroleum Development Co., F.E. Uwaifo and A large majority of the recent deepwate
                                                                            Abstract Cased-hole gravel packing is commonly
Samyak Jain, SPE, Raymond Tibbles, and Jock Munro, SPE, Schlumberger, Rajeswary Suppiah and Norhisham Safin, SPE, P
                                                                            Munro, Cased-hole gravel and Rajeswary Supp
Shahryar Saebi, SPE, Samyak Jain, SPE, Raymond Tibbles, SPE, and Jock AbstractSPE, Schlumberger,packing is commonly
                                                                            Abstract Gj�a Atwood, SPE, J. Heiland, SPE,
J. S. Andrews, SPE, H. Bj�rkesett, SPE, J. Djurhuus, StatoilHydro; I. C. Walton, SPE, D. C.is an oil and gas field located off B
                                                                            Abstract This paper presents
S. Wibawa, S. Kvernstuen, Schlumberger, and A. Chechin, J. Graham, and K.R. Dowling, Apache Energy the first installation o
                                                                            Abstract Screenless sand control completions pro
M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D. Bowman, R.A. Jansen, and S.N. Krenzke, Schlumbe
B. Vidick, SPE, S. James, SPE, and B. Drochon, SPE, Schlumberger            Abstract The search for a cost-effective alternative
                                                                            Abstract Sand production from the Sarir field becam
K. Qiu, SPE, Schlumberger; Y. Gherryo and M. Shatwan, SPE, AGOCO, Libya; R. Marsden, J. Alexander, and A. Retnanto, SP
                                                                            This paper was also presented SPE, Agoco
K. Qiu, J.R. Marsden, J. Alexander, and A. Retnanto, Schlumberger, and O.A. Abdelkarim and M. Shatwan, as SPE�100948
                                                                            Abstract This paper Alexander, case study involve
Ahmed Abulsayen and Abdulwahab Enneamy, VEBA (Libya), and Kaibin Qiu, Rob Marsden, Joe described a and Muhammad S
                                                                            Summary It is commonly acknowledged in the pet
Bailin Wu, SPE, and Chee P. Tan (Now with Schlumberger Oilfield Support Sdn Bhd.), SPE, CSIRO Petroleum, and Ning Lu, C
                                                                            Summary Although the stacked
Abdullah Kasim, SPE, Petronas Carigali; and Frank Wijnands, SPE, and Surej Subbiah, SPE, Schlumberger reservoirs of the B
J. Heiland, SPE, and M.E. Flor, Schlumberger                                Abstract During production of hydrocarbons the f
                                                                            Abstract This Scientific Services Sdn. Bhd.; C.P.
B. Wu, SPE, CSIRO Petroleum; Nulwhoffal Arselan Mohamed, SPE, Petronas Research &paper presents a geomechanical stu
                                                                            Summary Well Services
Hisham A. Nasr-El-Din, SPE, Saudi Aramco, and Mathew Samuel, SPE, Schlumberger Viscoelastic surfactant systems are use
                                                                             Texas A&M effects of acid solutions injected
M. Pournik, C. Zou, C. Malagon Nieto, M.G. Melendez, D. Zhu, and A.D. Hill,Abstract TheU., and X. Weng, Schlumberger into
                                                                            Abstract The SPE, an acid fracture treatment is t
G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt, SPE, D. Stief,goal ofL. Temple, SPE, and V. Rodrig
                                                                            Abstract Acid fracturing has been an integral part o
J. Ricardo Solares, SPE, J.J. Duenas, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE, Saudi Aramco, Venkateshwaran R
                                                                            Abstract Amorocho, SPE, Saudi an integral part
J. Ricardo Solares, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE, and Ricardo Acid fracturing has beenAramco, and Ve
                                                                            and C. Between December 2003 and February
M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE, Chevron;Abstract Smith, SPE, and A. Saxon, SPE, Schlumb
                                                                            Abstract The Maca� formation (Cretaceous ag
B. Lungwitz, SPE, Schlumberger; R. Hathcock, SPE, K. Koerner, SPE, D. Byrd, SPE, and M. Gresko, SPE, Devon Energy Cor
                                                                            Summary Effective matrix acidizing in Kuwait’
Hai Liu, SPE, Chad Coston, and Mohamed Yassin, SPE, Schlumberger; Shahab Uddin, SPE, Kuwait Gulf Oil Company; and Fa
                                                                            Abstract and Surasak Srisa-ard, Well Services Br
Yin-Chong Yong and Karim Saaikh, Brunei Shell Petroleum; Joao Queiros, Yan Song,Improving oil and gas production from the
                                                                            SPE, and M. Samuel, SPE, Schlumberger
H.A. Nasr-El-Din, SPE, and M. Zabihi, SPE, Saudi Aramco, and S.K. Kelkar,Abstract In treating sour water injectors in carbon
                                                                            Lungershausen, Zhaikmunai LLP; and N.T. is ofte
R. Arangath, SPE, Schlumberger; K.W. Hopkins, Aral Petroleum Capital; D. Abstract Stimulation of carbonate reservoirsBolysp
                                                                            Abstract T. Lindvig and X.W. Qiu, Schlumberger
F.F. Chang, SPE, Schlumberger; H.A. Nasr-El-Din, SPE, Texas A&M University; and Hydrochloric acid is the most commonly u
                                                                            Abstract The Uthmaniyah field is Venkateshwaran
Surajit Haldar, SPE, Ahmed A. Al-Jandal, SPE, Saad M. Al-Driweesh, Mufeed H. Al-Eid, SPE, Saudi Aramco; one of the bigges
                                                                            Abstract The Caballos formation is thick Soler, SP
Rafael Rozo, SPE, and Javier Paez, Petrominerales; Alberto Mendoza, SPE, Ecopetrol; and Arthur Milne, SPE, Diegolaminated
                                                                            Abstract The Orito field in the south of Colombia
Rafael Rozo and Javier Paez, Petrominerales; Alberto Mendoza, Ecopetrol; and Arthur Milne and Diego Soler, Schlumberger w
                                                                            Abstract The purpose of matrix treatments in carb
Frank F. Chang and Xiangdong Qiu, Schlumberger, and Hisham A. Nasr-El-Din, Saudi Aramco
                                                                            Abstract The majority of oil exploited from I. Faizu
D. Oussoltsev, I. Fomin, K.K. Butula, and K. Mullen, SPE, Schlumberger, and A. Gaifullin, A. Ivshin, D. Senchenko, andRussian
Murtaza Ziauddin, SPE, and Emmanuel Bize, SPE, Schlumberger                 Abstract Most carbonate reservoirs are heterogen
L.P. Moore, SPE, and H. Ramakrishnan, SPE, Schlumberger                     Abstract Restimulation of existing wells represents
                                                                            Abstract and based fluids are Petroleum
O. Bustos, Y. Chen, M. Stewart, K. Heiken, and T. Bui, Schlumberger, and P. MuellerCO2 E. Lipinski, Sagacommonly used to f
                                                                            Abstract Historically carbon dioxide
K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V. Nadezhdin, SPE, Schlumberger Well Services (CO2)–foam
                                                                            Abstract Well stimulation techniques
S.A. Utegalyev and S.K. Duzbayev, KazMunaiGas RD, and K. Kulbatyrov and S.V. Nadezhdin, SPE, Schlumbergerlike hydraul
                                                                            Abstract Cheneviere, and condensate drop Samu
Mohan K.R. Panga and�Suzylawati Ismail, Schlumberger Well Services;�Pascal Water blocks Total;�and Mathew out n
                                                                            Abstract Dual completed Redha�Kelkouli, the
Majdi Al Mutawa, Bader Al Matar, SPE, and Abdulaziz Abdulla Dashti, SPE, Kuwait Oil Company, andwells producing fromSPE
                                                                            Abstract Two classes (sonic and ultrasonic) of cem
Douglas Boyd, Salah Al-Kubti, Osama Hamdy Khedr, Naeem Khan, and Kholoud Al-Nayadi, ZADCO; Didier Degouy, ADMA-OP
                                                                            Abstract A new
N.M.A. Rahman, SPE, Schlumberger, and M.S. Santo and L. Mattar, SPE, Fekete Assocs. technique for analyzing and model
                                                                            Abstract Oil Co.; reservoir in the Greater Burgan
A.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi, SPE, KuwaitMauddudand P.-D. Maizeret, SPE, Schlu
                                                                            Abstract
J.F. Manrique, Occidental Oil and Gas Corporation, and B.D. Poe Jr., Schlumberger We present a unique methodology design
                                                                            Abstract Conventional Mohamed Elbadri, GNPOC
Moustafa Eissa, Sameer Joshi, and Kamaljeet Singh, SPE, Schlumberger, and Ajay Bahuguna andpressure transient testing u
K. Slimani, Sonatrach; D. Tiab, U. of Oklahoma; and K. Moncada, SchlumbergerAbstract Often and for many reasons the wellbore
Fikri J. Kuchuk, SPE, Schlumberger                                          Abstract Although it is often used in pressure trans
C. Contreras, SPE, S. Bodwadkar, SPE, and A. Kosmala, SPE, Schlumberger     Abstract Reservoir engineers operating in mature
                                                                            Summary In this work we Blasingame, SPE, Tex
M. Onur, SPE, and M. Cinar,* SPE, Istanbul Technical University; D. Ilk, SPE, P.P Valko, SPE, and T.A.present an investigation
                                                                            Abstract Two Schlumberger (DST) were conduct
                                                                                        Two Case Studies
A.J.G. Carnegie, Schlumberger; Stephen Ball, Premier Oil Vietnam; Pierre-David Maizeret,Drill stem tests Vietnam; and David
                                                                            Abstract The Soodabeh Esmaili and is essential
Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Energy Canada;identification of fracturesMohammad
                                                                            Abstract Exploration and appraisal campaigns for
S. Daungkaew, J.H. Harfoushian, and B. Cheong, Schlumberger; and O. Akinsanmi and J.Yeo, Shell; and S. Toulekima, Santo
                                                                            Abstract This paper presents techniques for interp
N.Karthik Kumar, SPE, Sameer Joshi, SPE and Raj Banerjee, SPE, Schlumberger, K.M.Sundaram, ONGC
                                                                             Pinguet and metering using conventional separat
David Costa; Total ABK, Jean-Paul Couput, Total; Florian Hollaender, BrunoAbstract FlowThomas Koshy; Schlumberger
                                                                            Abstract A number of tests were performed in Yam
B. Theuveny, Schlumberger; I.A. Zinchenko, Yamburggazdobycha Gazprom; Y. Shumakov, Schlumberger
                                                                             SPE, Saudi Aramco, and M.N. Aftab, A. Khan, an
E.J. Pinilla, SPE, C.H. Pardo, SPE, L.M. Warlick, SPE, and Y.M. Al-Shobaili,Abstract Well testing is one of the most effective m
                                                                            Abstract The
Kelechi Isaac Ojukwu, Petroleum Development Oman, and John Edwards, Schlumberger use of multiphase flowmeters (MPFM
                                                                            Abstract Surface welltesting of Gas-Condensate w
B. Theuveny, Y. Shumakov, and A. Zhandin, Schlumberger, and I. Zinchenko, Gazprom
                                                                            Summary Dedicated Smith, flowmeters are now
D.I. Atkinson, Schlumberger Cambridge Research; �. Reksten, 3-Phase Measurements A/S; G.wet-gas Schlumberger; and H
                                                                            Abstract
M. Metwalli Hassan and M. Bekkoucha, ADCO, and M. Abukhader, Schlumberger Production testing using portable Multipha
B.G. Pinguet, G. Roux, and N. Hopman, Schlumberger                          Abstract Using multiphase flowmeters in field oper
                                                                            Abstract The objective of this study SPE, investig
Faisal M. Al-Thawad, SPE, and Jim S. Liu, SPE, Saudi Aramco, and Raj Banerjee, SPE, and Dominic Agyapong,was to Schlum
                                                                            U.
D. Ilk, N. Hosseinpour-Zonoozi, S. Amini, and T.A. Blasingame, Texas A&M Abstract In this work we present the application of
A.F. Veneruso, SPE, and J. Spath, SPE, Schlumberger                         Abstract The pressure derivative has become the
M.-Y. Chen, B. Raghuraman, SPE, I. Bryant, SPE, and M. Supp, Schlumberger   Abstract Two successful field tests of streaming p
  cal storage is about pumping a reactive fluid underground and ensuring it doesn't find a way back to the atmosphere for a very long time –
   an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site Australia where the Cooperative Re
major challenges associated with CO2 geological storage is the performance of the confining system over long timescales. In particular the o
on of greenhouse gas emissions in order to decelerate the global warming process could be achieved through the emerging process of geolo
or CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geolo
  of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from p
fired plants are responsible for the one third of the carbon dioxide (CO2) emissions which thought to be a major contributor to the current ris
  he trapping of CO2 in the subsurface i.e. storage containment is of fundamental importance for a safe geological storage of carbon dioxide.
xide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers
 ¢ is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (then
4/8-A-6 AHT2 was drilled from the Visund Field Floating Production and Drilling Unit (FPDU) in the North Sea and set on production in Octo
  rton Field operated by Maersk Oil North Sea in Block 15/20 has a number of drilling and well placement challenges which hampered develo
 Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineeri
   Formation historically known as the Brown Niagaran is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle reef
on is one of the most efficient methods used to improve oil recovery and as world statistics shows its use has increased recently. Under a h
 ene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick s
 nsate reservoirs usually exhibit complex flow behavior due to the near-wellbore condensate bank build-up when bottomhole pressure drops
esented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project usin
  iscusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and less
 g is a mature field with 8 rounds of field development campaigns and close to 40 years of production. Currently only 50% of total strings are
  n from some of wells in the White Tiger field producing from a fissured Basement reservoir; have been impaired by excessive water product
 wells in Sabriya Field (Northern Kuwait) produce from reservoirs where multiple layers are opened to production. Problems related to non-d
 tacked nature of reservoirs in the Niger Delta the predominant completion types are dual-string multizone and single-string multi-zone comp
 off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horizo
  covery of new fields becoming less common and the continued development of brownfields water control is becoming increasingly essentia
uction is a major problem for any oil and gas field. If not properly managed unwanted water production will seriously impact the economics o
 ol is the key to prolong well life for economical and efficient oil recovery. When water reaches certain levels oil production profitability decrea
 arge potential reserves increased global demand for oil and high oil price exploration & development in deepwater and more challenging ar
mic characteristics of oil/water flow systems have not been understood fully. The need for improved designing methods has led researchers t
  ow is a common occurrence during production and transportation of petroleum fluids through pipes. Understanding of oil/water pipe flow beh
ation of intelligent wells to improve the economics of production is now common practice.�These wells allow the access to marginal reserv
  in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their r
er production systems extreme pressure and temperature conditions multipart sub-sea networks complex reservoir characteristics and var
 nt of deep offshore fields is costly. As such accurate information is required before a decision can be made on the feasibility of prospect dev
xide (CO2) occurrence in hydrocarbon bearing formations presents a challenge to the valuation and subsequent prospect development of the
nt uncertainty in establishing reservoir connectivity has always been an issue for reservoir management. Standard correlation methods using
  precipitation can have profound effects on oil production during miscible flooding heavy oil recovery or even primary depletion. Even though
 id properties are required for studies related to management of gas/condensate reservoirs or prediction of condensate reserves. Often these
hors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. It was shown
n large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir h
cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kalim
cterization quantifies the reservoir phase behavior fluid compositional changes throughout the reservoir and changes in fluid properties as a
 characterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages o
 based mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation t
  escribes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is
    Case Studies
 mation testing provides formation pressures high quality samples and fluid identification/characterization. In addition it can provide informat
 opment projects will rely on producing through existing production facilities which may not have been designed for sour hydrogen sulphide (H
uids frequently reveal complexities in hydrocarbon columns. Fluid compositional grading is usually caused by gravitational forces thermal gra
  and analysis of gas/condensate-fluid samples presents considerable challenges. This is because downhole sampling of a gas/condensate fl
ompartmentalization quantifying connectivity and assessing the presence of compositional grading are critically important to reservoir mana
uid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well know
r presents a case study of a North Sea appraisal well in which a vertical fluid-composition variation missed by a conventional pressure-gradi
epth plots have been used for over thirty years to evaluate fluid density fluid contacts and pressure compartmentalization in formation tester
uids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity capillary and chemical forc
  fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. For example in s
  escribes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional simu
uid analysis (DFA) together with wireline formation testing tools provides real-time measurements of reservoir fluid properties such as comp
ents are common in gas condensate and volatile oil reservoirs but they are also present in heavy oils reservoirs. There are numerous publica
  ears formation-sampling and formation-testing tools have provided a variety of new downhole optical measurements for downhole fluid anal
haracterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages of th
esters are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. Accurate identificatio
describes in detail computational techniques and formulations for constructing a phase envelope and/or subsequent isenthalpic/isothermal fla
nvariably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path stable e
 ive reservoir fluid sampling & characterization has become increasingly important as the exploration activities are moving into the ever-chall
neration of wireline formation testing fluid analyzer presented in this paper integrates in-situ optical fluid analysis device with a oscillating mec
  density-viscosity (D-V) sensor is introduced that provides a real time direct measurement of in-situ density and viscosity at reservoir conditio
 eous carbonate reservoir can be partly evaluated using OH logs but not fully. Even if production testing is used for evaluation important deta
  eration of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels
essure testers and reservoir fluid sampling tools have for quite some time now been considered viable alternatives to well testing. These too
 tive reservoir fluid sampling and characterization has become increasingly important over the years. With exploration appraisal and develop
 well testing has been acknowledged worldwide as a state-of-the-art technology for metering stream of oil gas and water without prior phase
 tion of deep wells is a difficult task mainly because of high reaction rate and the high corrosion rate induced by strong acids. One way to add
cally complex Algyo field discovered in 1965 is the largest hydrocarbon occurrence in Hungary consisting of more than 40 oil-and-gas-bear
matrix acidizing fluids for sandstone are executed in the field only after core tests qualify their ability to remove damage. However most cores
nvestigates the application of halite inhibitors and the mechanisms associated with salt formation and inhibition. Several new chemistries (two
  mation damage with waterflooding using sea/produced water has been widely reported in the North Sea the Gulf of Mexico and the Campos
ate-soap deposition and the related formation damage in petroleum reservoirs are investigated by means of laboratory-scale experimental an
rge perforating subjects the formation to shock-loading and large impact stresses causing damage to the rock surrounding the perforation tu
ompletions perforations provide the essential link between the wellbore and the reservoir. Productivity of the completion is promoted by opti
 lated to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates
ation and accumulation of scale deposits is a major concern for production companies in the Uinta Basin. Since 2003 conventional hydraulic
  hallenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enabl
 ition in completion strings is becoming a threatening problem to produce and safely operate wells completed in the Upper ZAKUM (UZ) oil fie
  m stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium strontium
 ld history matching is generally performed first at the field level then at regional level followed by individual well history matching. This pape
 vancement in streamline simulation technology in modeling fractured reservoir and streamline associated well allocation factors now it can b
discusses the incorporation of Streamline simulation into the Reservoir Management Processes of the super giant Sabriyah oil field. For the
he Gulf of Mexico Cantarell Field is the world’s second largest carbonate field which has been on production since 1979. After the imple
presents the results of an automatic surveillance system implemented by PEMEX for one of Mexico’s largest gas fields.� Activo Integ
  ater flooding has been the preferred pressure maintenance tool for many gulf carbonate reservoirs over the past 30 years. Due to uneven sw
  utlines the successful integration of subsurface water handling well surveillance and production operations teams across the North Kuwait
 onal means of artificial lift production for vertical and deviated wells in the Orinoco oil belt in eastern Venezuela used to be rod pumping and
   Belt (Faja) in Venezuela contains one of the largest resources of heavy and extra-heavy oil in the world. Due to the production decline of co
al EOR methods like steam-injection are usually not cost effective for deep wells and wells producing from thin pay zones due to excessive
   Heavy Oil Belt (Faja) has been exploited under primary recovery techniques using mainly horizontal fishbone and multilateral wells. This co
and development of Heavy oil fields in Muglad Basin in Northern Africa started with conventional vertical wells and as time progressed this m
ene/Eocene age 1st Eocene Reservoir is the shallowest producing interval of Wafra Field in the Partitioned Neutral Zone (PNZ) Saudi Arabia
 mation testers provide the measurements for the determination of formation pressure gradient in-situ effective oil mobility profile in-situ dow
 avy oil field located in Muglad basin in Sudan. Aradeiba reservoir in the field consists of highly heterogeneous sandstone that is thinly bedded
 formation in the Gulf of Suez is highly fractured depleted reservoir producing 9 to 10 API gravity heavy oil at water cuts up to 98%. Stimulatio
 nment With Sand Screen: A Case Study From Kuwait
  ecent hydrocarbon discoveries in the Gulf of Mexico are heavy and extra-heavy oils. Additionally given the imminent decline of lighter crude
 e is to present accurately the performance of the combination of a venturi and multi energy gamma ray in a case study in Venezuela. The foc
  bitumen produced by Steam-Assisted Gravity Drainage (SAGD) induces many issues arising from high operating temperatures (150-200 C)
  cidizing is very challenging because of the complex reactions that occur between the multiple-stage treatment fluids and the formation mine
and fluids evaluation of heterogeneous and over pressured retrograde gas condensate low-permeability but high-reserves potential reservoirs
 has already been undertaken by various operators throughout the industry to explore frontier areas and drill into ever-deeper geological horiz
  ies descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and s
of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.� In certain
of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.� In certain
  ng is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challenging
    Temperature Environment in Mexico Marine
describes an innovative and reliable first� High Pressure High Temperature digital electric permanent monitoring solution with state-of-the
  resents the results of propped fracturing operations conducted in the past 12 years in the Bach Ho (White Tiger) field offshore Vietnam. High
n an oil field in East Venezuela have a bottomhole static temperature of approximately 230�F and varied mineralogical composition from
 ed on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeable
 ge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at
  presents the development of a chemical system for water-block prevention in gas/condensate wells. The chemical system alters the format
describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The techni
ation and deposition of asphaltenic material in reservoir rock are significant problems in the oil industry and can adversely affect the producib
describes an efficient multistage horizontal openhole completion technique as an alternative to conventional openhole or cemented and perfo
 lity Carbonates
and rises and operators turn to tight gas reservoirs for new supplies the need to optimize the capacity and recovery potential from this type o
 ntional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic fracture mapping combined with an in-d
  cture azimuthal orientation depends on stress distribution in the formation and is considered to coincide with the maximal horizontal stress a
nt of gas are being produced from unconventional tight-gas sand reservoirs (e.g. Cotton Valley Fm. Lobo Fm. Taylor Sand Fm. and Wilcox
acture treatments are necessary to ensure the best deliverability of tight gas from east Texas Cotton Valley Sands.� Historically these trea
 lity Tight Gas Formations
ds Limestone in South Texas often requires stimulation to be commercially productive. The relatively low permeability high Young’s Mod
past decade multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it i
 as field in Sichuan Province whose discovery was officially announced by CNPC in August 2005 is a large-scale gas reservoir that has in ex
Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil prod
presents a closed-loop reservoir study in tight gas fluvial sands of the giant Jonah gas field located in the northwestern part of the Greater Gr
 r we will present an integrated single well modeling (SWM) technique to predict reservoir and completion performance for a Uinta basin dev
r presents several workflows for constructing adequate flow models of a tight gas field located in Wyoming. The numerical flow models were
nated tight gas sand sequences remain prolific targets worldwide and have often been bypassed using standard petrophysical analysis and s
                Grained Sandstones
natural fractures in tight carbonate reservoirs during the exploration and early development stages is critical in order to reduce geological unc
mation testing in low permeability carbonate reservoirs of the UAE has been challenging with frequent tool plugging extended pumping time
   the world’s oil and gas reserves are locked in tight “unconventional reservoirs. Without the presence of fractures (natural or hydrau
  covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body conti
  covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body conti
ovided by wireline formation testers (WFT) is critical to the evaluation and understanding of petroleum reservoirs. Pretest pressures gradient
r presents a field-development case study of a low-permeability turbidite reservoir in Russia. The giant Priobskoye field contains 30�API c
   successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal ch
o-Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging exp
 declining production and increasing demand geoscientists are challenged more and more often to develop new techniques and strategies fo
al of tight sands (quartzitic sandstones) makes these non-conventional reservoirs a priority for oil companies during next decades. Due to nu
onate reservoirs several factors make it difficult to estimate reserves in transition zones. In particular underestimation of reserves sometime
uction from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells leading to a co
  n of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts implem
  resents a case history of a slickline propellant stimulation treatment performed in a well at the Penara and North Lukut field which is a small
aking within the petroleum industry is a complex process involving extensive analysis of multiple objectives based on a variety of diverse crite
aking related to oil and gas exploration and production relies on objective data analysis as well on subjective judgment of experts. Expert jud
ve of supplying real time LWD or FE information (Logging While Drilling and Formation Evaluation) should be to enable the client to make qu
essure curves are a fundamental input to reservoir simulators both from the standpoint of initializing fluid saturations and from the perspectiv
   hole logs formation testers pressure transient tests and production logs are usually used to assess reservoir heterogeneity. A common lim
s based on conventional logs are found as strongly correlated to core lithofacies thin section microfacies and petrophysical measurements (
g the depositional sedimentary environment is the most important task for exploration geologists to model the reservoir heterogeneities. Inter
   reservoirs of the eastern Sahara province represent one of the main oil and gas accumulations in Algeria. This clastic succession correspon
  fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal co
  cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kali
hysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However it is difficult to correctly predict th
Tipam sandstone reservoir of Miocene age in the Jaipur oilfield lies within a highly folded and faulted Assam-Shelf basin in the north eastern
ging-while-drilling (LWD) tool that combines traditional measurements of gamma ray propagation resistivity gamma-gamma density and the
e chemical logging sources have been used in the E&P industry for many years to help operators obtain valuable information about their res
 erns have been expressed regarding discrepancies between LWD (Logging-While-Drilling) and WL (Wireline) GR (natural gamma ray) resp
  the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence i
 fying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and he
op concerns for carbonate reservoir evaluation is the effect of rock texture on permeability capillary pressure and relative permeability. Rece
oir is composed of a mixture of dolomite limestone anhydrite and shale interstratified with sandstones member. The sandstone is predomina
 tudy demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex heterogeneo
 turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds.� These
 he perforation intervals and evaluating the productivity of thin-bedded sands and shales is crucial for well completion cost optimization. This
  physical Analysis
 valuation in thin sand-shale lamination seeks first to determine sand resistivity volume fraction and porosity. Afterwards saturation and volu
 on evaluation (FE) of horizontal injectors drilled in water swept reservoirs involves different physical understanding of log responses to fluid f
  ical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydra
mation testing (WFT) and fluid sampling has long been used for determination of reservoir pressure evaluation of fluid type from in-situ dens
  erest in fractures and faults in a giant carbonate oilfield offshore Abu Dhabi involves such aspects as their origin nature orientation and imp
    trapping mechanism plays a critical role for hydrocarbon entrapment within the Middle-Late Cretaceous reservoirs in the Al-Khafji area. 3D
 l Model was built and an Uncertainty Assessment approach was used to better understand the reservoir behaviour. Conceptual models were
  of spatial statistics geostatistics is commonly used to model geologic facies and petrophysical properties. The spatial characteristics of geos
 ed reservoirs are increasingly a target of offshore exploration in the Malay Basin. These reservoirs exhibit heterolithic interbedding with vertic
clear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thin
  al power scenario changes with increased demand for oil and gas remote and challenging (deepwater offshore high pressure-high tempera
   illustrates the improvements in logging while drilling (LWD) images and subsequent formation evaluation by using a new methodology for de
 r Burgan Field consists of three sub fields (Ahmadi Burgan and Magwa). Drilling commenced in this field in 1938 and it went on stream in 19
  on and injection of fluids in a reservoir results in reorientation of stresses. This phenomenon has been supported by field studies and micro-
 anical parameters of reservoir rocks play an extremely important role in solving problems related to almost all operations in oil or gas produc
  leted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling throu
presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized delive
presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized delive
presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized delive
ah Sargelu and Marrat reservoirs are the main Jurassic reservoirs in Kuwait. These fractured-carbonate reservoirs that have moderate-to-lo
 ate reservoirs in Gulf of Suez area have complex geological structure due to the existence of fractures associated with faults. Thus fracture
 ocated in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial o
ring Upper Jurassic Arab reservoirs of an offshore Abu Dhabi fractured carbonate field (Abu Al Bukhoosh) have been producing for more tha
hskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where
     we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity pressure a
s of defining the fluid and reservoir properties of a hydrocarbon discovery represents a significant challenge to the industry. The practice of p
 rmation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over
 asurements have long been used to evaluate rock properties in the near-wellbore region and these methods are well documented. Compreh
  idated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR) in Naturally Fractured Clasti
most important objectives of fluid sampling using wireline formation testers (WFT) is to ensure that representative samples of the different flu
 s of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit lo
  challenge for nuclear magnetic resonance (NMR) well logging is that the quality and utility of the data depend on the acquisition sequence in
  Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent de
  ifferent petrophysical methodologies have been developed to improve the success rate in selecting oil intervals in the Gulf of San Jorge Bas
many of the producers are horizontal wells and a considerable number of them are equipped with smart complex completions. Evaluating the
 odology for porosity and permeability analysis in Carbonates with Inter-granular and Macro porosity is presented. This methodology uses NM
  nced drilling (UBD) is defined as a drilling operation in which the pressure of the circulating drilling fluid is lower than the pore pressure of the
 h structure in southwest corner of Kuwait is a multi reservoir field. One of the potential reservoirs is the Mishrif formation. Developed as a lim
   compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of iden
 ing reservoir architecture is critically important to effective reservoir management. Misinterpreting reservoir compartmentalization for instanc
 ntalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce
  resents the results of an investigation involving the development of a reliable and accurate methodology for establishing the stabilized delive
 estimations are mainly based on special analysis of representative core samples (SCAL). In high recovery oil fields where remaining oil satu
mentary features of gas fields are multilayered deltaic thinly laminated shaly sandstones consisting of channel and bar sands with limited late
 hofacies Mapping
 management requires the optimization of hydraulic fracture placement. The lack of direct stress measurements (vertical distribution and dire
  n of pressure transient tests conducted in a dynamic environment like drilling is challenging. One of the difficulties arises due to phenomen
 eld Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operational
 challenges that operating companies face during any oil field development project is to deal with the uncertainty associated with the data acq
  on declines and watercut increases wells are often converted from gas lift to electrical submersible pumps (ESPs).� ESPs are an attracti
 ew life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has b
dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using appr
 a is blessed with the world’s largest onshore and offshore reservoirs. Currently Saudi Aramco is aggressively pursuing production increm
hin sand bodies while drilling across heterogeneous sandstone reservoir is a major challenge that requires integrated reservoir engineering f
  from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The
 kflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacked
management is a standard industry practice to maximize oil recovery; however in mature fields the full potential is often not realized. Unlike g
  w alternatives to develop and produce sands B1 and B4 together belonging to the reservoir VLG-3729 of Moporo Field located in western V
 gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facility
most common methods of increasing production in oil fields is through the continuous injection of lift gas into the tubing.� The injected gas
 simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio
oil field discovered in 1968 and produced since 1978. With the objective of rejuvenating the asset a multidisciplinary optimization team was b
  tion projects consume considerable amounts of energy to generate steam.�� Understanding where the heat goes at various times and
eservoir studies aim at synergizing all disciplines to form a reservoir understanding and best strategy to field development. Handling uncertain
ve of this paper is to highlight the necessary steps for the successful use of integrated asset modeling. It presents the full workflow for optimz
  technology from reservoir through process facility has advanced so much that field development strategies can be developed within a new
  in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their r
processor cluster computing modular stochastic workflows and a dedicated project team the turn-around time for project execution has been
National Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fie
  on of large volumes of water is common in wells producing from strong aquifer reservoirs such as most of the fields in the Oriente basin of E
 t by limited capacity of 25 MMSCF/D was introduced for Khafji field in 1988 which could successfully sustain target rate until mid of 2004. A
u 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina
  will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate within a one-
 presents a unique workflow for gas reserves evaluation in fields with commingled production from several low permeability reservoirs. The w
   of high demand for rigs and other scarce equipment it may be appropriate and more advantageous for a client to agree to a forward contra
nt describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in de
 exco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in th
   a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we
ment decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downho
 presents an innovative filtering and analysis approach to identify candidates for sidetracking in mature water flooded fields.� It targets bypa
 infill drilling in oil rim reservoirs is a challenging task. In the case of thin oil rims with large gas caps early gas breakthrough and gas cycling
ng the optimal location of wells with the aid of an automated search method can significantly increase a project’s net present value (NPV
mber (SC) control during steam-assisted gravity drainage (SAGD) has a great impact on the efficiency of heavy oil and natural bitumen recov
t a set of new analytical solutions to the single layer reservoir problem both in real time and Laplace space.�The solutions are derived as
new semi-analytical solutions to the multiple layer reservoir problem both in real-time and Laplace space. Assuming a vertically stacked sys
g geologic models to production data is generally done in a Bayesian framework. The commonly used Bayesian formulation and its implemen
hod-based sensitivity for field-scale history matching with large number of parameters suffers from several limitations. First the CPU time de
 bjective is to investigate the use of Artificial Intelligence (AI) methods to accelerate the history matching process. A new criterion for measur
 reasing acceptance of stochastic workflows in mainstream reservoir engineering studies many frameworks have been developed to assist i
presents a novel methodology of history matching using the face recognition technique based on Principal Component Analysis which is cur

e the construction of a general unstructured grid parallel fully-implicit simulator for complex physics associated with heavy oil thermal recove
describes a general formulation for phase-component partitioning that can accommodate any number of phases and components any comp
wells often present a substantial challenge in reservoir simulation. In a recent field review we experienced difficulties modeling long horizonta

  nd multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used to maximi
 tion of Complex Wells (CW) as a component of an optimized field development strategy at single well sector model and or small scale multi
 essure stress state and geological structures as well as their evolution during an oil/gas field life have widespread influence on implications
  -compositional reservoir simulator pressures saturations temperature and compositions in all the existing phases must be solved. When th
ve analysis is a graphical procedure used for analyzing declining production rates and forecasting future performance of oil and gas wells. T
 re-propagation process performed with polymer-based fracturing fluids is applied commonly to increase the productivity of producing wells e
 he substantial tight-gas resources worldwide hydraulic fracturing is for many cases economically a viable option. However despite the sta
wells with multiple fractures are becoming more prevalent in the Industry. They are especially beneficial in carbonate plays where acid and fra
ate reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gas-c
 p is one of the mechanisms that can alter the growth of a hydraulic fracture when it encounters weak planes or natural fractures. In shallow o
   presents explicit simulation of hydraulic fractures in horizontal wells to predict the fracture behaviour and post-fracture production profile le
 ow reduces the productivity of fractured and frac and pack wells and causes erroneous results if ignored when analyzing well test data.1 Cur
 t gas reservoirs are often completed with multiple stages of hydraulic fracturing. Eventually each stage contributes to the commingled well p
presents the results of an investigation concerning the development of more accurate predictive and interpretive models of the boundary-dom
 on of horizontal well technology over the last twenty years has led to the parallel increase of the number of hydraulic fracturing treatments in
  this paper is to investigate the near-wellbore phenomena with respect to fracture initiation. The 2D numerical model was developed which ta
eural networks (ANNs) have been used widely for prediction and classification problems. In particular many methods for building ANNs have
  ture reservoir performance and uncertainties associated a series of reservoir simulation runs are required. It is now a common practice to g
 irs in the Nile Delta of Egypt are characterized vertically by its thin beds of sands and shale and laterally by severe variations in facies. These
r presents a mathematical model describing the variation of temperature along the length of a horizontal well during the process of water inje
es of about 2 cP and above (under downhole conditions) are common and often exhibit poor end-point mobility ratios when displaced by wate
 r we present the results of a material balance study for a mature field in East Malaysia. The field consists of several stacked sands and is hig
 n Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is ava
n objective of the mature fields development optimization is the value adding through extension of field life. While elaborating field developme
nt formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion pres
 arth of easy oil in the industry the importance of consistency in quantifying uncertainties and assessing their impact on investment decisions
ry-saturation function plays an important role in describing fluid distribution and modeling flow in reservoir simulation. In our full field review a
 nvestigates the control volume method with multipoint flux approximation (MPFA) applied to the discetization of –div(K(x)grad u) = f(x) the
 ities of retrograde condensation in the near wellbore region in naturally fractured formation were studied with the use of dual-porosity/dual pe
 ce of vugs in a naturally fractured reservoir can be a significant source of reserves.� These vugs can be connected to the fracture system
 ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistica
 uwait Jurassic Complex consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate formation
 methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculate
 ctured reservoirs can be seen as a set of low permeability matrix rock blocks and a high permeability network of fracture channels. This repr
n reservoir characterization and modeling have given the industry improved ability to build detailed geological models of petroleum reservoirs
models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a particu
 nown PUNQ-S3 reservoir model represents a synthetic problem which was formulated to test the ability of various methods and research gro
 els are becoming more widely used as they can simplify highly complex processes with reasonable accuracy. Especially in risk analysis whe
 ales precipitate in oilfield systems - downhole in the reservoir in the production flow tubing and in surface facilities - because of thermodyna
 ng complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improve
  with conventional vertical wells results in poor vertical sweep efficiency and steam breakthroughs when it is applied to heavy oil reservoirs.ï¿
methods have become an efficient technology for reservoir simulation. The key assumption of the method is that the pressure field can be up
most challenging problems for reservoir simulation is the computation of a multicomponent flow of compressible fluids in porous media with m
 discusses a new workflow to stochastically estimate the performance of infill locations in a mature oil or gas field. Usually performance evalu
  he ensemble Kalman Filter (EnKF) has gained popularity in atmospheric science for the assimilation of data and the assessment of uncertai
  presents a novel approach to analyze the quasi-continuous pressure data for ranking high-resolution geostatistical reservoir models and un
   a model for well inflow control devices (ICDs) that includes the effects of an annulus in which the flow between the ICDs is open or partially
 eservoir simulation still has wide application in the petroleum industry because it is far less demanding computationally than compositional si
Kuwait Jurassic Complex (NKJC) consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate
ock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be
ental study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation damag
   of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia
   carbonate oil-water transition zones contain vast amounts of producible oil. Yet traditional approaches to open-hole formation evaluation o
 m gas field discovered in the Emirate of Dubai (U.A.E.) in 1982 was heralded as a major discovery of its time and to this day still remains
 stability in most of the cases is a direct reflection of earth’s in situ stress state. It is well known that the stress distribution around the we
  summarizes the findings of the SPE Forum held in September 2005 on “Making our Mature Fields Smarter.�Participants in the Forum
 e of the main oil producing country in the world with very long history of the oil industry. In one's time in former Soviet Union a lot of attention
™s North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access to
  ast 10 years several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary proc
  han 20 years of exploitation many of the thick and prolific reservoirs of the Malay basin are depleted. However field studies indicate that lar
  ron measurements have been used since the early 1960s to measure porosity and sigma through casing. Since the formation sigma respon
  e-lapse saturation information is the key to making the right decisions on completion strategy maximizing oil recovery and reducing water cu
ast decade intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizon
 oduction logging tool string and interpretation technique were established in order to solve the surveillance limitations in the short string secti
  ogging and flow profile interpretations are necessary to properly assess completion performance and interpret pressure buildup data in Chay
cation of condensate banking has always been a challenge. Furthermore large productivity losses can result from the absence of early detec
 ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with form
 ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with form
 describes an innovative Down Hole Permanent Monitoring System (PDHMS) that allows real-time monitoring of bottom-hole pressure and te
wnhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions and results are prese
  ing availability of real-time downhole measurements in completions more and more uses of these data are evolving. A deepwater field in the
 e hydraulic fracture treatment was performed on a producing well in a mature tight gas field in West Texas and induced microseismic activity
 ght prediction and evaluation is critical in understanding the effectiveness of a fracturing treatment. Volumetrically fracturing must adhere to
  gnostics of wellbore fluid entry is crucial for the understanding of well performance paramount for reservoir characterization purposes as we
start-up and early operation of horizontal steam assisted gravity drained (SAGD) wells it is important to understand the flow distribution of bit
 addresses some recent developments in a production logging technique that uses Pulsed Neutron log measurements to evaluate the format
  resents some recent developments in a production logging technique that utilizes Pulsed Neutron log measurements for the evaluation of th
 ystems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This paper
 presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower comple
 and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estimat
  entification is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant impact on

 ility of accurate performance information throughout the production system is fundamental to optimization of the economic potential of the re
 ogging low flow rate wells is difficult because mechanical spinners have a small dynamic range in slow moving fluids. Low flow rates in horiz
eservoir has been producing for over 60 years and its pressure has slowly decreased over the years now below saturation pressure in some
 r we present a field example where pressure and distributed temperature measurements enabled understanding of reservoir characteristics
amatic increase in oil prices oil operators are not only concerned about oil production but also they are aiming at the optimum oil production
 reline formation testers (WFTs) are able to collect a massive amount of data at multiple depths thus helping to quantify changes in rock and
 ication of differential depletion in stacked reservoir sands before water or gas breaks through is the key to optimal reservoir drainage. Howe
ation of microseismic and surface-deformation monitoring with an array of tiltmeters was used to monitor the warm-up phase of a steam-assi
oping its Azeri field using deviated gravel-packed sand-screen completions producing from the multilayered Pereriv B C and D reservoirs. R
e of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity drainage an
 ey issues in creating a good reservoir model in carbonate reservoirs is the identification of the horizontal permeability conduits— “thief z
Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters
 ility of accurate production volumes at the well level and throughout the production network is fundamental to the workflows that target the o
  he potential of a producing well requires knowledge of the fluid types and flow rates entering the wellbore. Optimum and accurate determina
presents a novel logging approach used to identify water producing zones while under-balanced drilling (UBD) horizontal wells. This approach
  t of oil recovery and reduction in water-cut in a matured field requires precise time lapse saturation monitoring. Behind casing resistivity an i
e maintenance purpose peripheral wells have been used to inject sea water into a carbonate reservoir offshore Abu Dhabi. The injected wate
    we will briefly review the pilot design and demonstrate the utility of applying the EM imaging to the pilot. We will also show the benefit of the
  cross-well electromagnetic (EM) surveys are used to monitor two types of fluid injection (Water Injection and Water Alternating Gas) in a gia
   Coal Bed Methane (CBM) resources are huge estimated at 3 000 to 9 000 Tcf. The worldwide production from CBM is dominated by US pr
stems comprise the primary flow path within coal bed methane (CBM) reservoirs. These fractures also called as cleats define the reservoir
draulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. How
  tt shale is an unconventional gas reservoir that currently extends over an estimated 54 000 sq miles. In an effort to improve well economics
acturing is the requisite methodology for completing nano-darcy matrix permeability tight gas shales. Commercial success in producing these
  led tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations such as the Horsesh
wells represent a growing percentage of the drilling activity in low permeability reservoirs within the United States.� With effective stimulatio
  ippian Barnett Shale reservoirs have opened a new era for US gas production. Many reservoir characterization efforts have been made and
   2.5 trillion barrels Canada has the world’s largest share of ultra-heavy oil and bitumen resources. While shallow heavy oil reserves are
  Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent deve
 tion from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d which is more than 5% of total U.S. dry gas production. Typically
 al nature of carbonate rocks makes acidizing an effective matrix stimulation technique. Acid dissolves carbonates at high reaction rate to cre
  al Submersible Pump (ESP) a form of artificial lift technology has proven to be a durable solution for delivering the required rates from Sau
or high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves
  ystems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow nat
 hevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled practically all the re
 e northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field hav
od of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sle
  a mature oil field with depleted reservoir pressure supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is loca
presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells t
presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells t
  servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Matri
Minghuazhen is a shallow-water delta-plain sedimentary-deposit reservoir sand in Bohai Bay China. It has relatively heavy oil in place that is
describes a case-study detailing planning completion testing and production of the first Maximum Reservoir Contact (MRC) Multilateral (M
acement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. Histo
r describes a case study that details the planning completion testing and production of the first maximum reservoir contact (MRC) multilate
 r of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir developm
 ing technology is moving towards maximum reservoir contact (MRC) by means of extended-reach horizontal and multilateral wells in all type
of the increasing emphasis on reducing operating costs and minimizing deferred production a new system was designed for perforating well
   statistical methodology using survival analysis (SA) was developed and applied to electrical submersible pump (ESP) system performance d
uring has been a successful method to stimulate the Khuff Carbonate wells of Saudi Arabia since the beginning of the gas development prog
  eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress a
  rizontal lateral Bakken dolomite play began in 1999 in eastern Montana more than 330 wells have been permitted and more than 200 wells
hydraulic fracturing in various risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin as a s
  ng has been part of Saudi Aramco’s gas development strategy to maximize productivity from for vertical wells in the Khuff carbonates ov
describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. P
ds are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs
 y has been conducted on the effect of formation Young’s modulus and in situ stress on hydraulic fracture height containment in layered
 reservoir development continues at a record pace in North America. Additionally reservoir pressure depletion and declining quality of reserve
 elds produce larger quantities of water operators and service companies find themselves challenged with disposing flowback and produced
 he success of a tight-gas field development program in a fluvial environment is to understand the reservoir’s deliverability and what the o
s a pervasively used completion technique in wells targeting high permeability poorly consolidated and depleted sandstone formations locate
  ve pay of the low permeability Ryabchyk formation in the mature fields of Western Siberia is separated from underlying water zones by a we
   years horizontal well technology evolved in the Middle East field development strategies becomes favored over vertical and deviated wells o
n scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not
 ca hasn’t escaped the general industry trend of finding reserves in ever challenging environments. Complex geology and low permeabilit
Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their v
key strategies in Saudi Aramco’s optimum gas development project is drilling single and multilateral wells to achieve maximum reservoir
erations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment emphasis is
d System, Executed from a Supply Vessel; Black Sea Offshore
one of ONGC’s major brownfields discovered in 1983 and located in Gujarat. The Field produces approximately 30 000 bopd and is on d
presents the results of an investigation of the design and analysis of the boundary-dominated flow production performance of a vertically frac
 idespread proliferation micro-seismic fracture mapping it has been observed that some naturally fractured formations exhibit a non planar o
y of hydraulic fracturing work in Russia is being done in the Western Siberian basin where operators and service companies have gathered s
acturing of horizontal wells in shale gas reservoirs is now an established commercially successful technique.� The evolution of the compl
od of completing multiple layer wells has been successfully tested in the Piceance basin for Petrogulf Corporation. This new method placed s
hod of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string
engineers have faced the problem of hydraulic fracturing in soft rock formations for many years. However existing programs used with soft ro
  ic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer addit
 rbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the C
discusses the selection criteria design methodology and analysis of hydraulic fracturing treatments pumped using a solids-free liquid CO2 f
    Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela
 drilling program on North Raguba field in Libya has been suspended since the current well’s performance in this area was not promising
  resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturin
cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit pos
  c hydraulic fracture monitoring is having a major impact in how wells are being completed in tight sand reservoirs.� This existing technolo
 impairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the cha
   errors in the calculated azimuth and other parameters of a monitored fracture can be caused by not performing accurate borehole deviation
 lity Formations
  fracturing treatment fracture conductivity is created by differential etching of the fracture surface by the acid; without nonuniform dissolution
 lization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. Th
 adioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (near
  f our research is on a remote oilfield in western Siberia currently in the initial stages of development. There are two producing horizons of Ju
ere are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs there is still no sim
 s carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a numer
stribution at the tip of a hydraulic fracture is a key element for controlling fracture propagation. In low-permeability formations under downhol
  ght carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular in-situ gelle
presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is
mic imaging of a hydraulic-fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were identi
 wback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Variou
  the propagation of an orthogonal fracture and reopening along the initial fracture during a refracture treatment is studied by taking into accou
al problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from
ooded reservoir hydrocarbon recovery optimization is impacted by well spacing and hydraulic fracture extent. An excessive fracture length m
  summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since th
 s a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors eighteen producers and one g
acturing plays a very important role in these mature and complex geology fields located onshore northeast Brazil – Carm�polis and Siriz
ng the hydraulic fracture path have been observed in mapping of mined fractures and attempts have been made to reproduce their effects on
   auto natural and in-situ gas lift all refer to artificial lift systems that use gas from a gas-bearing formation to gas lift a well. The gas lift gas is
 and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on p
ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tech
ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tech
 horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize re
describes an innovative completion solutions with reservoir monitoring and control completion technologies that allows commingled oil produ
wells are superior in production and recovery to conventional wells however they are subjected to early water coning towards the heel (water
ompletions have been in commercial use for over ten years. Application of intelligent completions technology has evolved from intervention-l
describes an innovative completion solution with state-of-the-art reservoir monitoring and control completion technologies that allows commin
challenges remain in the development of optimized control techniques for intelligent wells particularly with respect to properly incorporating th
 and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandston
essing workflow has been engineered to combine reservoir deliverability defined by production logging (PL) measurements with nodal analy
 of exploration wells continue to escalate we need more than ever to evaluate each well quickly and efficiently to improve the appraisal proce
blems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in deple
own that in cased-hole completions productivity is enhanced by maximizing shaped charge penetration and shot density while minimizing per
on from completion to production often requires the well to be killed immediately after perforation is completed thus exposing the formation t
 g has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and lon
 astern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are
nal Offshore Oil Corporation (CNOOC) Chevron and ENI the field operator are partners in the development of the HZ oil and gas fields op
   an important technique for stimulating production in low-permeability formations and requires special consideration in designing the preced
  lenge identified by ADMA OPCO is the time delay and subsequent lost�production between a well being completed with the drilling rig un
 imates of post perforation damage skin are important for designing remedial solutions and productivity enhancement operations. Underbalan
  coiled tubing (CT) conveyance is used to optimize underbalanced perforating especially for rig-related operations. Well trajectory temperatu
  shaped charge fired from a perforating string or perforating gun will not only perforate its targets but also possibly cause excessive damage
  ivity is driven by establishing a clean connection through the near wellbore zone of drilling and completion induced permeability impairment c
n a series of laboratory flow experiments comparing the productivity of perforations created with reactive liner charges against those created
   productivity is achieved by establishing a clean connection to the wellbore through the near wellbore zone of drilling and completion induced
 co's drilling strategy witnessed a change in the last few years by drilling horizontal and extended reach maximum reservoir contact (MRC) we
s Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation the large percen
  illips is developing the Magnolia field with a tension-leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico.
   the wells reach there economical production limit and are consequently abandoned or mothballed until viable solutions are available to enha
  illips is developing the Magnolia field with a tension leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico.
 s situated in SPDC’s OML 22 in the eastern part of the Niger delta belt some 60kM NW of Port Harcourt. The field discovered in 1986 c
rators have recently launched a new industry-wide initiative on sand control reliability. The aim of the initiative is to gain a better understandin
rend of completion method in offshore reservoirs with sand control requirement is Horizontal Open Hole Gravel Packing (OHGP).� Thoug
Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and ze
 n A-45 located in the Norwegian Sea was completed in an unconsolidated sandstone reservoir that required sand control. The lower zone w
major challenges in underground gas storage wells in Italy is to maximize the sand layers exposure by drilling slanted or sub-horizontal wells
 ravel packing is one of the most popular completion techniques due to its high reliability along with the ability to deliver high-productivity well
 king has routinely been used as a sand control method in open-hole horizontal wells. With the advances in drilling technology in recent years
ajority of the recent deepwater developments in West Africa require sand control applications. Openhole gravel packing is the preferred sand
e gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend
  gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depends
 n oil and gas field located off the Norwegian Coast that is due to be developed with subsea infrastructure tied back to a floating production fa
presents the first installation of nozzle-based passive inflow control devices (ICD) for Apache Corporation in Australasia. This recent technolo
 sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on lo
  for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past incl
ction from the Sarir field became a major concern for AGOCO at the end of the 1980s when ESPs were introduced to the field. The sanding s
presented as SPE�100948 at the 2006 SPE International Oil & Gas Conference and Exhibition in China held in Beijing 5-7 December 200
  escribed a case study involved an investigation in a field in Libya where massive unexplained fill had been reported accompanying obstructi
 only acknowledged in the petroleum industry that water cut increases sand-production risk and a number of possible mechanisms have bee
he stacked reservoirs of the Bokor field offshore Sarawak Malaysia are prone to sand production the field-development team did not opt a
duction of hydrocarbons the formation is subjected to increasing levels of effective stress resulting from the reduction in pore pressure. In
presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Pen
 ic surfactant systems are used in the industry for several applications. Initially the application was focused on low-friction and solids-suspens
 of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture co
an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetrat
ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several yea
 ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye
 ecember 2003 and February 2005 eight wells were stimulated in Tengiz field in Kazakhstan using a viscoelastic diverting acid system to eva
¿½ formation (Cretaceous age Campos Basin Brazil) is predominantly an oolitic and oncolitic grainstone and packstone limestone with a b
matrix acidizing in Kuwait’s horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells ma
 il and gas production from the Brown Fields is now more important than ever to the operating companies as the oil price remains record hig
 our water injectors in carbonate formations in Saudi Arabia sulfide scavenging prevention of sulfur and iron sulfide precipitation is a major
of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is m
   acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However there are two major dr
 iyah field is one of the biggest sub fields and older producing sections in the giant Ghawar structure. A few wells have been dead for sometim
os formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy.�
 ld in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir is th
e of matrix treatments in carbonate reservoirs is to increase connectivity of a formation with the wellbore in the entire zone of interest. Succe
y of oil exploited from Russian oilfields today comes from the Volga-Urals and Western Siberian basin where large-scale fracturing and coile
nate reservoirs are heterogeneous at multiple-length scales.� These heterogeneities strongly influence the outcome of acid stimulation tre
 n of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having highe
fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water t
  carbon dioxide (CO2)–foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation p
 lation techniques like hydraulic fracturing which can involve large financial investments call for a basin- or reservoir-specific approach to m
  s and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trapped
 ted wells producing from the mature carbonate formation in northern Kuwait are encroached by injected water from adjacent wells presentin
   (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO’s standard cement evaluation program. The effecti
 ique for analyzing and modeling the pressure data from both flow and buildup periods in closed chamber tests (CCT) has been developed. It
  servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Matri
   a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled product
  l pressure transient testing using a pressure gauge positioned at a fixed depth in a well has historically been the main source of permeabili
or many reasons the wellbore does not completely penetrate the entire formation yielding a unique early-time pressure behavior. Some of th
 s often used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the petro
 ngineers operating in mature fields across the world struggle to get necessary reservoir data to make their exploitation plans more realistic.ï¿
 k we present an investigation of recent deconvolution methods proposed by von Schroeter et al. (2002 2004) Levitan (2005) and Levitan e

ation of fractures is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant imp
 and appraisal campaigns for deepwater environments are a continuous challenge in today’s operations. Data acquisition in such environ
presents techniques for interpretation of Mini-Drill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOF
ng using conventional separation-based technologies in low-pressure high gas rate environments typical of gas-lifted wells is a very difficult o
 f tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowme
 is one of the most effective means to characterize hydrocarbon reservoirs under dynamic conditions. Such characterization of reservoirs is a
multiphase flowmeters (MPFM) for well test measurements is increasingly becoming a standard practice replacing conventional test separato
 ltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well test
  wet-gas flowmeters are now commercially available for the measurement of gas and liquid flow rates and offer a more compact measureme
esting using portable Multiphase Flow Meters (MPFM) was implemented in ADCO Field “B with objectives to quantify the water and gas p
phase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0
ve of this study was to investigate a workflow where well test data could be used more effectively in history matching of full-field reservoir sim
  we present the application of the β-integral derivative function for the interpretation and analysis of production data. The β-derivative function
re derivative has become the primary interpretation tool for diagnosing well and reservoir behavior. In many situations however the derivative
 sful field tests of streaming potential measurements in oil fields have been carried out: one in a horizontal oil production well and one in a ve
   atmosphere for a very long time – possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) must
   Australia where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. Th
er long timescales. In particular the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage but also b
hrough the emerging process of geological CO2 storage. Also in terms of Enhanced Oil Recovery (EOR) the injection of CO2 as a pure comp
 dertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aqu
missions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D pr
   a major contributor to the current rise in the Earth's surface temperature. Reducing CO2 atmospheric concentrations by capturing emissio
 geological storage of carbon dioxide. During CO2 injection increasing fluid pressure temperature variations and chemical reactions betwee
                                                                                       OnePetro
The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on CO2 Sequestration (Galveston Island Texas Nov. 15-
 stry standards body Energistics (then POSC) in 2005. In November 2006 PRODML Version 1.0 was released. The focus was on production
                                                                                       OnePetro
h Sea and set on production in October 2005. The well was drilled to 9082 m/29796 ft measured depth and has an Along Hole Depth (AHD
 t challenges which hampered development during the 80’s and 90’s when operated by the previous owner. These include formation
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 the successful outcome of engineering efforts to increase extended reach capabilities. MOQ started to develop the Al Shaheen Field offsho
 containing hundreds of pinnacle reefs. These reefs discovered primarily during the 1970s have produced nearly half a billion barrels of prim
 se has increased recently. Under a high crude oil price scenario field applications of enhanced oil recovery (EOR) processes are becoming
 d stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered une
 up when bottomhole pressure drops below the dew point.�Such an accumulation of condensate liquid in the near-wellbore region forms
Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Ven
 escribes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis the paper also addresses the eco
urrently only 50% of total strings are flowing. However the idle wells could possibly access undeveloped marginal reserves in shallow reserv
                                                    OnePetro
 impaired by excessive water production. Excess water not only reduced the artificial lift efficiency but also imposed various damages to the
roduction. Problems related to non-desired water production are drastically affecting the oil production and have been an ongoing concern. T
ne and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field developm
oyed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatable
  ol is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured rese
will seriously impact the economics of a project through lost hydrocarbon production reserves recovery and ever increasing treatment costs.
vels oil production profitability decreases dramatically and even goes to negative. One feasible option in this case is a rigless water shut-off t
   deepwater and more challenging areas around the world have become a key target for the majority of oil and gas Exploration and Productio
 gning methods has led researchers toward its continuous investigation. The objective of this study was to characterize oil/water flow through
 derstanding of oil/water pipe flow behaviors is crucial to many applications including design and operation of flow lines and wells separation
 s allow the access to marginal reservoirs for which dedicated production might not be economic and also accelerate the recovery.�Sen
urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them som
  lex reservoir characteristics and various fluid phases flowing from the reservoir rock to the surface could promote production interruption du
 ade on the feasibility of prospect development. Such sets of information include the reservoir fluid characterization and flow assurance data.
 sequent prospect development of the hydrocarbons. Corrosion is a major concern effecting capital and operational expenditures since the pr
  Standard correlation methods using logs cores and seismic data are sometimes inadequate whereas an extended production test may be
                                                    OnePetro
  even primary depletion. Even though asphaltene precipitation and eventual deposition have been known to have strong effects on permeabi
  of condensate reserves. Often these studies must begin before laboratory data become available or possibly when laboratory data are not a
 d volatile oil reservoirs. It was shown before that MBO could adequately replace compositional simulation in many applications. In this work
A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are kno
  the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer mo
   and changes in fluid properties as a result of production and injection processes. High-quality fluid data are critical for reliable modeling res
aining this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid in
 id samples using wireline formation testers (WFTs). A sound understanding of the physics of OBM filtrate clean-up and identification of first-o
 oved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling reservoir compartmentalization e

n. In addition it can provide information for reserve assessment and producibility estimation. ��� In this paper we present compreh
esigned for sour hydrogen sulphide (H2S) service. This problem is compounded if production is routed to an NGL or GTL facility because eve
                                                  OnePetro
ed by gravitational forces thermal gradients biodegradation active and multiple charging water washing leaky seals and so on. Moreover
 hole sampling of a gas/condensate fluid—unlike its oil counterpart—does not guarantee the retrieval of a single-phase fluid. The same is tr
  critically important to reservoir management particularly in deepwater projects where uncertainties are large and mistakes are costly. Comp
 as condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and tempera
   ed by a conventional pressure-gradient-analysis method was observed in situ in real time by a new fluid-composition analyzer using visible
mpartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments many
 of gravity capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered for instance due
 planning decisions. For example in subsea wells flow assurance is a major concern and formation fluid samples from openhole logging hel
                                                        OnePetro
arrat field using a compositional simulation model with asphaltene modeling facilities.The model enables the simulation of asphaltene precipit
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 servoir fluid properties such as compositions of four or five components/groups and gas/oil ratio (GOR). With the introduction of a new gener
 servoirs. There are numerous publications (Creek 1985 Lars H�ier 2000 Montel 2002 Firoozabadi 1999 Ghorayeb 2003 Fujisawa 2
  easurements for downhole fluid analysis (DFA). DFA involves an in-situ measurement of optical absorption spectra used to compute propert
 ning this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid info
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 ging operations. Accurate identification of the produced fluid usually depends on the analysis of the sample chamber contents at the surface.
  subsequent isenthalpic/isothermal flash calculations that are practical for multiphase fluids in a non-isothermal environment.� These meth
   through the production path stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils
                                                                                         sampling
 tivities are moving into the ever-challenging environment around the world. Proper OnePetro and understanding of the fluid characteristics ha
                                                                                         OnePetro OnePetro
 analysis device with a oscillating mechanical sensor providing downhole density and viscosity measurements in real-time at reservoir conditio
                                                                                         OnePetro
 sity and viscosity at reservoir conditions using a wireline formation tester (WFT). The new fluid measurements are obtained during open-hole
                                                                                         pressure OnePetro
  s used for evaluation important details can often be overlooked such as individualOnePetro behavior of thin laminated sections and/or existe
   ervoir fluids in open hole with levels of filtrate contamination that are in many cases below measurable limits. Also the time required on sta
 alternatives to well testing. These tools are widely used to identify reservoir fluids and obtain representative samples for laboratory analyses.
  h exploration appraisal and development activities moving into marginal fields and more challenging environments accurate fluid characteri
 il gas and water without prior phase separation and provides in many cases much more accurate picture of the transient evolution of flow an
uced by strong acids. One way to address these problems is to use simple organic acids and chelating agents. Unlike HCl the reaction of org
  ng of more than 40 oil-and-gas-bearing layers. The Ap-13 is one of the biggest reservoirs and encompasses a myriad of challenges: it is a d
  move damage. However most cores that are used come from sandstone quarries and the cores are largely clean and undamaged (and not
 hibition. Several new chemistries (two inorganic compounds and one organic nitrogen-based product) have been identified which provide imp
                                                        OnePetro
     the Gulf of Mexico and the Campos Basin in Brazil. The damage is due to the capture of solid/liquid particles by the rock with consequent p
 s of laboratory-scale experimental and theoretical studies. Experiments were carried out in three directions to understand and quantify the na
he rock surrounding the perforation tunnel. This damage can lead to reduced productivity and to an enhanced risk of sand production both o
   f the completion is promoted by optimizing perforation characteristics such as geometry phasing and density but unfortunately it is restrict
    carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability restricts fluid flow in tubing and
n. Since 2003 conventional hydraulic fracturing treatments with scale inhibitor pumped simultaneously as an additive have been offered to th
mising reserves. One of the key enabling technologies in this area is intelligent well completions.�Downhole inflow control devices allow fo
   eted in the Upper ZAKUM (UZ) oil field. Calcite or Calcium Carbonate (CaCO3) scale mostly found in the upper part of the production string
   that may be rich in calcium strontium and barium ions this paper presents evidence for in situ sulphate stripping in a sandstone reservoir.
 dual well history matching. This paper presents a novel methodology for delineating multiple reservoir regions for the purpose of efficient his
  d well allocation factors now it can be used as an effective tool to validate fracture lineament through visualization of streamline-based flow
 uper giant Sabriyah oil field. For the Middle East region streamline simulation has particular significance due to the magnitude of reserves a
  oduction since 1979. After the implementation of Nitrogen injection peak production has reached to more than 2 million stb/d in early 2000s
™s largest gas fields.� Activo Integral Burgos (AIB) is a typical example of large gas field where production declined due to gas-loading bac
    the past 30 years. Due to uneven sweep and pressure distribution this technique has given way to pattern floods in several gulf fields. As th
  ions teams across the North Kuwait asset to significantly improve the operating procedure for waterflooding the Sabiriyah Mauddud field. Th
  ezuela used to be rod pumping and top-drive progressive cavity pumps (PCPs) particularly for wells with production rates ranging from 200
  . Due to the production decline of conventional light crude projects must focus on increasing the recovery of heavy and extra-heavy oils usin
om thin pay zones due to excessive heat loss to the overburden.� For such wells minimizing heat losses can be achieved by using microw
  hbone and multilateral wells. This cold development can only recover between 6% and 9 % of the considerable original oil in place existing in
   wells and as time progressed this matured into drilling of horizontal and high angle wells. Typically drilling challenges in this area include dri
 ed Neutral Zone (PNZ) Saudi Arabia and Kuwait. Characterization of this heavy oil reservoir is challenging due to observed variations in oil v
   fective oil mobility profile in-situ downhole fluids analysis (DFA) as well as taken PVT samples and maintaining them in single phase conditi
 neous sandstone that is thinly bedded unconsolidated bearing typical heavy oil. Bentiu reservoir is composed of massive sandstone uncons
oil at water cuts up to 98%. Stimulation is required to enhance oil production and extend the life of the field. An inherent problem with these w

                                                                                      OnePetro
the imminent decline of lighter crude oil fields such as Cantarell (the primary Mexican oil field) it seems that most of the crude oil production
 n a case study in Venezuela. The focus will be on practical information knowledge sharing to overcome all classical problems due to fluid be
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 operating temperatures (150-200 C) steam presence in the gas phase foaming emulsion and small density differences between bitumen a
atment fluids and the formation minerals. Such reactions are more likely to occur at elevated temperatures and can result in potentially dama
but high-reserves potential reservoirs requires use of advanced formation evaluation techniques. The Achimovskaya formation of Urengoisk
                                                                                      range of 15
drill into ever-deeper geological horizons. High pressures and temperatures in the OnePetro 000 psi and 450-F need to be handled to safe
reasing numbers of deep water and subsea production systems and High-Temperature-High-Pressure (HTHP) reservoir fluids have elevated
                                                   OnePetro
 lic fracturing treatment.� In certain cases excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are to
 lic fracturing treatment.� In certain cases excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are to
dequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is ex

  monitoring solution with state-of-the-art intellitite welded system that allows bottom hole pressure and temperature in real time in JFYN-01 g
 te Tiger) field offshore Vietnam. High temperatures (>275oF) and closure stress (>8 000 psi) combined with the fact that fracturing has to be
 ried mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in th
ations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with mini
  in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with re
he chemical system alters the formation wettability to intermediate gas wet conditions thereby decreasing the capillary forces and enhancing
 mperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a form
                                                      OnePetro
 nd can adversely affect the producibility of a given reservoir. To obtain a fundamental understanding of this phenomenon we have studied th
onal openhole or cemented and perforated lateral completions.� The application focuses on openhole (OH) completions in the Cleveland t

 nd recovery potential from this type of reservoir has risen. In this environment a multidomain integrated process enables the data and activi
 cture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can give a better understanding to the effective
   with the maximal horizontal stress azimuth. The knowledge of the hydraulic fracture orientation is of critical importance in field development
 bo Fm. Taylor Sand Fm. and Wilcox Fm. etc.) and shale gas-bearing formations (e.g Barnett Fayetteville Marcellus Woodford etc.). The
  ley Sands.� Historically these treatments have been performed using a wide variety of techniques using a range of fluids including slick w

   permeability high Young’s Modulus presence of natural fractures minimal stress barriers to control height growth and formation temp
                                                                                          OnePetro OnePetro
 re low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this techn
 rge-scale gas reservoir that has in excess of 100 billion m3 of natural gas reserves. The main sandstone reservoir in the Guang’an field
 rabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As th
e northwestern part of the Greater Green River Basin Wyoming. It produces gas from the micro-darcy fluvial channel sandstones of the Upp
  n performance for a Uinta basin development program. This technique has proven to be vital in the economic success of wells in the Uinta B
 ng. The numerical flow models were built by integrating seismic petrophysical geological and engineering data including hydraulic fracture
 tandard petrophysical analysis and simple porosity cut-off technique. The problem becomes more acute in marginal tight gas reservoirs. The
                                                                                          OnePetro OnePetro
 ical in order to reduce geological uncertainty and determine well trajectory in future horizontal drilling. Challenges are often found in both acq
 ol plugging extended pumping time and multiple trips out of the hole. At the same time there are increasing demands of various types of fo
esence of fractures (natural or hydraulic) these tight reservoirs with matrix permeabilities usually less than 0.1md and porosities between 3-
 ssure depletion and sand body continuity are fundamental to determining the economic viability of these projects. An elusive challenge has b
                                                                                          OnePetro OnePetro
 ssure depletion and sand body continuity are fundamental to determining the economic viability of these projects. An elusive challenge has b
 servoirs. Pretest pressures gradients and mobilities are generally regarded as essential inputs to the reservoir evaluation model. However a
  riobskoye field contains 30�API crude in laminated sandstones of 0.1 to 20 md at a depth of approximately 2 500 m. The complex geolog
 ventional formations such as coal chalk and shale. Conversely few tight-gas-sandstone reservoirs that require stimulation have realized su
m is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity
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elop new techniques and strategies for evaluation and appraisal of increasingly complex and deeper reservoirs. This paper describes the su
                                                   OnePetro
  nies during next decades. Due to numerous formation evaluation challenges in tight sands conventional logging does not allow reliable and
nderestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility of
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 prematurely kill wells leading to a considerable loss in recoverable reserves. In some cases mechanical techniques provide a viable solutio
pment strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate strat
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 nd North Lukut field which is a small oil field operated by PETRONAS Carigali offshore Peninsular Malaysia. The stimulation was performed
  es based on a variety of diverse criteria. As part of the decision-making process companies often convert non-monetary criteria to common
ctive judgment of experts. Expert judgment often considered to be less and accurate than objective data analysis. Nevertheless it is still one
 ld be to enable the client to make quick accurate decisions on the formations being drilled thus reducing and minimizing the geological unc
d saturations and from the perspective of predicting dynamic reservoir behavior. Traditionally this input has been obtained from special core
 servoir heterogeneity. A common limitation of these techniques is that they do not provide two-dimensional spatial information of reservoir ch
s and petrophysical measurements (f/k and MICP) as long as the carbonate pore system remains simple. Once dual porosity is present it is
el the reservoir heterogeneities. Interpretation of borehole images has been the key to better understanding of the sedimentary environment i
  ia. This clastic succession corresponds to fluvial estuarine and shallow marine deposits characterized by common lateral and vertical facies
   properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to
n the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer mo
  ver it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these res
 am-Shelf basin in the north eastern part of India. The analysis of this mature field carries a lot of interest not only because the sands within
 vity gamma-gamma density and thermal-neutron porosity with measurements unique to the LWD arena including neutron capture spectros
   valuable information about their reservoirs. Until recently much of the information obtained using these sources could not be obtained with
                                                                                           OnePetro
  reline) GR (natural gamma ray) responses in various wells. It has been suggested that these differences may arise from the variations in to
 luating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field re
n evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the fi
ssure and relative permeability. Recent advances in log analysis combined with new logging sensors that are sensitive to carbonate rock text
member. The sandstone is predominantly poorly consolidated and quartz rich. Much of the sand is medium grained although coarser sand is
 rom logs in a complex heterogeneous Middle Eastern carbonate reservoir.� The 795 ft conventionally cored interval consists of interbed
   of thin silt and clay beds.� These reservoir sands vary in thickness from millimeter to meters in thickness.� The reservoirs are highly p
                                                                                           OnePetro
 ll completion cost optimization. This requires the accurate identification of hydrocarbon-bearing sands and their contribution to production. R

osity. Afterwards saturation and volume are simple Archie applications. Resistivity anisotropy techniques can provide estimates of sand resis
erstanding of log responses to fluid flow and distribution than that FE of oil producers drilled in dry oil intervals. In reservoirs swept with water
 esence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity low matrix permeabili
 luation of fluid type from in-situ densities identification of fluid contacts and inter-reservoir connectivity. Fluid sampling and downhole forma
eir origin nature orientation and impact on productivity of Lower Cretaceous hydrocarbon reservoirs. Studies identified a conundrum with re
s reservoirs in the Al-Khafji area. 3D seismic data are acquired aiming at to delineate the stratigraphic and possible strati-structural traps and
                                                                                          all of which
  behaviour. Conceptual models were used to constrain the number of realizations OnePetro are equi-probable solutions that honour both h
es. The spatial characteristics of geostatistical methods in variogram kriging and stochastic simulation have made them the tools of choice fo
bit heterolithic interbedding with vertical heterogeneity and a wide range of layer flow properties. This paper describes methods of real-time a
 inations. NMR helps to 1) detect thin beds 2) determine fluid type and if hydrocarbon is present 3) establish the hydrocarbon type and volu
                                                     OnePetro
offshore high pressure-high temperature high-angle wells) locations are drilled in an ever-demanding exploration effort with minimum or no
 n by using a new methodology for depth and survey measurements corrections. LWD depth measurements are often considered inaccurate
                                                      the production comes from a giant oil reservoir in a siliciclastics depositional environment. T
d in 1938 and it went on stream in 1946. Most ofOnePetro
supported by field studies and micro-seismic observations. This paper presents a study of stress reorientation around horizontal wells. Stress
ost all operations in oil or gas production.� A continuous profile of these parameters along the depth is essential to analyze these problem
 erlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accura
  for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements.ï
  for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements.ï
  for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements.ï
e reservoirs that have moderate-to-low porosity were deposited in an inner- to midramp warm marine environment. The fracture systems pla
 ssociated with faults. Thus fracture characterization of this complicated area is very important to understand the reservoir behavior and hen
 ield in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomite
 h) have been producing for more than thirty years. All the available informations indicate that the producing layers subdivided into Upper and
  was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestone
 ng time-lapse resistivity pressure and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure and a pro
nge to the industry. The practice of performing a drill stem test (DST) over a significant reservoir interval and attributing the properties of the
w in East Kalimantan-Indonesia over decades despite technological advances.� One possible reason has been postulated as alteration of
                                                                                          OnePetro
hods are well documented. Comprehensive characterization of the wellbore rock relies on the knowledge of compressional and shear slowne
  (NMR) in Naturally Fractured Clastics Reservoirs of very low porosity (≈ 3.5%) in the Devonian of the Bolivian Sub-Andean reveals infor
 sentative samples of the different fluids encountered in the formation are obtained. Usually the wireline or LWD petrophysical logs will guide
s. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones and high apparent clay content. Calculated
epend on the acquisition sequence inversion parameters and the logging environment. Some modern NMR logging sequences are intended
  technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognize
ntervals in the Gulf of San Jorge Basin oilfields. These methodologies have been successful only in a limited number of cases and a solution
complex completions. Evaluating the performance of these horizontal producers is critically important for improved reservoir management. C
                                                                                       OnePetro
 esented. This methodology uses NMR log data and electrical image data when available to partition porosity into micro meso and macro c
 s lower than the pore pressure of the target formation of interest. The most widely recognized benefit of UBD is the reduction of formation da
Mishrif formation. Developed as a limestone sedimented in a mid-ramp environment it generally consists of fine-grained packstones to wack
                                                                                       OnePetro OnePetro
 opment. Traditional methods of identifying reservoir compartmentalization such as drillstem tests and extended well tests often become im
 oir compartmentalization for instance can result in non-optimal well placement completion strategy and facilities design as well as large er
nalysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory anal
y for establishing the stabilized deliverability performance of multi-layer commingled reservoir systems using multi-rate production log measu
ery oil fields where remaining oil saturations approach residual oil saturations it is possible to test these estimations using Pulsed Neutron D
hannel and bar sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations a

  ements (vertical distribution and direction) in the South Priobskoe field in western Siberia has created the need to determine the orientation a
e difficulties arises due to phenomenon known as supercharging which is caused by mud filtrate invasion. The supercharging results in an in
sensitive to reservoir and operational constraints and uncertainties. This so called “Optioneering process was an iterative multidisciplinar
 ertainty associated with the data acquired in the exploration and appraisal phases which can be ultimately used to forecast reservoir behavio
mps (ESPs).� ESPs are an attractive alternative since they can achieve lower bottom hole flowing pressures.� This can accelerate prod
  most as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide oi
production and efficiency. Using appropriate processes tools and technology production surveillance is able to be conducted in efficient man
gressively pursuing production increment ventures one of the main components being the development of stringers which are present amon
es integrated reservoir engineering formation evaluation geological and geophysical contributions.� The objective of this paper is to exem
  n in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000.�A to
 and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs risks and uncertainties in spite of c
otential is often not realized. Unlike greenfield developments mature oil fields deal with existing infrastructure and fluid export schemes with
 of Moporo Field located in western Venezuela different exploitation schemes were evaluated where intelligent completions have been highl
  ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizatio
 into the tubing.� The injected gas reduces the bottomhole pressure thereby allowing more oil to flow into the well.� The optimal amoun
reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysia
 tidisciplinary optimization team was built. The standard practices for production enhancement opportunities include logging nodal analysis a
                                                       OnePetro
 e the heat goes at various times and places during the process provides the means to improve the performance of a project.�� Enhanc
                                                                                           OnePetro
 ield development. Handling uncertainty and risk using probabilistic approach is a challenge since it becomes quickly overwhelming. This pap
   presents the full workflow for optimzing production and injection cycle times with the help of a simplified reservoir model (SRM) through the
  gies can be developed within a new systematic workflow using existing applications from many E&P departments. Detailed production data
urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them som
  d time for project execution has been significantly reduced.� Using these concepts it is now possible to conduct integrated studies succe
  in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (the
                                                                                           OnePetro
 t of the fields in the Oriente basin of Ecuador and neighboring Mara��n and Putumayo basins in Peru and Colombia respectively. In m
ustain target rate until mid of 2004. Artificial Lift is part of the long term production sustainability solutions for Khafji Field necessitated by the
  roduced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is increas
harged to demonstrate within a one-year time period measurable improvement in well productivity in the Saih Rawl field of Oman. Althoug
 al low permeability reservoirs. The workflow was originally developed for gas reserves evaluation of the Lower Vicksburg (LV) sands and the
   a client to agree to a forward contract for a service to be performed at a future date at some specified price. In this case the service provide
aximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool a latest-generation LW
orizontal section has been drilled in three horizontal production wells all within Palaeocene-aged Balmoral turbidite sandstones below a Sele
egions that are most favorable for well placement.�A technique is developed to apply this method to the problem of field development whe
   operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration informatio
 ater flooded fields.� It targets bypassed reserves to improve production and ultimate recovery from such fields at once.� The method is
 y gas breakthrough and gas cycling can cause serious problems especially in a co-mingled production environment and heterogeneous geo
project’s net present value (NPV) as modeled in a reservoir simulator. This paper has two main contributions: first to determine the effec
f heavy oil and natural bitumen recovery. An optimal production rate and corresponding bottomhole temperature and pressure should be ma
ace.�The solutions are derived assuming a cuboid shaped reservoir using a method of integral transforms.�The method can be applie
e. Assuming a vertically stacked system of layers an analytic solution within each layer can be derived using a method of integral transforms
ayesian formulation and its implementation have difficulties in three major areas particularly for large scale field applications. First the CPU
ral limitations. First the CPU time depends on the data points which are large for any brown fields of long history; second it requires large m
                                                                                    measured OnePetro
 process. A new criterion for measuring the deviation of the simulation model fromOnePetro and /or observed parameters has been introdu
                                                                                    OnePetro
orks have been developed to assist in the history match of reservoir models. This paper describes the application of experimental design and
 al Component Analysis which is currently used in computer vision applications. During history matching the spatial reservoir parameters at g

 ociated with heavy oil thermal recovery. The primary focus of the simulator is on the physics associated with steam injection and Steam Ass
 phases and components any component existing in any phase and requires no special ordering of phases or components. This type of for
ed difficulties modeling long horizontal wells due to the combined complexity of the wells and the reservoir. This reservoir is located in an offs

 ction wells. They are used to maximize the well to reservoir contact and improve oil recovery in a cost efficient manner. This is especially tru
                                                                                         contrast
  ector model and or small scale multi-well level is generally well understood.� In OnePetrothe application modeling and optimization of a fu
                                                      stability
widespread influence on implications for wellboreOnePetrohydraulic fracturing fault-reactivation early water-cut top surface subsidence rese
                                                                                         OnePetro
 ting phases must be solved. When this equation system is solved implicitly a system of nonlinear equations results which is solved by the N
e performance of oil and gas wells. This is achieved by curve fitting the past production performance using the rate-time data and extrapolatin
  the productivity of producing wells especially in tight gas formations. The fracture-cleanup process is complex and may suffer from the pres
able option. However despite the state of the art techniques such as multiple fracturing of horizontal wellbores the gas recovery from these
 n carbonate plays where acid and fracture stimulation can be used to improve productivity the technique can be used for tight reservoirs and
 nd improve the development of gas-condensate field. In recent years numerous research efforts were focused on the developing efficient nu
anes or natural fractures. In shallow or over-pressured formations interfacial slip between formation bedding planes is possible when the effe
nd post-fracture production profile leading to an optimum design and maximum production enhancement. The paper demonstrates the adva
d when analyzing well test data.1 Current practices to quantify the non-Darcy flow effect in a vertically fractured well are mostly based on the
 contributes to the commingled well production. This paper presents a stochastic analytic production analysis technique for multistage hydrau
erpretive models of the boundary-dominated flow performance of vertically fractured wells located in closed rectangularly bounded reservoirs
  of hydraulic fracturing treatments in highly deviated wells. The non colinearity of the wellbore axis and of the fracture plane has initially indu
 erical model was developed which takes into account the interaction of steel casing cement and surrounding rock and allows for a curved p
  any methods for building ANNs have appeared in the last 2 decades. One of the continuing important limitations of using ANNs however is
                                                     OnePetro
  ed. It is now a common practice to generate multi million-cell geological model to capture the heterogeneity details in the reservoir. However
  by severe variations in facies. These challenges in the static modeling have a strong impact in the dynamic modeling which can be summar
  well during the process of water injection. The model is obtained from a theoretical treatment accounting for both mass transfer and heat tra
mobility ratios when displaced by water in fields under waterflood or with active aquifers.This causes a triple hit on the recovery factor: Poor
 s of several stacked sands and is highly faulted resulting in a complex system of several compartmentalized reservoirs. The drive mechanis
ainty. Although some research is available in literature usually the effects of data uncertainty on material balance calculations are rarely cons
 fe. While elaborating field development additions an operating company meets a number of problems falling into two categories: The probl
 orous media. Thermal diffusion pressure diffusion and molecular diffusion are included in the diffusion expression from thermodynamics of
 their impact on investment decisions have become very crucial in management decisions. This has seen the stocks of both experimental de
                                                                                         OnePetro
 ir simulation. In our full field review a systematic procedure was developed to establish a capillary pressure-saturation correlation honoring v
  ation of –div(K(x)grad u) = f(x) the equationdescribing fluid flow through anisotropic porous media. The permeability tensor K(x) is allowed
   with the use of dual-porosity/dual permeability models and the direct numerical simulation based on the “Sugar Cube19 representation o
  be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system.� The modeling of the disp
  stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reservo
                                                                                          at near critical conditions with flow properties ranging from
 actured Jurassic carbonate formation. These reservoirs contain multiple fluid typesOnePetro OnePetro
  because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently streamline simul
 twork of fracture channels. This representation is conventionally described by a dual porosity model which is the one used in the present wo
 gical models of petroleum reservoirs. These models are characterized by complex shapes and structures with discontinuous material proper
  ms; understand behavior of a particular process in a reservoir system and assess impacts of changing input parameters during reservoir m
                                                     OnePetro
  of various methods and research groups to quantify the uncertainty in the prediction of cumulative oil production. Previous results reported o
                                                                                        OnePetro
 uracy. Especially in risk analysis where complex relationships between the uncertainty parameters exist proxy models are used in form of
 ce facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure
                                                     OnePetro
 pment mandate significantly improved and timely work flows for reservoir evaluation. Traditional modeling workflows are typically time consu
                                                     use of horizontal producers provides a larger contact area with the reservoir resulting in a be
  it is applied to heavy oil reservoirs.�� The OnePetro
 d is that the pressure field can be updated relatively less frequently and the saturations can be transported along the streamlines defined by
  essible fluids in porous media with mass exchange between phases. In this work we consider a streamline method for two phase compress
 gas field. Usually performance evaluations for infill wells are conducted using either much generalized statistical methods or numerical simul
 data and the assessment of uncertainty in forecasts for complex large-scale problems. A handful of papers have discussed reservoir charac
 eostatistical reservoir models and uncertainty assessment. Real time monitoring of pressures through permanent down-hole gauges is a re
 etween the ICDs is open or partially obstructed by the presence of packers and we describe the application of this model in a full-field simul
                                                                                        OnePetro
 omputationally than compositional simulation. But a principal limitation of black-oil reservoir simulation is that it does not provide the detailed
aturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types (gas-condensate and volatile oil) at near-critical
 andstone formations is known to be strongly water-wet. In contrast most carbonate reservoir rocks are believed to be mixed-wet or oil-wet to
                                                                                        OnePetro OnePetro
nd its contribution in formation damage. In the study an advanced laboratory test programme was designed after investigation of production
  f the discussion concerns the inertia resistance factor or the so-called beta factor β in the Forchheimer equation and whether the beta factor
   to open-hole formation evaluation often fail to predict how much oil should flow from them or even the location of the free water levels. A t
  s time and to this day still remains the largest onshore gas field in Dubai. This reservoir is characterized by a relatively low-porosity over-pr
  the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and rock
 Smarter.�Participants in the Forum have granted permission to present this paper on the basis that the authors are neither representing
 ormer Soviet Union a lot of attention was paid to oil recovery problems. Unfortunattelly the unfavorable economic climate of the late 1980-s a
 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with both
  cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant mate
                                                                                         lower quality but producible layers. These reserves are t
 owever field studies indicate that large volumes of hydrocarbons remain located inOnePetro
                                                                                        OnePetro OnePetro
  g. Since the formation sigma response is proportional to the salinity of the formation water pulsed neutron measurements are used to deter
 ng oil recovery and reducing water cut. This paper presents a case study from the Bahariya Formation a heterogeneous fluvio-marine chann
  th monobore and multilateral horizontal wells. However a clear understanding of zonal or lateral branch flow contributions still remains an is
 ce limitations in the short string section of the dual completion wells. The logging program was initiated in Kuwait Sabriyah Field where there
 terpret pressure buildup data in Chayvo Field. With a lateral reach in excess of 8 km acquiring production logging data is difficult.� Memo
                                                                                        OnePetro
 esult from the absence of early detection of a condensate bank in the near well bore area of the well. The traditional means of detecting a co
 ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contr
 ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contr
 oring of bottom-hole pressure and temperature of two stacked reservoirs using one vertical observation well in a Saudi Aramco field. Perma
  voir conditions and results are presented for two wells in the Norwegian Sea. The measurement technique for use with wireline formation-s
  are evolving. A deepwater field in the Gulf Of Mexico (GOM) consisting of numerous wells with permanent bottomhole gauges has been on
 as and induced microseismic activity was monitored from a nearby observation well. The objective of this microseismic monitoring campaign
 metrically fracturing must adhere to mass balance equations. Therefore proppant placed in the fracture must be accounted for in the creatio
                                                                                        OnePetro
 voir characterization purposes as well as the key element for identifying remedial action for isolation of unwanted fluid entry. Although multip
 understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood the distribution o
measurements to evaluate the formation inflow into a wellbore in which one or more of the completed intervals may be located in the annulus
 easurements for the evaluation of the formation inflow into a wellbore of which one or more of the completed intervals may be located in the
of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8th inch slickline cabl
  open hole gravel pack lower completion in Enfield field Australia. The principle of the technology involves positioning a number of different t
 ance. Traditional methods of estimating these parameters particularly for real-time detection and diagnosis of production anomalies have be
                                                                                        OnePetro
  nce they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation prope
                                                     OnePetro
  n of the economic potential of the reservoir. Without this understanding a company's field development and operational decisions may not p
 moving fluids. Low flow rates in horizontal wells means the fluid holdups in the stratified flow are very sensitive to the wellbore inclination and
w below saturation pressure in some structurally-high areas where gas cap has increased in size compared to very small initial gas caps in th
 rstanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well. The field example com
  aiming at the optimum oil production. Optimization of an oil producer is not easy as it might seem to be. Moreover oil price increase promo
 lping to quantify changes in rock and fluid properties along the wellbore to define hydraulic flow units and to understand the reservoir archite
 y to optimal reservoir drainage. However hitherto it has not been possible to monitor reservoir pressure changes in individual layers after a w
  the warm-up phase of a steam-assisted-gravity-drainage (SAGD) well pair. A sequence of microseismic events was recorded with signal ch
 red Pereriv B C and D reservoirs. Restricted wellhead access high rates and differential depletion of the different reservoir intervals limit c
g reservoir connectivity drainage and flow assurance. For those wells requiring sand control an additional constraint is that sandface senso
  permeability conduits— “thief zones— if any. In the Sabriyah field in Kuwait dynamic measurements showed evidence of thief zones

  ntal to the workflows that target the optimization of the economic potential of the reservoir. Without an accurate understanding of production
  e. Optimum and accurate determination of multiple phase fluid entry requires two primary measurements: 1) holdup or the cross-sectional a
                                                                                        OnePetro OnePetro
 UBD) horizontal wells. This approach will work in mixed-wet reservoirs and is particularly attractive for mature reservoir undergoing waterfloo
 itoring. Behind casing resistivity an important member of the comprehensive analysis behind casing services suite provides the required an
  fshore Abu Dhabi. The injected water preferentially follows the path of the of higher permeability zones since injection is done into formation
  . We will also show the benefit of the optimized casing material on the resolution of the crosswell EM resistivity images and describe the me
n and Water Alternating Gas) in a giant field in the Middle East. Cross-well EM data will help optimize sweep efficiency identify bypassed pay
 ion from CBM is dominated by US production of 1.6 Bcf/year where an estimated 20 000 wells are in production from CBM reservoirs. Wyom
called as cleats define the reservoir character and fluid flow potential. Cleats are commonly mutually orthogonal and occur perpendicular or
  res for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal sea
  an effort to improve well economics and to reduce the number of surface locations in populated areas the number of wells being drilled and
 mmercial success in producing these reservoirs depends to a large extent on successful hydraulic fracturing.� There is growing evidence
BM) formations such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zones
d States.� With effective stimulation techniques these wells have demonstrated favorable economics compared to vertical wells in the sa
 rization efforts have been made and completion practices established to help understand the Barnett Shale reservoirs. The borehole image i
While shallow heavy oil reserves are extracted from pit mines deeper reserves can only be extracted through wells. Production of these rese
  technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized
 al U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation tr
arbonates at high reaction rate to create flow channels (wormholes"). The high reaction rate often needs to be reduced to allow wormholes to
elivering the required rates from Saudi Aramco fields. Therefore this form of artificial lift was selected to increase production rate from one o
                                                                                          Suncor's
  nada's nonconventional oil reserves are estimated at just over 1 trillion barrels andOnePetro heavy oil reserves in northern Alberta Canada
g and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive research
had been drilled practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a ne
dstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1 400 m. T
a. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding sl
  rizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low laye
 lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the
 lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the
one with “good porosity.� Matrix permeability is low and natural fracture density can be quite variable in this reservoir.� Thus this re
                                                                                         horizontal
has relatively heavy oil in place that is high in viscosity. With the understanding thatOnePetro or multilateral profiled wells are the most favora
ervoir Contact (MRC) Multilateral (ML) and Smart Completion (SC) deployment in Ghawar Field.� The well was drilled and completed as
uids across the reservoir strata. Historically completions with cemented casing packers conformance controlling fluids/gels and selective p
um reservoir contact (MRC) multilateral (ML) and smart completion (SC) deployment in Ghawar Field Saudia Arabia. A well was drilled and
                                                     OnePetro
 ars as part of the reservoir development strategy to maximize well productivity through maximum reservoir contact. Although these wells are
 ontal and multilateral wells in all types and shapes. Horizontal and Multilateral applications become more commonplace to improve the well p
em was designed for perforating wells lifted with electrical submersible pumps (ESPs). The purpose of this project was to develop and apply
e pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modeling
ginning of the gas development program. Various types of acid systems including conventional emulsified and surfactant-based have been u
 along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best c
n permitted and more than 200 wells are now producing. The lateral play began in Richland County Montana and the success there is now a
s in the Western Siberia basin as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydrau
 rtical wells in the Khuff carbonates over the last several years. During acid fracturing the wormholes created by the reaction with the formatio
e largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fractu
d water blocks. As the gas reservoirs being stimulated become tighter the perceived value of these additives has grown. This value must be
acture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controllin
  letion and declining quality of reserves have resulted in escalating drilling completion and workover costs per unit of gas produced. This in
 th disposing flowback and produced water to reduce costs handling the logistics of getting enough water to hydraulically fracture the well as
voir’s deliverability and what the optimum fracture half-length is as a function of geological setting and stress state.� The application an
depleted sandstone formations located in Bachaquero T�a Juana and Lagunillas fields in West Venezuela. This technique combines stim
from underlying water zones by a weak stress barrier. Operating and service companies alike applied various techniques to prevent the brea
red over vertical and deviated wells offering the advantage of maximized reservoir contact higher production rates and better access to rese
 cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter preferen
Complex geology and low permeability are the common denominator in today’s environment. Developing reserves under these conditions
 tain the economic operation of their valuable assets. Large quantities of reserves can be found in low permeability consolidated formations
                                                                                      OnePetro OnePetro
  wells to achieve maximum reservoir contact to maximize well productivity. This strategy has proven very successful over the past few years
                                                   OnePetro
ure. In this environment emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources
                                                   OnePetro
pproximately 30 000 bopd and is on decline. A joint team from ONGC and Schlumberger carried out a rigorous process of candidate selectio
 ction performance of a vertically fractured well located in a closed rectangularly bounded reservoir.� The solution for dimensionless produ
                                                                                      OnePetro
 ed formations exhibit a non planar or complex set of micro seismic events. This fracture mapping technique has provided some valuable ins
d service companies have gathered significant amount of experience and knowledge. The sweeping success of hydraulic fracturing in Weste
 ique.� The evolution of the completion technique has reached the point that numerous stimulation stages through multiple perforation clus
                                                                                      OnePetro OnePetro
orporation. This new method placed sliding sleeve valves in the casing string and completed the well with normal cementing operations. The
ng sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened on
 r existing programs used with soft rock formations often do not provide satisfactory treatment designs. Difficulties emerge because hydrauli
 ons without the use of polymer additives.�VES fluids do not form polymer filter-cake and thus viscous resistance of the fluid flowing thro
                                                                                      OnePetro
  prove the Olmos production in the Caterina SW field in Texas. The reservoir is characterized by thin streaks of pay with potential water pro
mped using a solids-free liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast N

mance in this area was not promising. Well Raguba E-97 in this area was not producing even several attempts such as acidizing re-perforati
                                                                                       OnePetro
 ssful implementation of acid fracturing treatment in Marrat field. The acid fracturing treatment is quite challenging due to presence of high pre
rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed
 eservoirs.� This existing technology is being utilized in new and innovative ways to provide operators a clearer picture of the fracture deve
                                                                                       OnePetro
or this behavior are related to the characteristics of the porous media and are induced as a consequence of the fracturing process. Fracture
rforming accurate borehole deviation surveys for hydraulic fracture monitoring (HFM) and neglecting the effects of the deviating borehole traj

 acid; without nonuniform dissolution along the fracture face the fracture will close after pumping ceases and little lasting conductivity will be
act the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneo
nsight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a number
                                                     with a shale
here are two producing horizons of Jurassic age OnePetro barrier in between them and variable oil/water contact (OWC). Each new well of
 ity oil reservoirs there is still no simple practical production forecasting methodology for hydraulically propped fracturing stimulations for th
  sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells. At the gas velocities
 meability formations under downhole reservoir conditions a severe pressure drop occurs at the tip of the fracture and a lag zone develops d
 of acids such as regular in-situ gelled and emulsified acids have been used in order to achieve optimum fracture length and conductivity. A
hematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and fo
ault. Fracture orientations were identified through a combination of alignment of event locations polarization of the seismic waves and inject
 problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenom
atment is studied by taking into account the production induced stress field surrounding the initial fracture. It is shown that the propagation pr
 nt frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displace
xtent. An excessive fracture length may lead to an earlier than desired increase in water cut. Uncertainty in propped fracture dimension is rela
a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often
ctors eighteen producers and one gas injector to be completed in more than 4 300 ft of water depth. In order to maintain the oil production t
ast Brazil – Carm�polis and Sirizinho Fields – on the revitalization of the oil production. The purpose of this work is to demonstrate the
 n made to reproduce their effects on fracture growth using numerical hydraulic fracture models. Such offsets have long been recognized as
on to gas lift a well. The gas lift gas is produced downhole and bled into the production tubing via an auto gas lift valve designed for gas oper
 six high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulte
rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing ope
rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing ope
hole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary
 ies that allows commingled oil production from multi-laterals wells in Shaybah inside expandable liner.Slim intelligent completions technology
water coning towards the heel (water can breakthrough anywhere in the well not only at the heel due to permeability (K) variation and proxim
ology has evolved from intervention-less completion for sub-sea wells to new applications where intelligent completions are delivering better w
  tion technologies that allows commingled oil production from quad laterals wells in Abqaiq field. Many intelligent completions wells have bee
  h respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if
w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on hy
  PL) measurements with nodal analysis evaluation. This allows the effects of various completion modifications to be quantitatively modeled
                                                                                          OnePetro
ciently to improve the appraisal process and avoid unnecessary expenditure. At the same time an accurate reservoir characterization is the k
ally coincide with an increase in depletion water cut or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is d
  nd shot density while minimizing perforation damage.� However in tight carbonate reservoirs creating deep and clean perforations may s
 pleted thus exposing the formation to potentially damaging kill fluid. To obtain a perforation tunnel with maximum productivity this transition
  in intervening highly deviated and long section of horizontal wells under live condition where slickline and E-line have difficulties. This pape
District. Its main productive zones are the Merecure and San Juan formations which are sandstones characterized by their high permeabilitie
pment of the HZ oil and gas fields operating as the CACT Operators Group (CACT) in the South China Sea. The HZ fields are stacked thin
 onsideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress known as
  ing completed with the drilling rig until it is acid�stimulated using a multi purpose barge and put on production. Some wells in�ADMA O
enhancement operations. Underbalanced perforating (UBP) which is widely used in well completions induces transient fluid flow that provide
operations. Well trajectory temperatures and fluids can create uncertainties on both depth control and the accuracy of hydrostatic cushion b
so possibly cause excessive damage or swell to its carrier. Comprehensive understanding of the post-perforating conditions of the perforator
on induced permeability impairment commonly referred to as the “near wellbore damaged zone. This connection through the damaged zo
                                                                                          OnePetro
   liner charges against those created with conventional liner charges. Three of the tests involved shots into an outcrop carbonate rock called
 ne of drilling and completion induced permeability impairment commonly referred to as the “near wellbore damaged zone. This connectio
maximum reservoir contact (MRC) wells. One of the objectives behind this strategy is to improve the well productivity by maximizing oil produ
  ation consolidation the large percentage of fines present in the reservoir the heavy oil the low frac gradients the low net-to-gross ratio the
 nks Block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50–60� maximum hole a
 viable solutions are available to enhance there production to an economically feasible level. The Hawtah field (see Figure 1) discovered in th
 nks Block 783 in the Gulf of Mexico. The wells produce primarily from thick fine-grained Pleistocene reservoirs. Because of the long lengths
  court. The field discovered in 1986 currently has 9 wells completed and 13 drainage points. Well A-4L is one of the completed intervals on t
                                                                                            equipment
  ative is to gain a better understanding of Sand Control Completion (SCC) systemsOnePetro performance and reliability in a variety of app
  Gravel Packing (OHGP).� Though gravel packing is a proven method to stabilize the well bore controlling sand and maximizing productiv
 eved complete annular packs and zero mechanical skin factors resulting in well productivity indices that are significantly greater than expect
                                                       OnePetro
quired sand control. The lower zone was completed with a gravel pack completion and the upper zone was left unperforated. To enable produ
 rilling slanted or sub-horizontal wells through several shale bodies to obtain high gas rate performances during the production and the injecti
ability to deliver high-productivity wells. Currently there are two techniques used for gravel placement one utilizing low-viscosity carrier fluids
   in drilling technology in recent years horizontal wells with lengths ranging from 2 000 to 6 000 ft have become more common. Executing the
e gravel packing is the preferred sand control technique adopted by many operators in this region. It is considered one of the proven method
a cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and th
   cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and th
e tied back to a floating production facility. Nine horizontal oil producers and four S-shaped gas producers are planned and all will require som
 n in Australasia. This recent technology was simultaneously applied in a production well and a water injection well and served as a demonst
 minating the need to have a rig on location. To date six screenless completions have been performed for a major operator in the Gulf of Me
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  have been proposed in the past including various solutions based on permeable cement but none of them have made a real breakthrough.
 introduced to the field. The sanding severely impaired the performance of field and consequently led to significant economic loss. AGOCO
na held in Beijing 5-7 December 2006. Abstract Sand production is a major concern for many operators. It can impact production cause er
een reported accompanying obstruction of production for majority of production wells since the onset of production indicating possible sandin
 er of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed at
                                                                                          OnePetro
 field-development team did not opt a priori for gravel packs in every well. While such completions can indeed eliminate sanding risk the team
m the reduction in pore pressure. In weak but consolidated sandstones this can lead to shear failure in the rock surrounding the perforation
eld gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and t
 ed on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years the application of viscoe
 e laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of
 oir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of p
   carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin
  f carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin
coelastic diverting acid system to evaluate the effectiveness of this system in achieving diversion and zonal coverage in large limestone res
 ne and packstone limestone with a bottomhole static temperature (BHST) of about 150�F. The formation permeability often exceeds one
   the length of the horizontal wells make acid placement and diversion difficult particularly in high-water-cut (WC) wells in which water has br
 s as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low
                                                                                       OnePetro
d iron sulfide precipitation is a major requirement during acidizing treatments. �As the acid spends on the carbonate surfaces and in the p
n 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity damage to each zone matrix mine
wer. However there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction ra
 ew wells have been dead for sometimes due to high water cut (60 to 80%). In all cases the target interval was only 5’-10’ at the top o
                                                                                       OnePetro
                                                                                       OnePetro
m 20 mD to as high as one Darcy.� However the production from this formation is often limited due to the low critical flow rate in the matrix
 then. The most prolific reservoir is the Caballos Formation a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft th
   in the entire zone of interest. Successful matrix treatments depend on the uniform distribution of the treating fluid over the entire interval. W
where large-scale fracturing and coiled tubing operations have been on-going for the past six years.� In the mainly brown fields tertiary rec
 e the outcome of acid stimulation treatments which are routinely performed to improve well productivity.� However most previous studies
   that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Re
ons that are more sensitive to water treatments (high capillary pressure swelling clays etc). In particular the Frontier Formation located in Bi
 yoming—due to the low formation permeability and rock properties—and have been proven effective but still not perfect. Limitations on th
 - or reservoir-specific approach to maximize production. Integrated solutions use a performance-based process that integrates petrophysic
                                                                                       OnePetro
e liquid (water/condensate) is trapped near the wellbore due to strong capillary forces and/or viscous fingering of gas through the liquid. To re
   water from adjacent wells presenting a challenge for the operating company. Greater oil demand coupled with limited surface water handlin
 ment evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacement
 r tests (CCT) has been developed. It can be used for estimating the key reservoir parameters such as reservoir pressure permeability and s
one with “good porosity.� Matrix permeability is low and natural fracture density can be variable in this reservoir.� Thus this reservo
 eservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses and uses historical pro
   been the main source of permeability and skin estimation in formations. However if a well is completed as a multi-layer commingled produc
y-time pressure behavior. Some of the main reasons for partial penetration in both fractured and unfractured formations are to prevent or de
 e is no standard definition in the petroleum literature. The pressure diffusion corresponds to an instantaneous propagation of the pressure sig
 eir exploitation plans more realistic.� Pressure transients are the most effective way to understand the dynamic behavior of the reservoir.ï
  2004) Levitan (2005) and Levitan et al. (2006) and Ilk et al. (2006a b). These works offer new solution methods to the long-standing decon

 oirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation
 ons. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be
solute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous w
  of gas-lifted wells is a very difficult operation. Owing to low retention times of the gas the quality of separation and existing instrumentation i
 e performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of wi
                                                                                          It is therefore essential to have accurate measurements
uch characterization of reservoirs is as accurate as the data used for interpretation.OnePetro
e replacing conventional test separators. These MPFMs are usually tested and calibrated in laboratory controlled flow loops using idealized fl
 tering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. How
nd offer a more compact measurement solution than does the traditional separator approach. The interpretation models of traditional multiph
 ctives to quantify the water and gas production evaluate the performance of slugging/intermittent wells for procurement actions evaluate the
  of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (92
ory matching of full-field reservoir simulation models and also in situations where existing simulation models could be used in well test interpr
 uction data. The β-derivative function was recently proposed for the analysis and interpretation of pressure transient data [Hosseinpour-Zono
any situations however the derivative of the measured pressure data is uninterpretable or worse misinterpreted because of various artifacts
 al oil production well and one in a vertical water injection well. Pressure transients were created and the streaming potentials generated by th
ns (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 s
arge-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assumed
 eat the purpose of storage but also badly affect human health or the environment. Indeed cement degradation and casing corrosion in injec
  the injection of CO2 as a pure component or as part of a mixture has proved to increase the productivity of oil and gas reservoirs. Optimiza
 the storage reservoirs are saline aquifers exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2-
 e. The CO2SINK project is a R&D project mainly supported by the European commission the German Federal Ministry of Education and R
c concentrations by capturing emissions at the source—power plants or chemical units—and then storing them in subsurface reservoirs is
 ions and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Beside


 and has an Along Hole Depth (AHD) reach of 7593 m/24911 ft which is a world record for Extended Reach Drilling (ERD) from a floating in
vious owner. These include formation instability directional-drilling control issues and thin complex reservoirs which are poorly imaged on sei

 ed nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the so
very (EOR) processes are becoming economic in today’s environment. The natural CO2 sources come to be an excellent opportunity be
are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences alon
 d in the near-wellbore region forms a ring that may significantly reduce the gas relative permeability and consequently the well productivity.
 r characteristics from an eastern Venezuela formation. Due to the complexity and number of variables involved in the process SAGD prese
sis the paper also addresses the economic value of the campaign. Oil production from this field with complex geology and reservoir mechan

 so imposed various damages to the oil zones. Since 2002 a joint industrial project was set up to study the feasibility of performing water shu
 nd have been an ongoing concern. The exclusion of this water represents a challenging task by itself especially in case of multiple zones int
  infill wells required for field development. However they come with a disadvantage in regard to carrying out a successful intervention when
ssfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8 open hole at 10 600 ft at 88 � and capping it with cement and gel usi
 challenging in under-pressured reservoirs with openhole completions such as in the Boscan field in West Venezuela. Gravel-packed slotted
and ever increasing treatment costs. It may cause major economic and operational problems for several reasons. It requires increased capa
  this case is a rigless water shut-off treatment which involves an intensive process starting from candidate selection and finishing with post-
oil and gas Exploration and Production Companies. Development activities in the deepwater face significant challenges.� Of particular con
 o characterize oil/water flow through experimental data. The tests were conducted in a 2-in. horizontal test section using tap water and mine
 n of flow lines and wells separation and interpretation of production logs. In this study the oil/water pipe flow was experimentally investigate
also accelerate the recovery.�Sensors flow-control and other devices can be used to manage the production from the commingled reser
 ited coordination between them sometimes bypassing important considerations from other components of the overall production system ou
 d promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene wax and hydrates anywher
 cterization and flow assurance data. The subject of this paper is to demonstrate the importance of accurate and representative fluid characte
operational expenditures since the presence of CO2 can cause corrosion failures. Carbon dioxide also denotes an issue for health safety an
an extended production test may be too expensive or non feasible. Increasingly geochemical techniques are being deployed to determine re

 ssibly when laboratory data are not available. Correlations to estimate values of these properties have been developed that are based solely
 n in many applications. In this work a new set of MBO PVT correlations was developed. The four PVT functions (oil-gas ratio Rv solution g
tational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension but which had not been well characterized in the labo
 with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perforatio
 are critical for reliable modeling reservoir-engineering calculations and performance predictions and for subsequent economic analysis. Co
 g and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperatu
te clean-up and identification of first-order impact parameters is of paramount importance for the design of new generation WFT probes that
ing reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new fluid identification sensors

½ In this paper we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in w
o an NGL or GTL facility because even a tiny amount of H2S may dictate a prohibitively expensive upgrade. Detecting the presence of H2S
 f a single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality t
 arge and mistakes are costly. Compositional grading has been known for over 50 years but the topic received little attention until the 1980â€
  The reservoir pressure and temperature in such reservoirs are very close to the critical point and therefore small changes in reservoir cond
d-composition analyzer using visible near-infrared (NIR) spectroscopy. For optimal oil production assessing the spatial variation of fluid prop
shore deepwater environments many reservoirs are multilayered and highly variable in terms of connectivity permeability and fluid properties
e also encountered for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a g
d samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a formation fluid sa


   1999 Ghorayeb 2003 Fujisawa 2004 Elshahawi 2005 and Kabir 2006) that have dealt with complex fluid columns showing composition
 tion spectra used to compute properties such as hydrocarbon composition and gas/oil ratio (GOR). Abrupt changes in these fluid properties
  and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperature

 hermal environment.� These methods were designed especially for heavy oil applications and use in numerical simulators.� The metho
 t during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases in which submersible pumps are u




  limits. Also the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling method
 ive samples for laboratory analyses. In order to recover uncontaminated samples fluid is first pumped out of the formation into the wellbore
vironments accurate fluid characterization becomes more critical. This can be said for the formation tester DST and multiphase sampling a
re of the transient evolution of flow and more accurate picture of the volumes and rates especially in cases of condensate and heavy oil envir
 gents. Unlike HCl the reaction of organic acids with calcite is reversible and the reaction products can precipitate at certain conditions. The
asses a myriad of challenges: it is a depleted (180 bars reservoir pressure at 2400 m) layered dirty sandstone reservoir with a low permeabili
 gely clean and undamaged (and not representative of the sandstone conditions in actual producing wells). This study proposes novel applica
ave been identified which provide improved halite inhibition. Their inhibition performance was studied and compared with commercially availa

ons to understand and quantify the naphthenate-soap-deposition problem. Static bottle tests were conducted to determine the precipitation ra
  nced risk of sand production both of which are undesirable. The impact stresses fracture sand grains in the vicinity of the perforation tunnel
  ensity but unfortunately it is restricted by the perforation damage zone—a region of low permeability material surrounding the perforation
 bility restricts fluid flow in tubing and perforation fails electric submersible and rod pumps and plugs surface equipment. Local industry offe
 s an additive have been offered to this region. This service proved to be very effective in the Permian Basin using borate crosslinked fracturi
wnhole inflow control devices allow for the flexible operation of non-conventional wells.� By placing sensors and control valves at the rese
  e upper part of the production string and Celestite or Strontium Sulphate (SrSO4) mostly found in the lower part of the production string are
 e stripping in a sandstone reservoir.�The formation brine composition suggests that a moderate to severe barite scaling tendency will req
egions for the purpose of efficient history matching. Ideally the regions in a reservoir should be independent in terms of their effect on the ob
 sualization of streamline-based flow pattern and injection allocation between each injector and producers. Such capability has made streaml
 e due to the magnitude of reserves and scale of development.� Streamline simulation brings immediate added value due to its ability to h
 re than 2 million stb/d in early 2000s. Field is now on decline and currently one of the major challenges is to monitor the advancing fluid leve
ction declined due to gas-loading backpressure and reduced permeability in the target formation. The fast decline of the gas wells during the
 ern floods in several gulf fields. As these new floods are established it is important to understand the water saturation between wells to prop
ding the Sabiriyah Mauddud field. This effort required a new way of managing this reservoir in NK: a multifaceted approach of balancing void
 h production rates ranging from 200 to 600 barrels of oil per day (BOPD) of extra-heavy oil (8�API gravity and viscosities of 2 000 cp at a
  ry of heavy and extra-heavy oils using thermal and non-thermal methods. Steam-based thermal recovery processes are more efficient in low
 ses can be achieved by using microwave heating assisted gravity drainage.� In this study the feasibility of this method was investigated.ï¿
 derable original oil in place existing in the area. Owing to the high viscosities widely different formation thicknesses and heterogeneities foun
 ng challenges in this area include drilling of very reactive shale’s shallow kick off depths and high build rates. Unconsolidated sandstone
  ng due to observed variations in oil viscosity heterogeneity related to complex mineralogy a possible dual porosity system and the presenc
 ntaining them in single phase condition for lab analysis interval pressure transient testing (IPTT) for characterizing of permeability anisotropy
 posed of massive sandstone unconsolidated and traped very high viscous oil. Production performance of vertical wells indicates that the res
eld. An inherent problem with these wells is poor acid placement during matrix acidizing especially in reservoirs with high-permeability contra


 all classical problems due to fluid behavior met by multiphase metering device in extra heavy oil including classical separator. Heavy and E

es and can result in potentially damaging precipitation reactions. In conventional acid treatments fluid is usually pumped in multiple stages o
chimovskaya formation of Urengoiskoe field is one of Russia’s giant low-permeability gas condensate fields. The main objectives of the p

 HTHP) reservoir fluids have elevated the importance of fluid properties. Like rock properties fluid properties can vary significantly both aeria

result in friction pressures that are too high and may prohibit the treatment from achieving the design goals.� With titanium (Ti) or zirconiu
these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing ad

emperature in real time in JFYN-01 gas well. Permanent down hole system provide bottom hole pressures and temperatures during the prod
 with the fact that fracturing has to be performed from a vessel make the execution of fracturing treatments operationally difficult and challen
le damage have been reported in these wells. Currently various formulations of mud acids organics acids and solvents are used to treat t
 metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149�C) sandstone reservoirs in a
uire continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable r
 g the capillary forces and enhancing the clean up of trapped water at low drawdown pressures. Five different chemicals (A1-A5) are evalua
water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water ch

e (OH) completions in the Cleveland tight gas sand of the Texas panhandle. Horizontal wells have been drilled extensively in this low permea

d process enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular and
   better understanding to the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region w
  ical importance in field development planning including well spacing pattern water injectors location that will lead to desired line drive mech
 ville Marcellus Woodford etc.). These plays are partly technology driven and partly economics driven. Modern well log evaluation technique
 ing a range of fluids including slick water linear gel crosslinked polymers and CO2 emulsions. Most of the productive sands are associated


easons for the success of this technique vary but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing as
e reservoir in the Guang’an field Xujiahe formation mainly consists of Xu-2 Xu-4 and Xu-6 formation. The lithology of the Xu-6 formatio
 been produced within the PNZ. As the fields mature the easy produced oil in the high permeability intervals is diminished by increasing wate
uvial channel sandstones of the Upper Cretaceous Lance Formation after multistage hydraulic fracturing. Single sand body pay zones would
nomic success of wells in the Uinta Basin.� The integrated SWM involves the development of a petrophysical and a mechanical stress mo
ing data including hydraulic fracture data. The reservoirs consist of several sand units over a gross thickness of 4 000 ft in a fluvial depositio
 in marginal tight gas reservoirs. The high cost of hydraulic fracturing increases the need for an effective and useable petrophysical model fo

hallenges are often found in both acquiring the adequate data and assessment of the fractures/sub-seismic faults in the oil based mud boreh
asing demands of various types of formation testing measurements to satisfy various reservoir evaluation objectives. Thus the complexity of
 an 0.1md and porosities between 3-10PU do not produce commercially. While hydraulic fracturing is widely used to improve the economic v
 projects. An elusive challenge has been to gather fit for purpose pressure data in these tight formations due to the nature of the rock and th

servoir evaluation model. However acquiring this data in low permeability reservoirs can prove challenging. There is no stable flowing press
mately 2 500 m. The complex geology lack of reservoir information and lack of technology availability caused a 20-year gap between discove
 require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of no
ates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospe


ted. The measurement of mobility of the different phases throughout the transition zone which is affected significantly by complex rock heter

edium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This
 ert non-monetary criteria to common monetary equivalents i.e. assigning costs allocations regarding public response to a proposed project.
  analysis. Nevertheless it is still one of the most common ways in which decisions are made in the petroleum company. By improving judgme
 g and minimizing the geological uncertainty and maximizing or increasing the well bore exposure in the desired structure.� During the cou
has been obtained from special core analysis (SCAL) from a limited amount of cores due to time and cost. Rock typing is often used to help m
 nal spatial information of reservoir characteristics. For example cores and logs have excellent vertical resolutions but very small lateral radi
 e. Once dual porosity is present it is found that neural network using conventional logs can not distinguish 2 rock types having the same ran
 ing of the sedimentary environment in the study area in Krishna-Godavari basin (KG basin) along the east coast of India. The present study
by common lateral and vertical facies changes that are responsible for uncertainties in the modeling of the reservoir heterogeneities. A realis
 oir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from convent
d with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perforati
nt flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diage
st not only because the sands within the formation are hydrocarbon bearing but also because of the complexities associated with its evaluatio
 a including neutron capture spectroscopy and capture cross section opens up new opportunities for formation evaluation on LWD. The com
e sources could not be obtained with any other method. While the potential risks involved with the use of such sources have always been k

urface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent net rese
 nd surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent ne
 t are sensitive to carbonate rock texture have led to an improved workflow for petrophysical analysis of carbonates. The authors have earlier
 m grained although coarser sand is common in the lowermost thick sandstone units. Both anhydrite and carbonate cements are present wit
 ly cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures.� In some
ness.� The reservoirs are highly permeable but the silt and clay laminations affect the reservoir permeability in each layer resulting in cha


 s can provide estimates of sand resistivity and volume fraction but good results depend on the choice of the anisotropic shale point. The sam
ervals. In reservoirs swept with water effects of rock electrical anisotropy on logging-while-drilling (LWD) apparent resistivity measurements
 e low porosity low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits. Fracture corridors and
  Fluid sampling and downhole formation fluid analysis measurements also provide information for assessment of fluid complexity compositio
 tudies identified a conundrum with respect to core and image log correlation of discontinuities: fractures and faults seen on electrical image
nd possible strati-structural traps and their associated reservoir setting. Seismic attribute analysis of 350 sq. km. of 3D seismic data of Al-Kha

 ave made them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize the reservoir connectivity an
per describes methods of real-time and high-resolution formation evaluation and formation testing used to characterize such reservoirs. The
ablish the hydrocarbon type and volume and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale system

ments are often considered inaccurate and therefore not as reliable for well-to-well correlations correlations with data acquired with wireline

 tation around horizontal wells. Stress reorientation has been calculated for different scenarios and patterns of horizontal injection and produc
s essential to analyze these problems which include wellbore stability sand production fracturing reservoir compaction and surface subside
g-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling proble
-rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis of
-rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis of
-rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis of
  vironment. The fracture systems play a significant role in production in these reservoirs and it is essential to identify areas of high fracture d
stand the reservoir behavior and hence assigning the best completion intervals for the producing wells. In this paper we developed a workflo
sts mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of
 ing layers subdivided into Upper and Lower Arab are fractured to varying extents. As a result a better understanding of the fracture networ
eservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir
 Array (ERA) and pressure and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experim
  and attributing the properties of the produced fluid to a single reservoir fluid compartment is problematic. Overlooking the variation in fluid pr
  has been postulated as alteration of near-wellbore formation properties during drilling operations.� The relatively tight gas sands are drille
 e Bolivian Sub-Andean reveals information till now incoherent compared with core data. As it is well known when the rock does not have pa
or LWD petrophysical logs will guide the sample acquisition program. This typically means that resistivity and nuclear logs are used to infer b
 gh apparent clay content. Calculated water saturations are high and need to be accurately split between clay-bound capillary-bound and fre
NMR logging sequences are intended to be applicable over a wide range of environments and include measurements of transverse relaxatio
 sed. Written by individuals recognized to be experts in the area these articles provide key references to more definitive work and present s
mited number of cases and a solution that has field-wide applicability has been lacking. This project attempts to optimize previous results usin
  improved reservoir management. Conventional production logging tools cannot meet the challenges of logging horizontal wells especially in

  UBD is the reduction of formation damage by minimizing the drilling-mud leakoff and fines migration into the formation. It also facilitates the
 ts of fine-grained packstones to wackstones that is highly bioturbated. The average thickness is about 300 ft with an average Net of 170ft in

nd facilities design as well as large errors in reserves drainage volume and production rate predictions. Downhole fluid analysis along with co
DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This pr
sing multi-rate production log measurements. Both linear and non-linear systems are considered in this work providing a basis for the analys
 estimations using Pulsed Neutron Decay (PND) logging to monitor water saturation changes. Such monitoring techniques can identify incon
og data and performing correlations among nearby wells proved to be inconclusive in identifying gas reservoirs owing to their thin beds high

  e need to determine the orientation and magnitude of the least principal stress. The presence of impermeable shales between producing sa
n. The supercharging results in an increase in sandface pressure which is above the reservoir pressure. Therefore any calculation of initial p
cess was an iterative multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir prod
ely used to forecast reservoir behaviour hydrocarbon recovery and production. This particularly applies to marginal fields where uncertaintie
ssures.� This can accelerate production and improve recovery. This paper outlines the workflow used for candidate screening completio
pproximately 70% of the worldwide oil production. Unfortunately more often than not mature oil fields equate to high cost and low productivit
 able to be conducted in efficient manner. These tools play an important role in well diagnostics to cater for appropriate production optimizatio
  of stringers which are present among all the major offshore oil fields. One of the technology contributions to Saudi Aramco’s effort is pro
The objective of this paper is to exemplify geosteering challenges when drilling horizontal power water injector across Permian eolian sandst
ears beginning in June 2000.�A total of 63 wells have been tested with well site compression; there are now 52 permanently installed com
  risks and uncertainties in spite of complex geological structures and drainage patterns. The new workflow encompasses planning from con
 cture and fluid export schemes with capacities designed for peak production sometimes decades ago and/or different production techniques
 elligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well oi
ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-netw
  into the well.� The optimal amount of lift gas to inject into individual wells depends on a number of factors including inflow performance tu
 r in the Betty Field offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal st
  ies include logging nodal analysis and well engineering technologies. Usually the older the field the more challenging to achieve additional


d reservoir model (SRM) through the set up of an integrated asset model (IAM) to validate the SRM results and control the actual production
epartments. Detailed production data from many sources can be used within simulation models to give a good representation of future field
 ited coordination between them sometimes bypassing important considerations from other components of the overall production system ou
  to conduct integrated studies successively in a continuous chain of studies as if they were on a conveyor belt.� For example field develo
 ion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally the

s for Khafji Field necessitated by the increase of field water cut and depletion of reservoirs.� In order to make up for production decline in K
 lining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recovera
he Saih Rawl field of Oman. Although the field has been producing for more than five years the results shown are based on a one-year app
 Lower Vicksburg (LV) sands and the paper illustrates the key steps in the methodology. Developing Lower Vicksburg sands has been a grea
price. In this case the service provider is contractually bound to provide the service at the pre-agreed price within a specified time window re
magnetic tool a latest-generation LWD (Logging While Drilling) measurement was the technology differentiator for optimizing well placement
  al turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery the horizontal drainholes not only had to cut as much o
he problem of field development where field production profile moves through successive phases of buildup plateau and decline.�This re
  gnificant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed r
uch fields at once.� The method is based on production engineering concepts it is very time efficient and requires only a minimum of data
 environment and heterogeneous geological conditions. For the last years high resolution geological models have been widely used to plan n
tributions: first to determine the effect of production constraints on optimal well locations and second to determine optimal well locations us
perature and pressure should be maintained to improve SAGD cumulative oil recovery and the steam-oil ratio. SAGD optimization work inclu
forms.�The method can be applied to calculate the pressure as a function of position and time when using any continuous function to de
using a method of integral transforms. We fully account for crossflow between layers by coupling these analytic solutions together and solvin
 ale field applications. First the CPU time increases quadratically with increasing model size thus making it computationally expensive for fie
 g history; second it requires large memory to save the gridblock pressure and saturation per each time step used in the forward model. Thir


 the spatial reservoir parameters at grid blocks are adjusted in order to obtain a simulated response close to the observed response. This im

 with steam injection and Steam Assisted Gravity Drainage (SAGD) and to simulate such models efficiently using parallel processing. The si
ases or components. This type of formulation is desirable for flexibility in reservoir simulation but has not previously been used in commercia
ir. This reservoir is located in an offshore field that produces oil from a relatively thin oil rim. The reservoir also contains a large gas cap that

 ficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacities. Com



ng the rate-time data and extrapolating it to predict future performance with the primary aim of estimating reservoir remaining reserves and/o
omplex and may suffer from the presence of a yield stress non-Newtonian fluid in place and both mechanical and hydraulic damage to the m
 llbores the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality strong stress dependency in permea
e can be used for tight reservoirs and multiple compartments or anisotropic reservoirs with high permeability contrasts. Reliable evaluations o
ocused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computationa
dding planes is possible when the effective normal stress on the bedding interfaces is low. Fracture height growth could be hindered or stopp
nt. The paper demonstrates the advantages of using explicit numerical simulation in contrast to analytical modeling.� Conventionally an
actured well are mostly based on the work of Guppy et al. 2-6 where simple empirical correlations were developed in the form of apparent dim
alysis technique for multistage hydraulically fractured wells*. Based on Bayes’s theorem the new technique integrates production perform
  ed rectangularly bounded reservoirs.� In particular improvements in the characterization of the dimensionless productivity index of vertica
of the fracture plane has initially induced significant tortuosity effects and premature proppant screenouts. The length of the perforated interv
unding rock and allows for a curved path of the fracture. The model incorporates an effective finite-difference numerical method for solving a
mitations of using ANNs however is their poor ability to analyze small data sets because of overfitting. Several methods have been propose

 mic modeling which can be summarized in the following points. First the vertical sequence of sands and shale leads to the difficulty in detec
 g for both mass transfer and heat transfer between a horizontal well and a reservoir. The treatment is 1D linear in the wellbore and 1D radial
 ple hit on the recovery factor: Poor displacement efficiency Poor areal sweep Poor vertical sweep This is made worse by reservoir hetero
alized reservoirs. The drive mechanisms of these reservoirs range from strong gas cap drive to strong water influx or combinations of these.
  balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and account
alling into two categories: The problems associated with the quality and quantity of initial data (ID). Very often when the development histor
 expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in a
n the stocks of both experimental design and response surface techniques in the E&P industry rise significantly as an alternative to the more

he permeability tensor K(x) is allowed to have discontinuities. Transmissibility coefficients are obtained from local numerical flow experiments
e “Sugar Cube19 representation of the fractured porous media. Serious spatial inhomogeneity of the saturation distribution in porous mat
 ystem.� The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators since
hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagatio

PU times. Recently streamline simulation has been applied to fractured reservoirs at the geo-scale. However these simulations have been li
 ich is the one used in the present work. More precisely the porosities and absolute permeabilities at each point of a reservoir are considered
es with discontinuous material properties that span many orders of magnitude. Models that represent fractures explicitly as volumetric objects

oduction. Previous results reported on this project suggest that the randomized maximum likelihood (RML) method gives a biased character
induced by temperature or pressure changes or by mixing of incompatible brines. While much work has been performed to study the effect


  ted along the streamlines defined by the velocity field. The efficiency of the solution method along the streamlines is very important for the o
  line method for two phase compressible multicomponent flows in hydrocarbon reservoirs. We prove that even with standard PVT procedure
 tatistical methods or numerical simulation. Both approaches have a significant drawback; the prior being quick however very often lacking in
pers have discussed reservoir characterization applications of the EnKF which can easily and quickly be coupled with any reservoir simulato
 ermanent down-hole gauges is a recent development. A robust procedure to effectively use the enormous amount of data recorded by thes
ation of this model in a full-field simulator. Flow in an open or partially obstructed annulus requires looped flowpaths to be modeled within the

nsate and volatile oil) at near-critical conditions. Multiple scenario production forecasts are required to prepare an optimal development plan
believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir.� Despite the importan

equation and whether the beta factor β for a proppant pack should be constant over the range of flow rates of practical interests. The problem
 location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variation
 d by a relatively low-porosity over-pressured highly fractured and faulted carbonate. Production of the native retrograde gas condensate oc
m wellbore pressure history and rock strength to the trajectory orientation. A stress direction map is generated for the GoS from observations
he authors are neither representing the views of the SPE nor of the participants’ companies. We are delivering smarter fields in order t
economic climate of the late 1980-s and economic shocks during the period of well-known events in the country in 1990-s caused the rapidly
sed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960’s with no oil produ
 subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-el


a heterogeneous fluvio-marine channel deposit in the Western Desert Egypt. All the wells considered in this paper showed significant water
 flow contributions still remains an issue. Several SPE papers covering the issue have been published recently. This paper presents the eng
n Kuwait Sabriyah Field where there are two major producing formations: Mauddud Carbonate and Burgan Sandstone Formations. The well
on logging data is difficult.� Memory logging with conventional production logging tools via coiled tubing and a hydraulic tractor was empl

sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flo
sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flo
 well in a Saudi Aramco field. Permanent monitoring of pressure and temperature enables reservoir engineers to assess the performance of
que for use with wireline formation-sampling tools uses pH-sensitive dyes that change color according to the pH of the formation water. To
ent bottomhole gauges has been on a surveillance and diagnostic program for over 3 years. Pressure transient analysis of shut-ins give key
 s microseismic monitoring campaign was to determine the overall geometry of the hydraulically induced fractures in the Canyon sandstone f
e must be accounted for in the creation of fracture height width and length. In many cases excessive fracture height generation is at the exp

 ution is understood the distribution of steam injected either at the heel or toe of the steam injector can be adjusted to optimize the startup a
 ervals may be located in the annulus between the casing and tubing strings above the end of the tubing.� Of particular importance in this
pleted intervals may be located in the annulus between the casing and tubing strings above the end of the tubing. Of particular importance in
mbedded in a 1/8th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings. EnCana’s multi-zon
es positioning a number of different tracer materials each at specific locations along the length of lower completions prior to lowering downh
osis of production anomalies have been limited by sampling frequency and data quality. This paper presents field-test results of a new type o


 and operational decisions may not permit the maximization of economic value and may undermine the accuracy of the reserves estimates.
nsitive to the wellbore inclination and the high water cut means a small proportion of the flowing liquid will be oil. At what point do these com
red to very small initial gas caps in these areas. A peripheral water injection project is being considered to maintain the pressure above bub
orizontal well. The field example comprises a horizontal well in the South China Sea that was completed as an openhole monobore oil produ
  Moreover oil price increase promoted for technology improvement and set the unconventional techniques of the past to be conventional n
nd to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility pro
changes in individual layers after a well has been put on production without installing an intelligent completion or performing a multirate inflow
c events was recorded with signal characteristics that suggested deformation associated with thermal expansion of the wellbore in addition t
he different reservoir intervals limit conventional production logging possibilities so BP has chosen to install permanent fiber-optic distributed
nal constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering development p
ents showed evidence of thief zones in the Mauddud formation. Early water breakthrough has occurred in some wells. Previous studies indic

ccurate understanding of production volumes the company’s field development and operational decisions may not support the maximum
ts: 1) holdup or the cross-sectional area in the well occupied by the phase of interest and 2) velocity or the speed at which the available pha

rvices suite provides the required answer by acquiring deep resistivity information through casing for subsequent formation evaluation. A tim
  since injection is done into formation water below oil water contact. Though the sea water front movement in the reservoir has been estimate
 sistivity images and describe the methods employed for monitoring the fluid flow and show preliminary results of the modeling process. This
 eep efficiency identify bypassed pay and predict fluid-related issues such as water breakthrough by providing an image of the resistivity dis
 oduction from CBM reservoirs. Wyoming’s Powder River Basin (PRB) alone has 12 000 wells in production with an estimated 50 000 m
 hogonal and occur perpendicular or at very high angles to the bedding. The standard suites of logs such as density/neutron gamma ray and
 . High fracture pressures in coal seams coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing w
 he number of wells being drilled and completed has rapidly increased. With this change in development strategy operators and service com
uring.� There is growing evidence that initiating hydraulic fractures from horizontal wellbores is often difficult and requires abnormally high
 well has an average of 20 pay zones that are stimulated individually. The coal cleats are fractured by pumping nitrogen at high rates through
s compared to vertical wells in the same reservoir due to the much larger hydraulic fracture surface area that is created. In order to achieve o
hale reservoirs. The borehole image interpretation drilling-induced fractures and conductive/healed fractures reveals stress regime orientatio
 rough wells. Production of these reserves requires methods such as steam-assisted gravity drainage (SAGD) and cyclic steam simulation (C
ed. Written by individuals recognized as experts in the area these articles provide key references to more definitive work and present specific
  nitial hydraulic fracture stimulation treatment so that within 5 years an operator is normally faced with a well producing below its economic
s to be reduced to allow wormholes to penetrate deep into the reservoir hence extending the effective wellbore drainage radius. The wormho
  increase production rate from one of the offshore fields while optimizing offshore producing facilities. This offshore field has favourable con

lved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by
 into production. There emerged a necessity to develop the oil-water zones and marginal areas zones with poor reservoir properties and min
e vertical depth (TVD) of 1 400 m. The original development project for this field did not include sand control for the initially forecasted produ
 cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completions
e with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceou
 important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required t
 important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required t
ble in this reservoir.� Thus this reservoir must be exploited using horizontal wells in all areas.� In areas where fractures may not be do

he well was drilled and completed as a proof of concept. It was completed as a trilateral and was equipped with a SC that encompasses surfa
controlling fluids/gels and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interval.
Saudia Arabia. A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encom

e commonplace to improve the well productivity by providing maximum reservoir contact minimizing operating costs lowering the pressure d
his project was to develop and apply a new concept for well completion involving ESP systems tubing-conveyed perforating (TCP) drillstem
 e data and permits lifetime modeling with parameter combinations employing all available data. The analysis explicitly accounts for ESPs tha
ed and surfactant-based have been used in an attempt to achieve optimum fracture length and conductivity.� Acids used for these treatme
mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine
 tana and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting sev
 ted near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sac
 ated by the reaction with the formation results in excessive fluid loss. Controlling fluid loss is one of the key objectives in acid fracturing treat
us after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer lo
 tives has grown. This value must be balanced with the cost of the additives which can be significant in slickwater fracturing treatments. The
  is the dominant parameter controlling fracture height growth and that Young’s modulus contrast is less important. However a recent st
sts per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operatio
er to hydraulically fracture the well as well as complying with stricter governmental regulations. As produced water is recycled and used in fra
d stress state.� The application and appropriate modification of basin best practices and the application of technology for reservoir charac
zuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which bypa
arious techniques to prevent the breakthrough of hydraulic fractures into the underlying water zone but so far without clear success. The pa
ction rates and better access to reserves. However most of these horizontal wells are completed openhole with little alternatives for stimulat
d treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing o
ping reserves under these conditions with conventional vertical wells is in most cases uneconomical. In this setting horizontal wells have co

y successful over the past few years as the majority of the horizontal gas producers have yielded excellent results with open-hole completion


igorous process of candidate selection fracture design and implementation of fit-for-purpose technologies. 10 candidate wells were selecte
The solution for dimensionless productivity index of a finite-conductivity vertically fractured well in a closed rectangularly bounded reservoir a

cess of hydraulic fracturing in Western Siberia organically expanded to projects in Tymen-Pechora and Volga-Urals basin. Both basins are g

h normal cementing operations. The sliding sleeves were opened one at a time to fracture layers independently without perforating. The valv
ng sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation
 Difficulties emerge because hydraulic fracturing in soft rock involves development of a plastic zone near the fracture surface where rocks pa
 us resistance of the fluid flowing through the rock matrix primarily governs fluid loss.�This has historically limited the application to fractu

and reservoirs located in Southeast New Mexico (SENM).� The wells discussed in the paper were completed in various Morrow Sand int


allenging due to presence of high pressure/high temperature and high asphaltene content in the crude oil which renders the situation even m
w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited a
 a clearer picture of the fracture development.� This information can be combined with other fracture diagnostic techniques and along wit

 effects of the deviating borehole trajectory. For common HFM geometries a 2� deviation uncertainty of the positions of monitoring or trea

s and little lasting conductivity will be created. Despite this critical role of differential etching in the creation of fracture conductivity little is kno
e the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height half-length and a
 ting tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a frac

 ropped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector. The candidate selection proces
nductivity cells. At the gas velocities normally encountered in hydraulic fracture proppant packs non-Darcy pressure drops dominate and t
he fracture and a lag zone develops due to fluid cavitation. Properly taking into account the controlling parameters of tip behavior has resulte
um fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic
ns of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the dim
 tion of the seismic waves and injection details. Stimulation below the fault indicated a near-horizontal fracture geometry. Above the fault a n
wback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In pa
e. It is shown that the propagation pressure of the orthogonal fracture quickly increases to above the closure stress on the initial fracture due
 lacing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix. The present paper provides the dat
  in propped fracture dimension is related to the distribution of stresses and elastic properties as well as fluid leak off. Those factors have str
 actures although successful often underperform: Frac and Pack completions exhibit positive skin values and traditional hydraulic fracture
  order to maintain the oil production target for this field the water injection rate should double the target oil rate. To achieve this water must b
se of this work is to demonstrate the benefits of applying an integrated analysis for a hydraulic fracturing evaluation that is performed using a
ffsets have long been recognized as sites of restricted width in the fracture channel potentially leading both to significant pressure drops and
o gas lift valve designed for gas operations. The value of auto gas lift is probably easier to demonstrate than for other types of intelligent well
uire sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Grav
 ured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ut
 ured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ut
ype of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will the
 im intelligent completions technology has been successfully installed in Shaybah field operated by Saudi Aramco. Included in the description
 permeability (K) variation and proximity of water traps). Furthermore conventional completions do not handle effectively heterogeneity or per
 nt completions are delivering better wells through improved efficiency productivity and hydrocarbon recovery with fewer wells both offshore
ntelligent completions wells have been successfully installed in Abqaiq operated by Saudi Aramco. Included in the description are equipment
model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed sche
 ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to actu

 ate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exhi
 oduce the hydrocarbon. Sanding is detrimental to optimum field development and therefore information about the possible advent and exten
ng deep and clean perforations may still not be enough to generate the desired productivity.� Therefore the wells are often stimulated by a
maximum productivity this transition requires an optimal cleanup and the removal of the perforation damages. A new underbalanced oriente
nd E-line have difficulties. This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak field
aracterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi). The wells in Anaco District are normally perforat
Sea. The HZ fields are stacked thin high-permeability sandstone reservoirs interlayered with low-permeability layers. The shallower layers g
maximum geological stress known as the preferred fracture plane (PFP) provides significant opportunities to improve the efficiency of the fra
 oduction. Some wells in�ADMA OPCO fields that are perforated using conventional perforating techniques�will not produce until stimu
duces transient fluid flow that provides an opportunity for quantifying the formation parameters. However the skin factor can rarely be estima
 he accuracy of hydrostatic cushion before firing the guns. The conventional method of correlating the CT on depth involves two CT runs the
erforating conditions of the perforator or perforator system is required if such damage and potential retrievability risks are to be avoided. In pr

  to an outcrop carbonate rock called Indiana Limestone. Three of the tests involved shots into an outcrop sandstone rock called Berea Sands
 llbore damaged zone. This connection through the damaged zone is usually achieved by perforating and the effectiveness of this connection
 l productivity by maximizing oil production and minimizing water production. The paper will demonstrate the challenges and successes of red
 dients the low net-to-gross ratio the low bottomhole temperatures and the requirement for pressure maintenance. The development of the
 lls with 50–60� maximum hole angles. The wells are completed using dry trees from the TLP and are produced primarily from massive
h field (see Figure 1) discovered in the late 1980s is located 180 km south of Riyadh the capital of Saudi Arabia (figure 1). Hawtah is one of
 servoirs. Because of the long lengths of the producing reservoirs and large variations in sand-grain sizes/permeabilities premium screens w
 s one of the completed intervals on the S7000E horizon. Production from this interval began in April 1997 and oil recovery averaged 2000 ST

 olling sand and maximizing productivity it entraps the filtercake formed by the reservoir drilling fluid.� This results in low production rate a
 t are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigorou

 during the production and the injection cycles. This challenge has a significant effect in selection of the completion technique in these wells
ne utilizing low-viscosity carrier fluids and low gravel concentration. In this technique the gravel is placed in two waves commonly called Alph
 ecome more common. Executing these open-hole gravel-pack jobs (alpha-beta packs) has been a challenge. Although scattered attempts
 onsidered one of the proven methods of sand control from both reliability and productivity standpoints and allows access to larger reserves
conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfora
 onduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfora
rs are planned and all will require some form of sand prevention. Extensive rock mechanical work using Statoil’s finite element modeling
ection well and served as a demonstration of its potential benefits in the development of Stag oilfield. Located offshore in the North-West she
or a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings as well as excellent return on investm

  significant economic loss. AGOCO recognized that it was facing a major challenge in terms of understanding potential sanding risk for Sarir
  s. It can impact production cause erosion in downhole and surface facilities require additional separation and disposal and lead to significa
 production indicating possible sanding issues for this field. To investigate this problem relevant data from different sources and different do
  y perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production. The labo

  the rock surrounding the perforations and the borehole. Sand production in weakly consolidated formations is generally assumed to be a tw
 ategies to maintain mechanical and time-dependent stabilities of extended reach wells and 2) to assess sand production risk in the developm
 ast 4 years the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants hav
 reatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture both in the
  acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fun
 eally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid
deally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid
onal coverage in large limestone reservoirs. The viscoelastic diverting acid system was pumped through coiled tubing in three of these wells
ation permeability often exceeds one darcy. The mineralogy is composed of calcite (98 to 99%) with about 1% halite and < 1% quartz; there
 cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore acid penetration
al production gain with relatively low level of investment. In the recent acidizing campaign in Brunei a particular challenge was the flowback o

y damage to each zone matrix mineralogical composition and pressure regimes of each zone need to be taken into consideration. The pre
wells. The first is its high reaction rate with carbonate rocks which limits acid penetration in the formation. The second is its corrosivity to we


cated at a depth of 6100 to 7500 ft that has produced (30 to 45 �API crude) for over 35 years with production peaking at 66 000 BOPD. T
 ating fluid over the entire interval. When fluids are pumped into a well they naturally tend to flow into the zone with the highest permeability o
In the mainly brown fields tertiary recovery methods such as water-flooding are implemented to maintain financial viability of the well stock. I
� However most previous studies reported in the literature have focused on investigating the effects of injection rate temperature and flu
 ssure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as comp
  the Frontier Formation located in Bighorn Basin Wyoming has seen a variety of stimulation fluids used over the past years with varying deg
 but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the
 process that integrates petrophysical and reservoir characterization expertise with production and completion knowledge by developing an

 ed with limited surface water handling facilities increased the importance of stimulating this type of challenging wells due to the drastic perme
 d are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. C
 eservoir pressure permeability and skin. There are two aspects of the proposed approach - straight-line analysis and modeling. A novel app
  this reservoir.� Thus this reservoir must be exploited using horizontal wells.� Recently a 2 270 ft long horizontal well has been drilled i
 ient analyses and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rates
d as a multi-layer commingled producer then this conventional approach makes it difficult to measure the permeability and skin of individual l
 ured formations are to prevent or delay the intrusion of unwanted fluids into the wellbore i.e. water coning.� A similar early-time pressure
neous propagation of the pressure signal in the entire spatial domain when a flow rate or pressure pulse is applied to the sandface (beginning
e dynamic behavior of the reservoir.� Loss of production and cost of acquiring data versus the benefits has always been a classical mana
n methods to the long-standing deconvolution problem and make deconvolution a viable tool for well-test and production-data analysis. Howe

 e these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long bee
 xpensive development plans can be put in place. New technology real time monitoring and integrated reservoir data are essential to unders
 rvoirs are vertically heterogeneous with high permeability. MiniDST’s are conducted using the inflatable straddle packer system of wireli
aration and existing instrumentation is often doubtful leading to an under-estimate of liquid rates. An aggravating factor is that such wells are
he operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenge

ontrolled flow loops using idealized fluids in steady state conditions. However for high water-cut high gas-volume-fraction and low pressure u
 ir and production management. However it can be difficult to compare data sets obtained with different measurement devices. Multiphase f
 retation models of traditional multiphase flowmeters emphasize the liquid rate measurements and have been used to well test and meter mo
for procurement actions evaluate the production test data measured by the conventional test separators and improve the testing duration an
e of device especially in the High (92-96%) or Very High GVF (96-98%) ranges. Most of the purchasers put a cut off in the GVF range of 85-9
dels could be used in well test interpretation. The need to effectively use information available from well test analysis in full-field simulation ha
ure transient data [Hosseinpour-Zonoozi et al (2006)] and we demonstrate that the β-integral derivative and its auxiliary functions can be us
terpreted because of various artifacts collectively termed noise. While various noise-smoothing techniques have been used there are valid c
  streaming potentials generated by these transients were measured by arrays of permanent electrodes placed in the boreholes.�The elec
recognized as a weak spot in CO2 storage where containment can break down. This is because cement steel and elastomers can be corro
grity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above calculated from the density log data. T
adation and casing corrosion in injection production or abandoned wells can create preferential channels over time allowing migration of CO
y of oil and gas reservoirs. Optimization techniques have been applied independently to the reservoir and surface models leading to non-op
arse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes such as dry-ou
 Federal Ministry of Education and Research and the German Federal Ministry of Economics and Technology targeted at developing an in s
ring them in subsurface reservoirs is thought by many scientists to be a reliable solution until emission-free energy sources are developed a
ervoir and in its surroundings. Besides the mechanical properties of the rocks exposed to CO2 may be altered. The impact of the resulting d


Reach Drilling (ERD) from a floating installation.� The 34/8-A-6 AHT2 is also the longest Down hole Instrumentation and Control System
 voirs which are poorly imaged on seismic. Reservoir overburden is fast drilling formations with hard stringers. The field pore-pressure gradie

300 reefs have been located in the southern portion of the basin many of which have produced more than 5 MM bbls of oil. The EOR potent
me to be an excellent opportunity because of its low cost. Since 60 years ago 2500 km2 of carbonate formations containing CO2 were disco
minated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disburse
d consequently the well productivity.�Also when reservoir pressure drops below the dew point a big portion of condensate liquid will rem
nvolved in the process SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective of
mplex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling cap

 the feasibility of performing water shutoff treatments in the open-hole completion oil wells. The study involved evaluation of a high temperatu
specially in case of multiple zones interval simultaneously producing and where completion of the wells restricts considerably the convoyed d
g out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are prob
nd capping it with cement and gel using coiled tubing (CT). Historically it has been difficult if not possible to perform mechanical water shut
  st Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection c
   reasons. It requires increased capacity of water separation and handling facilities decreases hydrocarbon production and results in large a
date selection and finishing with post-treatment well performance analysis. This kind of operation becomes more challenging for horizontal we
  ant challenges.� Of particular concern are the effects of produced fluid hydrocarbon solids (i.e. asphaltene wax and hydrates) precipitati
est section using tap water and mineral oil (density=0.85 g/cm3 and viscosity=15 cp) with superficial velocities ranging from 0.025 to 1.75 m/
 e flow was experimentally investigated for different inclination angles (0� �1� �2� and –5�). A total of 324 tests were con
 oduction from the commingled reservoirs and optimize the recovery. Traditional methods for production optimization and back-allocation of
s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a produ
phaltene wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on fi
 rate and representative fluid characterization and resulting flow assurance data on optimum facility and production method design for develo
  enotes an issue for health safety and the environment (HSE) and is readily absorbed by elastomer seals weakening the resistance of those
 s are being deployed to determine reservoir connectivity based on the compositional differences in the reservoir fluid. In a number of reservo

been developed that are based solely on commonly available field data. These properties are the dewpoint pressure of the reservoir fluid cha
 unctions (oil-gas ratio Rv solution gas-oil ratio Rs oil formation volume factor Bo and gas formation volume factor Bg) were investigated
 ot been well characterized in the laboratory until recently. In this paper we review a gravitational gradient of asphaltenes in a reservoir and a
duction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wells m
or subsequent economic analysis. Compartmentalization and spatial variations of fluid composition are two primary factors that cause major
 uring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation testin
 of new generation WFT probes that can operate in OBM filtrate environments with enhanced efficiency. Analytical as well as numerical mod
 and new fluid identification sensors which allow real time monitoring of a wide range of parameters as GOR fluorescence apparent density

lizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections a new foc
 de. Detecting the presence of H2S early in the life of a discovery can help to accurately assess the feasibility of a project and determining if
nhole separation. Given this reality the pressure/volume/temperature (PVT) analysis of any fluid sample with an equation-of-state (EOS) mo
 ceived little attention until the 1980’s when sufficiently advanced analytical methods became available to assess the phenomenon. Indiv
fore small changes in reservoir condition will result in a change of fluid properties considerably. As a result there exists a broad spectrum of
sing the spatial variation of fluid properties is as vital as assessing the spatial variation of formation properties. Conventional wireline triple-co
 ivity permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure g
  a complex process that requires a greater number of data points fluid samples and associated laboratory analysis. Pressure gradients with
  facilities. When a formation fluid sample is taken from a well drilled with oil-based mud (OBM) sample contamination by the OBM filtrate is


ex fluid columns showing compositional gradients for columns in thermodynamic equilibrium or under steady state conditions. Montel et al. (2
upt changes in these fluid properties with depth may be markers for reservoir compartmentalization. However hydrocarbon differences can b
 ing the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation testing

 numerical simulators.� The methods are based on a fluid characterized by pressure and temperature dependent K-values.� Although t
es in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems




son to conventional sampling methods. Formation-fluid sampling has always been adversely affected by mud-filtrate contamination which in
out of the formation into the wellbore until real-time downhole monitoring of the fluid in the tool flowline ensures it is clean. The reservoir fluid
ster DST and multiphase sampling and fluid characterization environments with the most challenging area in recent years arguably being the
 es of condensate and heavy oil environment where traditional means of measurements are impaired by the difficulty to separate the phases
precipitate at certain conditions. The precipitant may form on the rock surface and act as a barrier and ultimately stop the reaction of the acid
 stone reservoir with a low permeability of approximately 15 mD containing saturated oil. The 122�C temperature complex mineralogy p
 s). This study proposes novel applications of straightforward chemistry to synthesize calcium carbonate particles that damage the porosity o
 d compared with commercially available inhibitors. Salt deposition in high salinity brines can cause blockages to production and process sys

 cted to determine the precipitation rate for various pH and temperature conditions. Microscopy investigations were carried out to verify the gr
n the vicinity of the perforation tunnel resulting in a zone of reduced permeability called the crushed zone. Additionally the impact stresses p
material surrounding the perforation tunnel and created by the impact of the shaped charge jet on the rock fabric. Perforating underbalanc
urface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibitors
asin using borate crosslinked fracturing treatments (with scale inhibitor concentrations as low as 5 gal/mgal). However these design criteria a
ensors and control valves at the reservoir face engineers can monitor reservoir and well performance in real time analyse data make deci
ower part of the production string are the common type of scales encountered in Upper ZAKUM producing wells. Injection seawater (rich in S
 evere barite scaling tendency will require inhibitor concentrations in the range of 10-50 ppm to control scale but in practice concentrations <
dent in terms of their effect on the objective function. Otherwise perturbing one variable to improve the match in a particular region may adve
 s. Such capability has made streamline based history matching very attractive and more reliable in expediting history matching of simulation
ate added value due to its ability to handle high-resolution full three-dimensional models with hundreds of thousands to millions of cells inco
  is to monitor the advancing fluid levels at wells and control the unexpected fluid breakthroughs. Hence the design and intelligent well manag
st decline of the gas wells during their first year of production drove a change from reactive into proactive management tactic to monitor the f
ater saturation between wells to properly manage the sweep and recovery. In 2007 ADCO initiated water injection (WI) and WAG pilots to te
 tifaceted approach of balancing voidage with injection conducting extensive surveillance/analysis within the reservoir to assess the efficacy
avity and viscosities of 2 000 cp at a reservoir temperature of 133�F). After 1995 with the implementation of horizontal drilling technologie
ry processes are more efficient in low pressure reservoirs; however due to their depth the initial pressures of the reservoirs in the Faja are re
 ity of this method was investigated.� Heavy oil samples from conceptual reservoirs (Bati Raman (9.5 API) Garzan (12 API) and Camurlu
 hicknesses and heterogeneities found the implementation of different thermal recovery methods is necessary. This project covers a feasibi
 uild rates. Unconsolidated sandstones and interbedded shale’s are sensitive to mud weight and are prone to lost circulation. First few h
 ual porosity system and the presence of fractures at varying scales. This case study of the 1st Eocene reservoir characterization in the stea
 racterizing of permeability anisotropy and in-situ minimum horizontal stress estimations. Pressure and fluid samples are obtained by setting
 of vertical wells indicates that the reservoirs are facing problems of low productivity bottom water conning and sand production. In his circum
servoirs with high-permeability contrasts. Conventional acidizing results in the stimulation of water zones and misses targeted oil zones. The


ng classical separator. Heavy and Extra-Heavy Oil represents more than 50% of the worldwide oil reserves and large efforts have been spe

 usually pumped in multiple stages of pre-flush main fluid and over flush. The drawback of conventional sandstone acidizing treatments is th
te fields. The main objectives of the pilot phase of the exploration projects in the Achimovskaya formation are reducing reservoir and fluid un

 rties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper we have studied the effects of gra

oals.� With titanium (Ti) or zirconium (Zr) crosslinked gels which are known to be prone to irreversible shear degradation early crosslinkin
nded with the difficulty of providing adequate corrosion control. In addition the health safety and environmental implications of acid handling

res and temperatures during the producing life of the well both in flowing and shut in conditions which allows to optimize production and flow
nts operationally difficult and challenging. More than 60 treatments have been performed in over 40 wells placing over 3 million lbm of propp
cids and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of hig
149�C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of ma
uid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undes
fferent chemicals (A1-A5) are evaluated in this study for their ability to prevent water block formation at high temperature. Adsorption/desor
tory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard labor

drilled extensively in this low permeability gas reservoir to enhance productivity.(5) While the increased contact area offers a potential for enh

optimization and field geocellular and simulation modeling. Through this process various development scenarios for completions and drilling
wells in the Rocky Mountain region were mapped in real time with a 3-D stimulation viewer software package. One well employed technique
at will lead to desired line drive mechanism optimized reservoir drainage and maximized recovery factor. That information is not less critical
Modern well log evaluation techniques and completion methods are required to yield economic wells. In some cases microseismic monitorin
he productive sands are associated with nearby water sands that are often intersected by the hydraulic fractures as their heights grow which


 fectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore areas.
 on. The lithology of the Xu-6 formation which is the main reservoir section where the lithology mainly consists of fine-medium feldspar-quar
 vals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves c
g. Single sand body pay zones would not be commercially attractive. Rigorous reservoir modeling and simulation workflows were employed
 physical and a mechanical stress model calibrated from offset nearby wells to match well production and fracturing treatments response.�
kness of 4 000 ft in a fluvial depositional environment. Reservoir rock permeabilities are in the microdarcy range. The overpressured reservo
e and useable petrophysical model for an accurate productivity indication of the target interval. The pressure to avoid non-economical comple

mic faults in the oil based mud borehole environment. This paper summarizes part of the experience learned from the use of an optimal data
 n objectives. Thus the complexity of the wireline formation testing (WFT) has dramatically risen and continues to rise. It requires an effective
 idely used to improve the economic viability of wells and fields to that matter the presence of natural fractures plays the same role in improv
s due to the nature of the rock and the granularity of the data necessary. This case study summarizes results for a wireline pressure data col

 ing. There is no stable flowing pressure during the pretest build-up times can be long and the confidence level of the final pressure is often
 used a 20-year gap between discovery and development. The initial pilot development was halted after poor drilling success thus the opera
success is the Cleveland Sand of north Texas and the Oklahoma Panhandle. Very recently some success with horizontals has been observ
terogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day. The article


ed significantly by complex rock heterogeneity can only be accomplished by selective flow measurements. To use openhole sampling tools f

s and economics of the project. This is further complicated in tight viscous and sand incursion prone formations. This paper discusses abou
 blic response to a proposed project. However this approach has many limitations related to recognizing the company’s true financial pe
 leum company. By improving judgment elicitation process particularly in the case of multi-criteria decision-making it is possible to improve q
 desired structure.� During the course of drilling an 8 well Horizontal drilling program for the Kuwait Oil Company (K.O.C.) in the Burgan Fi
st. Rock typing is often used to help map the available capillary pressure data to the reservoir layers. Borehole nuclear magnetic resonance
 esolutions but very small lateral radii of investigation and the pressure transient tests have a large lateral radius of investigation but very po
 sh 2 rock types having the same range of porosity but different porosity-permeability relation. The dual porosity system is illustrated by stron
ast coast of India. The present study aims at reconstructing sedimentary depositional environment with the help of image logs and cores and
he reservoir heterogeneities. A realistic identification of the depositional environment is critical to the delineation and prediction of the best qu
 on cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy which can provi
 duction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wells
al in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an ave
 plexities associated with its evaluation. The complexities in general relate to a heterogeneous reservoir with complex mineralogy varying wa
rmation evaluation on LWD. The compact design of the new-generation LWD tool greatly increases the likelihood that measurements will be
 of such sources have always been known more awareness in the industry has led to increased efforts towards the reduction or even elimin

 nty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to asses
 certainty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to a
carbonates. The authors have earlier described an approach to estimating permeability in carbonates from borehole NMR logs and electrical
d carbonate cements are present within the sandstone with the anhydrite dominating in the uppermost units. The basal sand syones are ofte
a wide variety of textures.� In some intervals the depositional textures are preserved in others they are highly altered by diagenesis.� V
 eability in each layer resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR borehole ima


f the anisotropic shale point. The same shale point should be used in the determination of sand porosity. Difficulties will arise when anisotrop
) apparent resistivity measurements (attenuation and phase shift) could be significant. These effects need to be considered in resistivity log i
ial deposits. Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in h
sment of fluid complexity compositional grading and acquisition of samples for input to PVT studies. Many deepwater reservoirs comprise
 and faults seen on electrical image logs cannot always be discerned as to whether they are of natural or drilling-induced origin. Cross-refer
 sq. km. of 3D seismic data of Al-Khafji oil field shows number of sinuous (channel-like) events in the north and north-east of the main Khafji

racterize the reservoir connectivity and sweep efficiency. However geostatistical modeling methods do not always make an accurate inferen
 o characterize such reservoirs. The formation evaluation of thinly bedded reservoirs has several objectives: identify the layers that may co
sed to that of the sand-shale system). Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolution

ions with data acquired with wireline measurements and formation layer thickness determinations. The reasons for these inaccuracies gener

rns of horizontal injection and production wells. Horizontal wells are increasingly being used for production and waterflooding. Long-term inje
voir compaction and surface subsidence.� The mechanical parameters can be divided into three main groups viz. elastic parameters st
 warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed a
 providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective In
 providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective In
 providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective In
ial to identify areas of high fracture density. It has been observed that fractures associated with certain faults have facilitated the flow in the J
In this paper we developed a workflow of integrating formation micro imager Stoneley waves and petrophysical analysis for better fracture c
e zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associated with natura
understanding of the fracture networks and their relationship with major and sub-seismic faults in this field is now critical to optimize infill drill
s vugs in some zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associate
Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties such as relativ
c. Overlooking the variation in fluid properties that can and do exist in what appears to be a homogeneous reservoir on a typical log analysis
he relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud syste
own when the rock does not have paramagnetic elements the porosity measured with the NMR is not affected by the minerals within the ma
y and nuclear logs are used to infer basic fluid types caliper log is used to verify that the borehole is suitable for sampling and NMR logs are
n clay-bound capillary-bound and free water. In addition to these reservoir characterization problems we observe effects caused by the drilli
measurements of transverse relaxation (T2) polarization (T1) and diffusion (D). But compromises are inevitable for any given NMR techniqu
o more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent adva
mpts to optimize previous results using an integrated petrophysical characterization workflow. The geological complexity of the Estancia Cho
 logging horizontal wells especially in multiphase flow. A new logging tool has been specifically designed to better characterize fluid flow in h

o the formation. It also facilitates the possibility for reservoir characterization during drilling. The purpose of this paper is to present (1) how to
00 ft with an average Net of 170ft in the upper layers. An average porosity value will be around 15% and permeability ranges between 0.001â

Downhole fluid analysis along with complementary techniques including geochemical mud-gas and pressure analyses provide valuable insig
 large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentration
work providing a basis for the analysis of reservoirs that exhibit Darcy and non-Darcy flow respectively. An extension of the conventional S
nitoring techniques can identify inconsistencies leading to possible adjustments in recovery strategies and eventual improvements in ultimate
ervoirs owing to their thin beds high shale content and variable formation water resistivity. Missing gas-bearing formations translates into los

meable shales between producing sands complicates fracturing design and field development to maximize recovery. Permeability and perme
  Therefore any calculation of initial pressure and permeability must take into account the supercharging effect. We present an algorithm tha
  options developed by reservoir production drilling and facilities engineering and ranked by economics. The process specifically involved firs
  to marginal fields where uncertainties such as geology (static information) and reservoir drive mechanism (dynamic information) may impac
 d for candidate screening completion selection and ESP system design of the first such conversion on the Bokor Field offshore East Malay
quate to high cost and low productivity making mature fields unattractive when competing for resources with other options in a company’
 or appropriate production optimization for the field.� The Bokor field is located 45 km off the coast of Sarawak East Malaysia. The reserv
ns to Saudi Aramco’s effort is proactive geo-steering using Directional and Deep Resistivity technology to maximize the net sand delivere
 jector across Permian eolian sandstone reservoirs with high degree of structural and reservoir uncertainty. The integrated reservoir manage
 are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional w
 flow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given s
 nd/or different production techniques.� Substantial increases in producing gas-oil ratios and water production can occur over the lifetime
with the goal of maximizing the well oil production avoiding cross-flow minimizing operational risks and well interventions(coil-tubing operatio
   of reservoir simulators surface-network simulators process-modeling simulators and economics packages.��� We present a com
 ctors including inflow performance tubing and surface hydraulics.� Additionally careful consideration must be given to operating constrain
onal environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir unlik
 ore challenging to achieve additional reserves. This paper outlines an integrated approach for achieving these opportunities reducing the ris


lts and control the actual production performance. A discusson of the theory of the IAM as well as the steps to set up a SRM and IAM are pr
  a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 y
s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a produ
 or belt.� For example field development planning studies for ten reservoirs some with history of more than 20 years have been generate
 lt of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include san

 o make up for production decline in Khafji Field and to sustain the field target rate and defer large investments associated with exploration an
servoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone rese
  shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of historic
wer Vicksburg sands has been a great challenge to all operators in the region not only because of the high drilling and completion cost but a
 ce within a specified time window regardless of the prevailing price and availability. This paper presents a mathematically consistent framew
entiator for optimizing well placement in a number of deep water horizontal wells. The new directional measurement is highly sensitive to res
 nholes not only had to cut as much of the good reservoir sand as possible but as the Brenda field depends on water drive as its main produ
 dup plateau and decline.�This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) unti
 od for comparing a set of assumed reservoir parameters especially the presence of a connected aquifer and its size with a set of simulatio
 and requires only a minimum of data which makes it in most cases more suitable than other methods. The approach provides a filtering co
 dels have been widely used to plan new wells trajectories. However the dynamic behavior of the reservoirs was widely ignored. These effec
o determine optimal well locations using a gradient-based optimization method. Our approach is based on the concept of surrounding the we
 l ratio. SAGD optimization work includes simulation results and real-time data monitoring. Existing analytical models1 2are mainly dedicated
n using any continuous function to describe the production rate of a point source. Successive integration of the point source solution can be
analytic solutions together and solving for the flux field at the layer interfaces. The time evolution of these flux fields is governed by a Volterra
ng it computationally expensive for field applications with large number of parameters; second the sensitivity coefficients that define the relat
  step used in the forward model. Third it is computationally expensive as it requires solving the Adjoint system of equations backward in time


se to the observed response. This implies that the optimization problem can be prohibitively large and inefficient. In order to circumvent this

 ntly using parallel processing. The simulator solves component material balance energy balance and mass equilibrium equations for compo
 t previously been used in commercial simulators due to its complexity and inefficiencies in both memory and speed. Here we describe an eff
oir also contains a large gas cap that provides the dominant energy for reservoir recovery. The reservoir is composed of interbedded shallow

 with limited platform capacities. Commonly a horizontal well trajectory undergoes undulations that may result in special wellbore flow dynam



 g reservoir remaining reserves and/or remaining productive life. The effective use of the forecast techniques: Empirical Fetkovich Locke &
 anical and hydraulic damage to the matrix near the fracture face. A previously published fast-and-robust single-well model was applied to stu
  strong stress dependency in permeability hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow
bility contrasts. Reliable evaluations of stimulation performance are required for field development planning. As such pressure transients are
 roblem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production op
ht growth could be hindered or stopped by interfacial slip when a vertical hydraulic fracture propagates in such formations. An interfacial slip
cal modeling.� Conventionally analytical methods and software are used to forecast post-fracture production rates to evaluate the profita
developed in the form of apparent dimensionless fracture conductivity as a function of the true dimensionless conductivity and the inertia resi
chnique integrates production performance data production logs and prior information to arrive at the most probable description of the reser
 nsionless productivity index of vertically fractured wells in closed rectangularly bounded reservoirs during boundary-dominated flow have bee
s. The length of the perforated interval has therefore been reduced to the acceptable minimum. Although operational problems have been s
 ence numerical method for solving a system of coupled differential equations: 1D equations of power law fluid flow along the fracture trajecto
Several methods have been proposed in the literature to overcome this problem. On the basis of our study we can conclude that ANNs that

d shale leads to the difficulty in detecting a single gas-water contact in the field. Second the vertical heterogeneity leads to the use of fine gri
D linear in the wellbore and 1D radial in the reservoir. A numerical algorithm for reservoir temperature calculation is proposed and an analytic
his is made worse by reservoir heterogeneity. The commonly used concepts of productivity index (PI) and injectivity index (II) are not particu
ater influx or combinations of these. Fourteen material balance models were built and the results analyzed. This study shows that proper inte
ach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under di
y often when the development history counts more than 20 years some well data for instance formation pressures become unavailable. W
  are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our ca
 ficantly as an alternative to the more traditional uncertainty analysis. Whilst there are papers describing experimental design workflows and

 om local numerical flow experiments (transmissibility upscaling) for each cell face. Monotonicity of the solution matrix is discussed and a ver
 saturation distribution in porous matrix blocks was demonstrated. Dual porosity/permeability models are obviously unable to reproduce spat
ual porosity reservoir simulators since triple porosity system “isolated vugs are not part of the formulation. The simulation of oil productio
 tribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estimat

wever these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractured
ch point of a reservoir are considered to be those of two interpenetrating continua the matrix and the fractures one. It is also assumed that th
 ctures explicitly as volumetric objects pose a particular challenge to standard simulation technology with regard to accuracy and computation

ML) method gives a biased characterization of the uncertainty. A major objective of this paper is to show that this is incorrect. With a correct i
s been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation i


 reamlines is very important for the overall efficiency of the method. In this work the acceleration of the saturation transport using adaptive m
at even with standard PVT procedures performed at each time step at each spatial point streamline technology maintain its better scaling ab
g quick however very often lacking in accuracy the latter being very accurate however usually very complex in setup and computation. The p
e coupled with any reservoir simulator. Neither adjoint code nor specific knowledge of simulator numerics is required for implementation of th
 ous amount of data recorded by theses monitoring systems has been proposed and tested on a synthetic case. Geostatistical simulations
d flowpaths to be modeled within the well. We describe the extension to the formulation of the well model together with considerations to ens

repare an optimal development plan for the complex. Current compartmentalization understanding based on geological and engineering data
e reservoir.� Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a contin

tes of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and C
nging water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading mu
 native retrograde gas condensate occurs primarily from three major formations: Shuaiba Kharaib and Lekhwair in the Thamama limestone.
erated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base viz. electrical Images
are delivering smarter fields in order to add value to our business – there are many facets to this value beyond reservoir well process and
 country in 1990-s caused the rapidly decline of the number of new EOR projects. EOR technologies started to develop in direction of sweep
tered the 1960’s with no oil production but by the end of the 20th century the provinces combined had delivered almost 50 billion barre
 odels are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a sim


n this paper showed significant water production. To identify the main water-producing zones and the bypassed oil all the wells were logged
ecently. This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the Ose
gan Sandstone Formations. The wells were completed with dual production strings due to distinct fluid and reservoir properties in these forma
 ng and a hydraulic tractor was employed.� However due to the wear experienced by the coil high cost and poor data quality at low flow

 sponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda formati
 sponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda formati
ineers to assess the performance of the reservoir in areas such as flood front movement and pressure support maintenance. In this well a m
to the pH of the formation water. To make a real-time pH measurement the dye is injected into the formation fluid being pumped through the
ansient analysis of shut-ins give key performance indicators (KPIs) such as permeability-height (kh) skin (s) and current average reservoir p
 fractures in the Canyon sandstone formation. Information and results initially derived from the microseismic interpretation were used to prov
acture height generation is at the expense of fracture width and length creation. As a result in fracture treatments where excessive height gr

 be adjusted to optimize the startup and early operation of the SAGD pair. Total E&P Canada permanently installed optical fiber along their f
 � Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the well outflo
 e tubing. Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the well o
ocity strings. EnCana’s multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed n
completions prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up oil samples ar
ents field-test results of a new type of downhole multiphase flowmeter which confirm the value of permanent downhole metering. The meter


 accuracy of the reserves estimates. Present digital oilfield technology gives the production engineers all the data needed to monitor process
 ill be oil. At what point do these compounding affects limit the ability of current technology to measure low oil flows? This paper explores this
  to maintain the pressure above bubble point and improve oil recovery from the flank areas. However limited information is available concer
  as an openhole monobore oil producer using a slotted liner. The well began production with an initial oil rate of 1 800 bbl/d. Oil production q
ques of the past to be conventional nowadays. This boom in technology application permitted high margin of investments to optimize wells/fie
s spanning pressure and mobility profiling vs. depth fluid sampling downhole fluid analysis (DFA) interval pressure-transient testing (IPTT)
pletion or performing a multirate inflow performance relationship (IPR) test. This paper describes a technique allowing individual layer pressu
xpansion of the wellbore in addition to events apparently associated with induced fracturing in the reservoir. Integration of the microseismic d
stall permanent fiber-optic distributed temperature monitoring systems with its sand screens and to use these systems to monitor production
 a recent engineering development program was to create a new deployment system that directly addressed these constraints. Instead of in
n some wells. Previous studies indicated that it was very challenging to detect the thinly layered thief zones using conventional openhole logs

cisions may not support the maximum economic value of the reservoir and can undermine the accuracy of the reserves estimates. With cur
 the speed at which the available phase is flowing.� Recent industry developments in production logging have addressed these fundamen

 bsequent formation evaluation. A time lapse saturation figure could be generated immediately after the acquisition which is extremely instrum
ent in the reservoir has been estimated indirectly via numerical reservoir simulator successes of direct methods have been limited by the inje
esults of the modeling process. This crosswell EM technique which has been successfully employed and proven in other geographical areas
oviding an image of the resistivity distribution between boreholes in time lapse. This paper explores the influence of a high quality background
oduction with an estimated 50 000 more wells to be drilled in the next 10-15 years. The production rate from CBM reservoirs is low perhaps
 h as density/neutron gamma ray and resistivity define some of the petrophysical properties of the coal layers but the nature and extent of c
 nd inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fracture
  strategy operators and service companies alike have had to search for innovative solutions to overcome challenges faced in horizontal com
difficult and requires abnormally high treating pressures.� In this paper we show that the combination of high stiffness significant elastic a
umping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly.� Currently energy that can be deli
  that is created. In order to achieve optimum horizontal well stimulation the lateral section must be characterized and the perforation placem
 ures reveals stress regime orientation fracture morphology and their orientations. The interpreted results guide the design of horizontal well
 AGD) and cyclic steam simulation (CSS) (Butler 1991). �Optimal well placement defines the propagation of steam within the reservoir an
 e definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances i
a well producing below its economic threshold. To keep up with current gas demand operators have moved to an aggressive horizontal drilli
ellbore drainage radius. The wormholes created by a retarded acid are deep but thin. During production the flux through the thin wormholes
 his offshore field has favourable conditions for ESP application producing from carbonate reservoir with no anticipated fines production low

easing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that eliminate
with poor reservoir properties and minor reservoirs in order to maintain the production rates. Application of horizontal drilling allowed achieve
ontrol for the initially forecasted production rates. However the possibility of expanding the gas production rates of each well to more than 1 M
ntly without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design
Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from the
 s than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encountere
 s than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encountere
areas where fractures may not be dominant it is crucial to achieve maximum reservoir contact (MRC) through the well architecture.� To th

ed with a SC that encompasses surface remotely controlled hydraulic tubing retrievable advanced system coupled with pressure and temper
oachment over the reservoir interval. Recently completion technologies using downhole valves which allow production and injection control
was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pres

erating costs lowering the pressure drawdown and maximizing profitability. This paper presents the results of a numerical study performed to
onveyed perforating (TCP) drillstem testing (DST) and chemical treatment of the formation by using standard equipment and techniques. T
alysis explicitly accounts for ESPs that are still operational at the time of the study thus removing a historical source of statistical bias. The a
 vity.� Acids used for these treatments have been typically formulated with 28-wt% HCl and have been used successfully to increase produ
 illance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriza
he Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tried
 racture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This c
 key objectives in acid fracturing treatments to be able to create longer and wider fractures and hence maximize well productivity. Alternating
 s and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placemen
slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric microemuls
 less important. However a recent study pointed out that modulus contrast can have significant implications on fracture geometry and proppa
mpletion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions the se
 ced water is recycled and used in fracturing applications each cycle of re-used water returns with a more complex chemical make up than b
 on of technology for reservoir characterization can shorten the learning curve of an operator in the development of a basin.� Numerous c
 a short and wide fracture which bypasses the near-wellbore damage while gravel-packing the zone of interest. This paper describes a nove
 so far without clear success. The paper describes a technique of physical barrier placement and tailoring fracturing fluid systems to control f
hole with little alternatives for stimulation water shutoff or workover treatments. A very challenging task to stimulate long openhole sections e
 ated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropriat
 this setting horizontal wells have come to mitigate the problem however in most unfavorable conditions where oil and gas are found in tight

ent results with open-hole completions in particular. Consequently most of the planned future wells will be drilled as open-hole horizontal com


ies. 10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. Mo
ed rectangularly bounded reservoir and the corresponding pseudosteady state shape factor of this type of well and reservoir completion unde

 Volga-Urals basin. Both basins are geologically lithologically and stratigraphically vastly different from West Siberia. Adding the difference in

ndently without perforating. The valves have a unique design feature which allows an unlimited number of valves to be placed in a single we
e possibility of high fracture initiation pressures is identified as the main risk with this approach. This paper will discuss the theoretical and
  the fracture surface where rocks partly lose their cohesion. This study has developed a more appropriate model for fracture design which t
 ically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high p

ompleted in various Morrow Sand intervals around 10 500 ft with an average Bottom Hole Static Temperature (BHST) of 190oF.� Wellbor


oil which renders the situation even more difficult because of fluid incompatibility issues. The formation tends to produce oil with asphaltene c
 tive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mecha
 diagnostic techniques and along with sound engineering practices can have a profound impact on how wells are completed.����

  of the positions of monitoring or treatment well surveys can cause more than a 40o uncertainty of the inverted fracture azimuths. Furthermo

on of fracture conductivity little is known about the texture of the fracture surface created during acid fracturing or about the dependence of t
 xist: fracture height half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is know
using this technology as part of a fracturing treatment. These issues along with regulations concerning the transportation of radioactive mate

ctor. The candidate selection process including production prediction is at an infant development stage and is additionally hampered by th
Darcy pressure drops dominate and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeability
arameters of tip behavior has resulted in more accurate and robust fracture propagation models. However the situation is still unclear in high
ure of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stage
y induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed recta
 acture geometry. Above the fault a near-vertical fracture geometry was observed. A change in fault orientation was supported by differences
 owback during the life of a well. In particular determining whether the proppant flowback will stop after a few days of production or will contin
 sure stress on the initial fracture due to the fracture penetrating into the higher stress region which leads to fracture reopening along the initi
   The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium
  fluid leak off. Those factors have strong implication on proppant distribution especially when larger size proppant are used. Although the lat
ues and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production frac
 oil rate. To achieve this water must be injected into the formation at fracturing pressures. The completion campaign started with three wate
   evaluation that is performed using a workflow including time-lapse Sonic Anisotropy and Flexural Waveform Dispersion Analysis (open hole
 oth to significant pressure drops and to proppant bridging as fluid and slurry move through the restrictions. New modeling results are presen
 han for other types of intelligent well because it provides a direct replacement for conventional gas lift equipment compressors and pipeline
 d Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performanc
 d. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple fra
 d. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple fra
  or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation?
 i Aramco. Included in the description are equipment selection design and development details installation procedures and “lessons lea
andle effectively heterogeneity or permeability contrasts exposed along the sand face. The ICD controls and interrogates more optimally both
 overy with fewer wells both offshore and on land. Intelligent completions have proven their value in managing production from multilateral we
 ded in the description are equipment selection design and development details installation procedures and “lessons learned after insta
uncertainty. Recently developed schemes which update models with data acquired during the optimization process are computationally very
 rovide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes placed

hinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore it is critical to combine high reso
n about the possible advent and extent of sanding will be helpful in planning for completions and facilities. The study presented in this paper
 re the wells are often stimulated by a matrix acidizing treatment after the perforating.� A prevalent mind set in the industry is that acid diss
mages. A new underbalanced oriented perforating technique has been successfully implemented in Algeria. It combines the use of a formatio
on evolution in infill well at Resak field one of the gas field operated by Malaysia National E&P Company Petronas Carigali Sdn Bhd. Since
n Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated u
eability layers. The shallower layers generally have better permeability and were developed first while the deeper lower-permeability reservoi
 es to improve the efficiency of the fracture job maximizing ultimate production from the well. Wells are frequently completed with multiple tu
niques�will not produce until stimulated with acid.�A new perforating technique has been deployed that creates clean low skin perforati
 r the skin factor can rarely be estimated reliably from pressure data acquired in the current UBP operations if without flowing on surface in s
T on depth involves two CT runs the first to run a memory gamma ray (GR) and casing collar locator (CCL) and the second run for the actua
evability risks are to be avoided. In practice the perforating design engineers do not have a well-established analytical tool to help them unde

p sandstone rock called Berea Sandstone. Four different charge types were tested including one standard (conventional) charge and three d
d the effectiveness of this connection is the result of the perforating system selection the well environment in which the perforating job is exe
 the challenges and successes of reducing produced water by using smart completions and how multiphase flow meters (MPFM) helped in g
 intenance. The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazil’s drive to
 re produced primarily from massive fine-grained Pleistocene reservoirs. These reservoirs require sand control to prevent sand production
i Arabia (figure 1). Hawtah is one of several small fields located along the Hawtah Trend (others are Ghinah Hazmiyah Nisalah and Umm J
s/permeabilities premium screens with shunt tubes in conjunction with cased-hole frac packs have been used to complete the wells. The th
 7 and oil recovery averaged 2000 STB/D. Sand production was anticipated under normal drawdown from production onset and as such the

  This results in low production rate and consequently leads to the requirement of high drawdown pressure. �Hence it is imperative that the
 een attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reservoi

completion technique in these wells which require an effective and reliable sand control for long term and open-hole and large tubular size t
  in two waves commonly called Alpha/Beta packing. The second method utilizes a viscous carrier fluid and high concentrations of gravel in c
lenge. Although scattered attempts have been made to separately understand different parts of the gravel-pack process the industry still lac
 and allows access to larger reserves through fewer wells. Since most of these reservoirs contain reactive shale streaks they require synth
stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surgin
tem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surgin
 Statoil’s finite element modeling method suggests that oriented perforations can prevent sand production in the horizontal wells. This wa
 cated offshore in the North-West shelf of Australia Stag field is a shallow and unconsolidated glauconitic sandstone reservoir with a top and
s well as excellent return on investment for the operator. Screenless completions are an integrated solution that involve many field-proven te

anding potential sanding risk for Sarir and that it was necessary to design and implement a sandface completion and sand management stra
on and disposal and lead to significant economic loss. On the other hand precautionary but unnecessary sand prevention will mean unwarra
om different sources and different domains (i.e. wireline logs laboratory test data drilling data well data and field data) were integrated to g
ailure and sand production. The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and out

 tions is generally assumed to be a two-step process with the shear failure being the first step and the transport of the sand out of the perfo
  sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: 1
 e stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. Th
 es in a hydraulic fracture both in the main flow direction along the fracture and in the fluid loss direction. In our tests the injection rate into th
 ation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern i
excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsifie
 excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsifie
 h coiled tubing in three of these wells and bullheaded in five other wells for comparison between both methods of placement. Pre- and post-
 out 1% halite and < 1% quartz; therefore the formation is a potential candidate for acid stimulation. This limestone is atypical because of its
 tures. Furthermore acid penetration is limited by the large surface area of the horizontal wellbore and this is exacerbated by the relatively s
articular challenge was the flowback of tubing pickling and spent acids and neutralization of the spent acid on the surface. A series of effectiv

 be taken into consideration. The presence of natural fractures makes the entire treatment more complex. Acid placement and diversion nee
on. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two proble


 oduction peaking at 66 000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the pa
e zone with the highest permeability or least damage. Field experiences showed that there is no assurance of complete zone coverage witho
 n financial viability of the well stock. In many areas however production wells do not benefit enough from the water flood or the injection sch
 of injection rate temperature and fluid properties and few have focused on the influence of rock properties on stimulation treatments.� Th
  (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is
d over the past years with varying degrees of success. When dealing with water sensitive formations a common practice has been to use oil
age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different opti
mpletion knowledge by developing and refining more complete interpretation and completion models based on comprehensive data. This pro

enging wells due to the drastic permeability contrast across the pay zones. Typically the treating fluid in a matrix treatment flows into high pe
producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response the relia
  analysis and modeling. A novel approach is taken to develop the analytical solutions and procedures for both liquid and gas wells. Approxim
 ong horizontal well has been drilled in an area interpreted to have high fracture density.� A comprehensive test program including flowing
n logs to; 1) determine the flow rates for each individual stage in a multi-fractured well 2) apply rate-transient solutions that use rate-normaliz
e permeability and skin of individual layers. Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has
 ng.� A similar early-time pressure behavior may be due to the presence of plugged perforations. Drilling problems associated with high m
 is applied to the sandface (beginning of a drawdown or injection) of a well. However the initial pressure propagation is not diffusive but it pro
 s has always been a classical management dilemma.� With the advent of digital oilfield technology the pressure and hence the deteriora
  and production-data analysis. However there exists no study presenting an independent assessment of all these methods revealing and d

essure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended techniqu
eservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of vertica
 able straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods induced
gravating factor is that such wells are often producing at high water-cuts thus leading to significant uncertainty on oil rates. To solve such me
ompositions create unique challenges to the successful acquisition of well test data. The paper discusses the challenges and potential bene

 s-volume-fraction and low pressure unstable flow these controlled conditions are far from reality which can lead to unforeseen errors in the fi
 measurement devices. Multiphase flow meters have been proved for multiphase production metering by many operation companies worldw
 been used to well test and meter mostly liquid-rich flow streams. These models were not developed for the measurement of gas flow rates
s and improve the testing duration and strategy. The program included in addition a set of elements to qualify the multiphase meters results b
put a cut off in the GVF range of 85-92% following the type of technology. These criteria are often based on past experience or special cases
 test analysis in full-field simulation has long been recognized. However only limited benefit could be obtained by reconciliation of the analytic
e and its auxiliary functions can be used to provide the characteristic signatures for unfractured and fractured wells. The purpose of this pape
 es have been used there are valid concerns that smoothing procedures may adversely affect the well-test interpretation. In contrast measu
placed in the boreholes.�The electrodes are partially insulated from the other completion components but nonetheless record high signal-
nt steel and elastomers can be corroded by CO2 and the ageing process will be accelerated by any defects in the cement sheath. It is there
alculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data a borehole wall ele
 s over time allowing migration of CO2 from the reservoir to shallower formations (e.g. aquifers) and/or to the surface. In this paper a risk-b
nd surface models leading to non-optimal solutions due to the non-dynamic integration between models. A recent trend of the industry is the
  complex processes such as dry-out salting-out chemical reactions to the dynamic model. Simulation in these situations is one of few mea
nology targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in u
-free energy sources are developed and viable.�The current options for captured CO2 utilization are; Enhanced Oil Recovery (EOR) Enh
 altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment perf


 nstrumentation and Control System (DIACS) installation worldwide with the lower isolation packer set at 8560 m / 28084 ft measured depth
ngers. The field pore-pressure gradient is at 9.07ppg EMW but mud density needed for wellbore stability is greater than 11.6ppg. This resulta

an 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only five
ormations containing CO2 were discovered in North of Mexico. The Quebrache region contains several occurrences of natural CO2 that hav
uation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin high-qua
 portion of condensate liquid will remain in the reservoir and will not be produced. Many condensate reservoirs have been producing with v
 nal implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selecte
 The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to shu

 olved evaluation of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cemen
 restricts considerably the convoyed down-hole tools configuration � This paper covers water shut off case history of an oil producer that h
ediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result most exploration and p
 le to perform mechanical water shut-off in open horizontal well as inflatables are quite sensitive to be set in open hole. This paper shows th
methods in this field. Dual injection combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water pro
bon production and results in large amounts of produced water that need to be disposed in an environmentally friendly manner. Some fields
 es more challenging for horizontal wells with open hole completion. Well A a horizontal open hole producer with 2 440 ft of reservoir contact
altene wax and hydrates) precipitation and their potential to disrupt production due to deposition in the near-wellbore regions and production
 ocities ranging from 0.025 to 1.75 m/s. Data were acquired on flow patterns pressure drop phase fraction and droplet size as a function of
“5�). A total of 324 tests were conducted in a 0.0508-m (2-in.) ID 21.1-m (69.6-ft) long test section using tap water and mineral oil with sup
n optimization and back-allocation of complex well configurations such as nodal analysis work only for a static problem.� They cannot a
 he oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constrai
ors that create significant impact on field development planning especially when dealing with marginal deposits having varying fluid characte
production method design for development of offshore fields. In this study fluid characteristics and flow assurance aspects of a live waxy cr
  s weakening the resistance of those seals and compromising the integrity of the fluid samples and the safety of equipment and personnel.
eservoir fluid. In a number of reservoirs around the world carbon dioxide (CO2) is a critical gas composition. Examples from two such reser

 nt pressure of the reservoir fluid changes in the surface yield of condensate as reservoir pressure declines and changes in the specific grav
volume factor Bg) were investigated. According to our knowledge no other correlation for calculating oil-gas ratio exists in the petroleum lite
nt of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent; a
ng correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to correlat
wo primary factors that cause major and expensive differences between predicted and actual performance in the oil field. Furthermore differ
 nalysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environme
   Analytical as well as numerical models reported in the formation testing literature rely predominantly on simplifying assumptions in terms of
GOR fluorescence apparent density fluid composition (CH4 C2 C3-C5 C6+ CO2) free gas and liquid phases detection saturation press

 and low mobility sections a new focused sampling device was utilized for effective formation testing and sampling purity. One case history d
sibility of a project and determining if an offset discovery can be produced without a facility upgrade can economically make or break a proje
e with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many sam
ble to assess the phenomenon. Individually geochemistry downhole fluid and mud gas analyses have provided valuable insights into compo
sult there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extremely
erties. Conventional wireline triple-combination measurements showed that the interval of interest was uniform and free of noticeable imperm
  pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy and identification of in-situ fluid type can be difficul
ory analysis. Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density fluid contacts and layer conne
 contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample pressure/volume/temperature (PVT) prope


eady state conditions. Montel et al. (2002) discuss processes that arise from recent charging of these reservoirs which are not in equilibrium
wever hydrocarbon differences can be identified reliably only when the significance of uncertainties from measurement and the oil-based mu
alysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environment

 dependent K-values.� Although these procedures may be extended to more general N-phase systems the paper gives full details for a 3
perate heavy-oil production systems knowledge of the realistic viscosities of the emulsified heavy oil under the actual production conditions




y mud-filtrate contamination which introduces errors into the laboratory measurements of fluid properties and requires analytical methods to
nsures it is clean. The reservoir fluid is then captured in sampling bottles or chambers. Gas-condensate sampling has always been the trick
ea in recent years arguably being the multiphase environment. Multiphase flow meters have been accepted for several years now by the indu
y the difficulty to separate the phases.� Furthermore in-line multiphase flowmetering brings significant benefits to the ease of deployment
timately stop the reaction of the acid with the rock. Recently chelating agents have been introduced as stimulation fluids. The advantage fo
 emperature complex mineralogy poor consolidation and a wide range of sources of potential formation damage make any stimulation a ch
 particles that damage the porosity of clean sandstone cores (in core flow tests); the study includes reactions carried out under controlled con
kages to production and process systems requiring remedial action often on short notice. Current commercial halite inhibitors are only effec

 tions were carried out to verify the growth of naphthenate-soap particles under different pH conditions. Core-flow tests were conducted to ge
e. Additionally the impact stresses plus the outward traveling shock wave severely weaken the rock matrix by de-bonding the cohesive inter-
 ock fabric. Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity thoug
 lar and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention no succ
 gal). However these design criteria and formulation of the scale treatments had to be changed significantly to be effective in the typical Uinta
n real time analyse data make decisions and modify the completion without physical intervention to optimise reservoir and asset performan
 ng wells. Injection seawater (rich in Sulphate) and formation water (rich in Strontium ions) mix in the reservoir and/or wellbore under varying
 cale but in practice concentrations < 5 ppm are adequate.�Investigation of the produced brine compositions has revealed that this is du
 atch in a particular region may adversely affect the match in other regions. Full independence of regions within a reservoir is not possible un
 diting history matching of simulation project. The objectives of the study are to improve the history match by validating fracture lineaments a
of thousands to millions of cells incorporating large amounts of field and well events over substantial operation periods be they historical (i.e
 the design and intelligent well management is key IOR option to Cantarell’s late field life management. This paper presents the results o
e management tactic to monitor the field and to select candidates for workovers.� However the large number of wells in AIB (approximate
er injection (WI) and WAG pilots to test the recovery strategy. The pilot employs advanced geophysical and modeling tools to measure forma
  the reservoir to assess the efficacy of various courses of action and most significantly adjusting various teams’ “key performance i
ation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones electrical submersible pumps (ESPs) beca
 es of the reservoirs in the Faja are relatively high in the range of 600 to 1 500 psi with viscosities typically greater than 2 000 cp. For the abo
 API) Garzan (12 API) and Camurlu (18 API)) in south east Turkey were used.� Using a novel graphite core holder packed with crushed li
essary. This project covers a feasibility study considering the Horizontal Alternating Steam Drive (HASD) process geared to increase the rec
  prone to lost circulation. First few horizontal wells were drilled with traditional technology of positive displacement motor with Silicate mud. M
reservoir characterization in the steam flood pilot area will improve our understanding of the range and distribution of formation properties wh
 luid samples are obtained by setting a rubber packer and small diameter probe. The packer hydraulically isolates a small part of the formatio
ng and sand production. In his circumstance CNPCIS set itself a daunting task of tripling the production in less than a year. Horizontal wells
  and misses targeted oil zones. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low v


 ves and large efforts have been spent to overcome difficulties related to this kind of oil production. Venezuela has pone of the largest reserv

 l sandstone acidizing treatments is that the success rate is generally low due to the uncertainty associated with the fluid-formation interaction
  n are reducing reservoir and fluid uncertainties confirmation of technical and commercial feasibilities construction of a pilot gas processing

er we have studied the effects of gravity using experimental data available for five live oil and condensate systems (at high pressure and tem

e shear degradation early crosslinking in the tubulars can substantially reduce the final gel strength even to the degree that near wellbore p
nmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully apprecia

 ows to optimize production and flow above dew point in deep high pressure and high temperature wells where intervention is very expensive
 s placing over 3 million lbm of proppant with a success rate greater than 85%. The wells targeted were both injector and producer wells. The
n developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms the new sandsto
m 2% to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using corefloo
 e fluids are known to generate undesired effects such as uncontrollable height growth significant proppant pack damage lengthy clean up ti
 high temperature. Adsorption/desorption characteristics of these chemicals and temperature stability are also investigated for long-term pre
 ng. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures current practice involves

contact area offers a potential for enhancing well productivity and overall well economics additional stimulation is usually required. Conventio

scenarios for completions and drilling locations can be systematically and rigorously analyzed. Case studies from North America and the Mid
ckage. One well employed techniques standard to the area –while some experimental fracture techniques were tested on the other. A gene
 r. That information is not less critical for infill drilling fracturing �old� wells re-fracturing fracturing of sidetracks and the knowledge of h
  some cases microseismic monitoring campaigns are performed in these various low permeability environments to improve the understandin
 fractures as their heights grow which results in high water production and a subsequent significant reduction in produced gas. An integrated


 pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technological
onsists of fine-medium feldspar-quartzite sand lithic feldspar-quartzite sand the pore type dominated by inter-granular small inter-granular a
quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary methods.
imulation workflows were employed to build a 3D flow model from geology geophysics petrophysics and engineering data and interpretation
d fracturing treatments response.� The SWM is coupled with the development of NPV optimization models for each well.� Tools for the
cy range. The overpressured reservoirs become economically viable only by hydraulic fracturing. Two major challenges of modeling the field
sure to avoid non-economical completions continues to leave hydrocarbons bypassed. Using recent advances in logging technology and prod

arned from the use of an optimal dataset in addition to a workflow on fracture characterization for tight deep carbonate reservoirs in Kuwait. I
ntinues to rise. It requires an effective solution to significantly reduce the largely extended rig time due to heavy WFT programs and operation
actures plays the same role in improving the flow mechanics. As an industry there are many tools available which characterize the propertie
 sults for a wireline pressure data collection campaign on twenty wells where more than 120 pressure measurements were taken in the Wam

ce level of the final pressure is often uncertain. These issues are painted on the ever-present backdrop of supercharging that can limit the da
  poor drilling success thus the operator invested in 3D-seismic acquisition and an integrated multidisciplinary reservoir modeling and simula
ess with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and north Louisiana. Horizontal wells are com
 than 600 m3 oil per day. The article describes efforts made on a new exploration approach elaboration based on an integral analysis of the


 ts. To use openhole sampling tools for these flow measurements it is essential to differentiate between water-base mud (WBM) filtrate and

 mations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of la
  the company’s true financial performance in comparison to quality safety environmental concerns and other factors. When nominal fa
on-making it is possible to improve quality of critical decisions. Different technique can be used to elicit judgment from individual experts and
 l Company (K.O.C.) in the Burgan Field Kuwait it became apparent that there was a need for clearer and better quality real time log informa
orehole nuclear magnetic resonance (NMR) has been demonstrated to provide pore size distribution information and methods exist in the lite
 al radius of investigation but very poor vertical resolution. Constructing an appropriate simulation model requires rescaling the data and tha
porosity system is illustrated by strong leaching (i.e. dissolution) overprinting the primary interparticle porosity of a grainstone and responsibl
he help of image logs and cores and other available data set. Data analysis and integration of borehole images in 9 wells of the study area pr
 ineation and prediction of the best quality reservoir facies so that optimized exploitation of the reservoir can be achieved. This paper describe
  ptical spectroscopy which can provide estimates of filtrate contamination gas/oil ratio (GOR) pH of formation water and a hydrocarbon com
  ng correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to correla
ntional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating di
 with complex mineralogy varying water salinities across the field which makes the visualization of a conceptual geological model in the pres
  likelihood that measurements will be made before the onset of significant invasion. The colocation of resistivity- and neutron-based sensors
 towards the reduction or even elimination of the use of chemical sources where possible. A new Logging-While-Drilling (LWD) tool has bee

 a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly used
work a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly
om borehole NMR logs and electrical images and have earlier studied the relationship between NMR T2 distributions and capillary pressure
 nits. The basal sand syones are often shaly and silty. The sandstone porosity value range from 9% to 26% with typical values being from 22%
 e highly altered by diagenesis.� Vugs are developed in several intervals.� Computation of permeability from porosity alone yields scatte
 e applications of NMR borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology the geometry a


 . Difficulties will arise when anisotropy is not caused by sand-shale laminations when no sand-shale point exists or when the nearby thick s
ed to be considered in resistivity log interpretation. In this study LWD resistivity modeling work was conducted to study relationships between
 ough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of critic
Many deepwater reservoirs comprise of young turbiditic formations which even at great depths remain unconsolidated or only weakly cement
 or drilling-induced origin. Cross-reference with cores from the same sections allows such discrepancies to be reconciled: in an example case
 rth and north-east of the main Khafji Structure in Tayarat Formation of Late Cretaceous age. The present study utilizes twenty two well data

not always make an accurate inference of reservoir properties from well-logs to a reservoir model because of the stationarity and ergodicity a
 ives: identify the layers that may contain hydrocarbons verify productivity and fluid types with formation testing and sampling calculate net
heir detection. NMR vertical resolution is mainly controlled by the antenna aperture that is in the case of a high-resolution antenna 6 in. or 1

reasons for these inaccuracies generally originate from the traditional practice that LWD depth is purposely made equal to the driller’s de

 on and waterflooding. Long-term injection into these wells can result in the creation of fractures that grow over time. The effect of fractures o
 n groups viz. elastic parameters strength parameters and in-situ stresses.� Even the profile of in-situ stresses with depth is estimated u
 lling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stress
nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well c
nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well c
nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and well c
 aults have facilitated the flow in the Jurassic reservoirs. Identification of faults and associated fractures mainly has been on the basis of 3D-/
  physical analysis for better fracture characterization and selecting the best perforation intervals for a producing well. This workflow is applied
wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complete integrated a
  ld is now critical to optimize infill drilling and produce the remaining reserves. The present paper focuses on the characterization of different
   potential of wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complet
phase flow properties such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water in
 us reservoir on a typical log analysis can lead to incorrect assumptions about the economic value of the hydrocarbon discovery the productio
 one layers using oil based mud systems. To further investigate possible near formation alteration an extensive evaluation program was unde
 ffected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characteris
able for sampling and NMR logs are used to gauge if permeability is sufficient for a sample to be taken. However these logs are not able to c
e observe effects caused by the drilling process such as gas dissolution in OBM filtrate and time-lapse effects between LWD and Wireline l
evitable for any given NMR technique. For example the overall acquisition time is dictated by operating at reasonable" logging speeds so fu
 e general readership of recent advances in various areas of petroleum engineering. Introduction This summary of the state of the art in n
 gical complexity of the Estancia Cholita Field which is mostly due to limited lateral continuity and small reservoir bed thickness particularly in
d to better characterize fluid flow in horizontal wells. Advanced sensors provide better resolution among gas oil and water and cover more c

 of this paper is to present (1) how to use the inflow data for the evaluation of formation properties and (2) how to cope with the uncertainty
 permeability ranges between 0.001–17 mD. The oil in the Mishrif is highly viscous and production is normally enhanced by fractures in the

ssure analyses provide valuable insights into reservoir architecture. Each analytic method relies on different fluid traits and has its own limitat
xico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in the
  An extension of the conventional Selective Inflow Performance analysis is presented in this paper to obtain estimates of the formation and
nd eventual improvements in ultimate recovery. The recovery strategy for As Sarah oilfield in Libya has been based on SCAL. PND logging
 bearing formations translates into lost productivity while perforating water zones can have detrimental effects on well performance. Moreove

ze recovery. Permeability and permeability anisotropy at different depths are unknown variables that affect well completion and reservoir man
  effect. We present an algorithm that takes into account the supercharging effect in analysis of pressure transient tests acquired with a sing
 The process specifically involved first generating a series of unconstrained production options which then considered drilling reach and anti
 m (dynamic information) may impact significantly the estimation of reserves and result in the termination of the project during the appraisal p
 the Bokor Field offshore East Malaysia.� A brief description of each methodology is outlined potential benefits and challenges are discus
 with other options in a company’s portfolio of investments. The re-development project presented in this and its companion paper1 (SP
  Sarawak East Malaysia. The reservoir sands are highly unconsolidated at the top of the structure and gaining consolidation with depth.�
 gy to maximize the net sand delivered from each well. The drilling of development wells in sand stringers involves very thin and sinuous targ
nty. The integrated reservoir management team has utilized the geological and seismic impedance to locate a power water injector in the so
e low-pressure area and additional wells highlighted by the Moving Domain study.�Compressors were installed on successful test candid
ntation work. Scalable to any given size of hydrocarbon prospect and number of infill wells the computational method incorporates cross-dis
 oduction can occur over the lifetime of the field. Falling reservoir pressures cause not only a drop in manifold pressures and the need for arti
well interventions(coil-tubing operations) leading to better reservoir management.� To evaluate the intelligent completion technology an I
 ages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and su
  must be given to operating constraints including cost handling capacities compression requirements and the availability of lift gas.� In tr
h confirmed that A6.0 reservoir unlike all others in the field which co-exist within a stacked sequence is surprisingly isolated from the surrou
 these opportunities reducing the risk on oil recovery associated with the various enhancement initiatives. The objectives of this paper are to


teps to set up a SRM and IAM are presented in this paper. The steps are described in context of an actual field operation. A WAG cycle optim
at has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 60k
he oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constrai
e than 20 years have been generated within one year. The three main enabling technologies for the rapid execution of integrated studies ar
ng. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated b

 ments associated with exploration and drilling new wells as well as commissioning new facility expansions Production Optimization and de-b
 ral locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development prog
s is the dynamic integration of historical data and new information technologies and engineering diagnostics to systematically identify laye
gh drilling and completion cost but also due to the high risk and uncertainty involved in the process. To make wise investments in such a diff
 s a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo simulation to appropriately value fut
 easurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while d
 nds on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoir to
cribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach p
er and its size with a set of simulation models to assist with well placement decisions. In the South Timbalier 316 block a delineation well
 The approach provides a filtering concept to select all wells that might have bypassed reserves in their drainage area and provides a step by
oirs was widely ignored. These effects are related for instance to interference phenomena which directly impact the optimum number of infill
on the concept of surrounding the wells whose locations have to be optimized by so-called pseudowells. These pseudowells produce or injec
ytical models1 2are mainly dedicated to describing the ability of a reservoir to drain heated oil and do not depict all details of real SAGD proce
n of the point source solution can be performed to calculate the average bottom hole pressure of a well. These equations are applicable to
e flux fields is governed by a Volterra integral equation. Within a multiple layer reservoir scenario our semi-analytical solutions are applicable
tivity coefficients that define the relationship between reservoir properties and the production response typically depend on either the number
 ystem of equations backward in time per each forward time step which is usually of high magnitude in case of field scale applications of long


 efficient. In order to circumvent this problem a set of multiple geologically plausible permeability realizations or the training images for a give

 ass equilibrium equations for component mole fractions saturation temperature and pressure using the Newton-Raphson method. External
  and speed. Here we describe an efficient natural-variable-based general formulation approach which handles general partitioning of phase-
 is composed of interbedded shallow marine-ridge sands with some coarsening-up sequences. A typical horizontal well in this field has perfo

  result in special wellbore flow dynamics. In addition technologies such as intelligent completions can be used to regulate flow from various



 iques: Empirical Fetkovich Locke & Sawyer and Analytical Transient solutions for oil and gas wells/Reservoirs using a production surveilla
 t single-well model was applied to study the important parameters involved in the fracture-cleanup process. This three-phase 2D model prov
process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one r
 ing. As such pressure transients are often used and can be successful tight reservoirs where transient flow regimes can be used to observ
etter and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for th
n such formations. An interfacial slip model has been developed and implemented in a pseudo-three-dimensional (P3D) hydraulic fracture si
 roduction rates to evaluate the profitability of fracturing. The availability of analytical software that is simple and fast has been the rationale f
nless conductivity and the inertia resistance factor. However based on the parameter matrices of their numerical analysis restrictions were a
  ost probable description of the reservoir/completions. After validating results with a numerical reservoir simulator we systematically used th
 g boundary-dominated flow have been made using a mathematically rigorous model for pseudosteady state flow.� This model has been u
gh operational problems have been solved this way the net pressure response while successfully fracturing did not obey any of the existing 2
w fluid flow along the fracture trajectory and 2D equations of the linear elasticity for rock massif. The model predicts and evaluates the near-w
 dy we can conclude that ANNs that use radial basis functions (RBFs) can decrease the error of the prediction effectively when there is an un

erogeneity leads to the use of fine gridding especially in the vertical direction to accurately simulate the fluid flow in the reservoir. Third the la
alculation is proposed and an analytical solution is derived on the basis of some realistic assumptions. The analytical solution can be used to
nd injectivity index (II) are not particularly useful when the mobility ratio is high since they require the use of a nominal drainage radius where
 ed. This study shows that proper integration of all pressure production and geological data is critical in defining reservoir compartmentalizati
material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir eng
 n pressures become unavailable. Well logs and well tests can be missing if not properly archived. Moreover the data may be complete bu
 without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are p
  experimental design workflows and the different methods of generating response surface models for reservoir simulation studies there is a

 olution matrix is discussed and a version of the method that provides an M-matrix is described. Convergence and numerical flux consistency
e obviously unable to reproduce spatial condensate distribution in near wellbore zone of the reservoir but after proper tuning these models ca
ation. The simulation of oil production from triple porosity reservoirs requires the development of composite porosity composite relative perm
However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited ap

on of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases. Flow simulation of f
 ctures one. It is also assumed that the flow occurs in fractures only i.e. the matrix permeability is equal to zero. Mass transfer between mat
  regard to accuracy and computational efficiency. We present a new simulation approach based on streamlines in combination with a new m

 that this is incorrect. With a correct implementation of the RML method within a Bayesian framework we show that RML does an adequate j
 ure increase on scale precipitation it is only recently that a body of work has been developed on the impact that the dynamics of brine mixin


 saturation transport using adaptive mesh refinement (AMR) along streamlines is investigated. The refinement strategy is based on the multi-
hnology maintain its better scaling ability than traditional finite difference/volume technologies. However we went further and have treated the
plex in setup and computation. The presented workflow is a new approach to infill well performance prediction that combines speed and reas
 s is required for implementation of the EnKF. Moreover data are assimilated (matched) as they become available; a suite of plausible reserv
 tic case. Geostatistical simulations involve generating multiple equi-probable fine scale depictions of the reservoir heterogeneity each hono
el together with considerations to ensure that the resulting equations have a Jacobian matrix that is invertible and explain the necessary mod

 d on geological and engineering data led to 24 isolated segments for which up to 24 separate simulation models can be potentially built. Bec
 g technique that can provide a continuous wettability log. A detailed analysis of a new model for the conductivity of reservoir rock called the â

 ayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005. To properly assess all the arguments
s in the pressures of the invading mud filtrate and formation oil to result in the following unusual yet often observed behavior: 1) negative pr
Lekhwair in the Thamama limestone. Commercial production from the field commenced in late 1984 with good performance being attributed
 log data base viz. electrical Images and sonic logs. In vertical wells the maximum tangential stress around borehole can produce breakout
e beyond reservoir well process and production management.�What may not be so clear is how to apply these smart technologies to m
 rted to develop in direction of sweep efficiency improvement by cheap agents. Nevetheless by now the very intereresting EOR experience ha
  had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States. Alaska’s North Slope started prod
ely simple situations that require a simplified set of input data. In these cases the results are consistent with those of finite-element models. M


passed oil all the wells were logged using a through-casing formation resistivity tool. One well was also surveyed with pulsed neutron captur
was drilled and completed in the Oseberg S�r field in December 2005. The solution combines hydraulic flow control valves with advanced
nd reservoir properties in these formations. Water injection was implemented in Mauddud Formation in late 2000 after a successful waterflo
ost and poor data quality at low flow rates this technique was abandoned after initial logging efforts. Development of a state-of-the-art elect

 time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double
 time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double
 support maintenance. In this well a multi-reservoir dual gauge system was deployed to monitor pressure and temperature in two stacked car
mation fluid being pumped through the tool flowline and the relevant visible wavelengths in an optical detector are used to record the dye sign
 n (s) and current average reservoir pressure (Pave); the KPIs are summarized on a quarterly basis and compared with historical trends to ch
smic interpretation were used to provide the operator with recommendations for reservoir management such as drilling patterns new well pla
 reatments where excessive height growth is believed to have occurred premature screenouts are usually the result of insufficient fracture wi

ntly installed optical fiber along their first Joslyn SAGD production well to monitor the temperature profile continuously during startup and prod
he well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well.� Sub-c
e in the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well. Sub-
 eted with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This comp
 er. Upon well start up oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer pres
anent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements withou


 l the data needed to monitor process parameters and fluid production under the assumption that deviation from any target would be detecte
 w oil flows? This paper explores this question by analyzing production logs from wells with water cuts as high as 99%. The horizontal well e
mited information is available concerning Wara reservoir heterogeneity. Shut-in of all Wara producers provided an “once-in-a-lifetime opp
l rate of 1 800 bbl/d. Oil production quickly dropped to 1 000 bbl/d and gradually declined to 200 bbl/d. During this period the gas oil ratio (GO
 n of investments to optimize wells/fields production and gave production/reservoir engineers a good hand in obtaining better data for decisio
val pressure-transient testing (IPTT) and microfracturing. Because of the complex tool strings and the elaborate operational aspects involved
nique allowing individual layer pressures or gas/oil ratios (GOR) to be monitored continuously during production. The technique employs the
voir. Integration of the microseismic data with volumetric strain inverted from the measured surface deformation indicates a discrete deform
these systems to monitor production rates and changes over time. The optic fiber has been installed on the periphery of the sand-screen sh
ssed these constraints. Instead of individual gauges on mandrels digital sensors were miniaturized and distributed along a single spoolable
nes using conventional openhole logs. This paper describes a methodology of recognizing the different types of thief zones in the Mauddud c

  of the reserves estimates. With current Digital Oilfield technology it is possible to measure production volumes at the well level and at interm
 ing have addressed these fundamental requirements of measurement with multiple probe technology that differentiate between Oil Holdup (

acquisition which is extremely instrumental to take an immediate decision. The technology is well known in the industry and already proven b
methods have been limited by the injection volume and environmental effects. Direct spatial measurement of the injected sea water front with
d proven in other geographical areas is being implemented first time in UAE. The EMI technology is being deployed in southern part of a com
nfluence of a high quality background geologic model in constraining the interwell results and providing a higher resolution image of the ongo
 rom CBM reservoirs is low perhaps 50-100 mcf/day. Various completion methods are being evaluated and new technologies are being deve
 ayers but the nature and extent of cleating often remains poorly defined from these logs and by using standard log evaluation methods. A C
  to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed m
 e challenges faced in horizontal completions. Inefficient fracture initiation is the largest reoccurring problem encountered when completing h
n of high stiffness significant elastic anisotropy and coupled elastic property and horizontal stress development in tight gas shale reservoirs
 ¿½ Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). Effo
 acterized and the perforation placement customized to account for reservoir changes along the wellbore.� In most cases evaluation is lim
 ts guide the design of horizontal wells to control hydraulic fracture directions and intensities. Conventional logs and cores have been used to
ation of steam within the reservoir and the resulting flow of crude. SAGD recovery methods require tremendous amounts of steam in order to
 eral readership of recent advances in various areas of petroleum engineering. Introduction Annual natural-gas production from coalbed- an
oved to an aggressive horizontal drilling and completion program.� Additionally in an effort to increase the productivity of existing wells and
   the flux through the thin wormholes can be so high that high pressure gradient occurs. Therefore the optimized wormhole geometry should
h no anticipated fines production low GOR low temperature low bubble point pressure and high API gravity. All new installations were carrie

nd operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift system
  of horizontal drilling allowed achievement of the above tasks.� Horizontal completions resulted in not only enhancement of individual well
on rates of each well to more than 1 MMm3/D �increased the associated sand production risk and led to the need for evaluating� the be
mpletions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well w
oductive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally on
 ritical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly fro
 ritical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly fro
 rough the well architecture.� To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reservo

 m coupled with pressure and temperature monitoring system. The SC provides isolation and down hole control of commingled production fr
allow production and injection control over multiple zones have become available. The central idea is that downhole control may be used to a
 dvanced system coupled with a pressure- and temperature-monitoring system. SC provides isolation and downhole control of commingled p

ults of a numerical study performed to determine the production performance of dual opposed laterals compared to horizontal wells. With a to
andard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the abo
 rical source of statistical bias. The analysis uses Kaplan-Meier (KM) (Kaplan and Meier 1958) and Cox proportional hazards (CPHs) (Cox 19
n used successfully to increase production from the Khuff carbonates. Although acid fracture treatments create significant conductivity enha
  based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydraulic
ompletion techniques have been tried since the start of the play with different degrees of success. In June of 2005 a new technique was intro
based on net pressure control. This can be achieved using low-viscosity fluids such as viscoelastic systems oil-based systems or reduced p
 aximize well productivity. Alternating stages of polymer pad with diesel emulsified acid for deeper penetration and in-situ gelled acid a polym
o be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and high
g nonionic to amphoteric microemulsion and oil-wetting components. Determining the best additive for a specific reservoir is not a simple m
ons on fracture geometry and proppant placement (Smith et al. 2001). To expand on this topic we consider the combined effects of modulus
 one commingled completions the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity and fluid
 e complex chemical make up than before. Therefore the usable lifetime of the recycled water is shortened or requires expensive cleaning o
 lopment of a basin.� Numerous completion strategies (Limited Entry high rate limited entry and various Pin-point Stimulation Technique
 nterest. This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole to
  g fracturing fluid systems to control fracture net pressure development that combined is used to mitigate fracture height growth. The method
o stimulate long openhole sections effectively due to poor acid distribution especially in reservoirs with high permeability streaks that require
sm is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operation.
s where oil and gas are found in tight formations fracture stimulation needs to be added to the equation. Conventional multistage fracturing t

 be drilled as open-hole horizontal completions. Nonetheless due to the highly complex nature of the Khuff carbonate reservoir some wells h


GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery p
of well and reservoir completion under boundary-dominated flow conditions has been developed and utilized in this study. The mathematical

West Siberia. Adding the difference in the maturity of the fields with significantly depleted reservoirs high asphaltene and paraffin oil content

 of valves to be placed in a single well without incremental reductions to the ID thus allowing normal cementing operations. A control line is c
 aper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept b
ate model for fracture design which takes into account processes in the plastic zone for the special case of soft rock that is a cohesionless g
has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico.�The fluid exhibits enhanced f

 ature (BHST) of 190oF.� Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive


ends to produce oil with asphaltene content when the flowing bottomhole pressure is drawn below the Asphalting Onset Pressure (AOP). An
estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 2002
w wells are completed.������ This paper discusses the completion design methodology execution and results from two off

nverted fracture azimuths. Furthermore if the positions of the injection point and the receiver array are not known accurately and the velocity

 cturing or about the dependence of this texture on the acidizing conditions. To study this important aspect of the acid-fracturing process we
  a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model w
 he transportation of radioactive materials have impacted the application of this technology in international markets. This paper will describe

 e and is additionally hampered by the lack of or ambiguity in the reservoir and production data. This is particularly true for the Yamburgsk
 de lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing.
 er the situation is still unclear in high permeability formations because the formation fluid can invade the tip zone where the pressure drops
  pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressure
ertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under boundary
 ntation was supported by differences in the microseismic-signal characteristics and the treatment-injection data. This difference in fracture g
a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion method.
 s to fracture reopening along the initial fracture plane (called in-plane frac hereafter). A dual-frac PKN model is developed to predict the grow
amages in elastoviscoplastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydrau
  proppant are used. Although the latter could lead to more conductive fractures they could also bridge at the wellbore impeding both lateral
gth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented in
 on campaign started with three water injector wells. The initial results were not as expected i.e. after pumping 1000 bbls of treated seawater
 eform Dispersion Analysis (open hole and cased hole) which main objectives consisted on the generation of a horizontal stress map for the s
 ns. New modeling results are presented that quantify these and other effects of offsets by using a coupled 2D hydraulic fracture model. Offse
quipment compressors and pipelines and the ancillary equipment they require. An estimated 60 auto gas lift systems have been installed a
n the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing these
 he operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficient f
 he operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficient f
applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producing h
 on procedures and “lessons learned after installation of the fully hydraulic tubing-retrievable advance completion system with digital perm
 and interrogates more optimally both rock and fluid properties in the reservoir hence delaying early water breakthrough. This early water bre
naging production from multilateral wells horizontal wells with multiple zones and wells with heterogeneous reservoirs using a single wellbor
 and “lessons learned after installation of the fully hydraulic tubing-retrievable advanced completion system with digital permanent down
on process are computationally very expensive. We suggest that simple reactive control techniques triggered by permanently installed dow
ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure p

 fore it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the product
s. The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depleti
nd set in the industry is that acid dissolves the perforation debris and creates wormholes that bypass the perforating and other near wellbore
eria. It combines the use of a formation isolation valve (FIV) to keep damaging completion fluid off the formation immediately after perforation
y Petronas Carigali Sdn Bhd. Since the beginning of Resak Field production coiled tubing has been used to perforate numbers of infill wells
ctivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amou
  deeper lower-permeability reservoirs have been developed more recently. The lower-permeability reservoirs are generally of lower porosity
 frequently completed with multiple tubing strings (up to four in some cases) sensor lines control lines or other hardware that can be damag
 that creates clean low skin perforations�and allows the well to be produced at commercial rates while waiting for the multipurpose barge
 ons if without flowing on surface in sufficient time. The reasons are that (a) the flow rate after an UBP continuously varies during the surge; (
CL) and the second run for the actual perforation. The underbalanced condition calculated based on wellbore fluid displacement is often deem
hed analytical tool to help them understand post-perforating behavior of perforators. They have to rely on their own experiences and previous

ard (conventional) charge and three different designs of reactive liner charges. Among all charges the only difference of note was the design
ent in which the perforating job is executed and what happens to the perforations after shooting and before they are used for production or in
 ase flow meters (MPFM) helped in getting better results to allow faster decision making. In one of the challenging areas in Ghawar field whe
 ey component of Brazil’s drive to achieve petroleum self sufficiency by 2006. Because of the challenges presented by the heavy oil and
d control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high-rate long-life comp
 inah Hazmiyah Nisalah and Umm Jurf). The Trend runs approximately 30 km east to west and 50 km north to south. Production in Hawtah
n used to complete the wells. The third well A1ST1BP1 was completed using the same techniques as were used successfully on the first tw
m production onset and as such the well was completed with sand-control measures in place. After about ten years of production a significa

re. �Hence it is imperative that the filter cake be removed uniformly to ensure lower drawdown pressure and even flow distribution throug
s of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted for

 nd open-hole and large tubular size to minimize friction losses. Until now standard open-hole gravel packing was the common completion in
and high concentrations of gravel in conjunction with alternative path screens which mitigate problems caused by unpredicted downhole even
vel-pack process the industry still lacks a tool that accurately models the complete process and aids in successfully designing these jobs. Th
 ve shale streaks they require synthetic/oil-based drilling fluids (S/OB). Considering that the openhole gravel packing in the industry deals p
ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the connec
ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the connect
 uction in the horizontal wells. This was offered as an alternative to mechanical sand control in the long horizontal wells due to traverse sever
 c sandstone reservoir with a top and bottom sealing shale. The reservoir pressure is low and it contains heavy and viscous oil of 19� API
ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing r

 mpletion and sand management strategy for more than 400 wells in the field. It was decided to apply a particular systematical approach term
ry sand prevention will mean unwarranted reduction in productivity. Reliable sanding prediction analysis thus provides a basis for designs tha
a and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths an
nes obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. Wa

ransport of the sand out of the perforations and up to the surface being the second step. Existing sand production prediction models have f
data required for the study include: 1) in-situ stresses including magnitude and orientation and formation pressure 2) mechanical and petro
tic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structure
. In our tests the injection rate into the fracture is much higher than in many previous tests and the fluid loss flux is controlled to match field
 temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple s
 and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exces
  and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exce
methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In one
 s limestone is atypical because of its texture—a granular aggregation of carbonate particles poor cementation and a moderate-to-low roc
 his is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse formation damage
 id on the surface. A series of effective methodologies for the stimulation of offshore multi�layer sandstone oil reservoirs was implemented

 x. Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor to
acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity their low dissolving capa


 ne Darcy. At different times in the past attempts were made to hydraulically fracture one or more of the sands using a variety of different (w
 ce of complete zone coverage without proper diversion. Therefore diversion is recommended in all treatments especially in extended reach
m the water flood or the injection scheme is not optimized.� A consequence of reservoir pressure depletion is the increase in filtrate leak
 ies on stimulation treatments.� This study primarily explores the influence of pore scale heterogeneities on stimulation treatments.� So
 rstanding these basic differences is essential to a successful restimulation. In the past candidate selection methodology has focused on un
common practice has been to use oil-based fluids. However fluids of this nature can have detrimental effects on gas zones with low reservoi
oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. It
sed on comprehensive data. This process includes the current service standard of design execution and evaluation but goes far beyond b

  a matrix treatment flows into high permeability sections and/ or high water saturation thief zones" resulting in higher water cut due to the ove
y management. In response the reliability of these tools and their interpretations for determining the existence of poor behind casing cement
 r both liquid and gas wells. Approximate solutions for the early-time and late-time pressure behavior are derived from the rigorous solution a
ensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) log
 sient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods 3)
 g Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia Bentiu-2 and Bentiu-3 formations. These fo
 ing problems associated with high mud losses when the well encounters fractures often prevent well penetration of the total formation thickn
  propagation is not diffusive but it propagates like a wave with a finite speed. If we have a pressure gauge at a distance we will only start to
 he pressure and hence the deterioration in well deliverability can be continuously and cost effectively monitored.� This paper illustrates ho
of all these methods revealing and discussing specific features associated with the use of each method in a unified manner. The algorithms

 analysis is a recommended technique for fracture evaluation but its use is still not well understood. Analysis of pressure transient data prov
  reservoirs is the presence of vertical heterogeneity and varying layer flow properties. Wireline formation testers have been commonly used
ngle or multiple flow periods induced using a downhole pump followed by a pressure buildup. The objectives of a MiniDST are sampling est
rtainty on oil rates. To solve such metering challenges with a large majority of their wells operating above 95% gas fraction under metering c
es the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siberia

 an lead to unforeseen errors in the field. Recent experience shows that in certain conditions the various types of multiphase flowmeters reac
 y many operation companies worldwide. However in artic environmental conditions like those of Yamburgskoe gas-condensate field with lo
 the measurement of gas flow rates particularly those of wet gas. A new interpretation is described that allows a traditional multiphase flowm
 ualify the multiphase meters results before use and considered parallel testing with conventional separators to allow fair comparison of result
  on past experience or special cases which could be several years old. A split in terms of naming is even commonly accepted in the multiph
 ained by reconciliation of the analytical well test model with the numerical full-field model. We present a more complete approach where a m
 ured wells. The purpose of this paper is to demonstrate the application of the production data" formulation of the β-derivative function (i.e. t
 est interpretation. In contrast measurements from new pressure gauge systems can now provide the stability and resolution required to char
  but nonetheless record high signal-to-noise ratio responses. These field experiments have demonstrated that the streaming potentials arisin
 ects in the cement sheath. It is therefore of critical importance to understand and characterize fluids and solids across the caprock. This has
 leak-off test data a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horizo
  to the surface. In this paper a risk-based approach is proposed for well integrity and confinement performance management. The approach
  . A recent trend of the industry is the integration of sub-surface and surface simulators to have a better representation of the fluid production
 n these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics and
 anding of the processes involved in underground CO2 storage evaluate applicable monitoring techniques and provide operational experien
  Enhanced Oil Recovery (EOR) Enhanced Coal Bed Methane Recovery (ECBM) Enhanced Gas Recovery (EGR) Food processing applic
 o properly manage containment performance and leakage-incurred risks. The analysis starts with the construction and the calibration of a M


at 8560 m / 28084 ft measured depth. The well includes three hydraulically operated flow valves which are used as down hole chokes to op
 is greater than 11.6ppg. This resultant high overbalance and other issues such as hole cleaning complex directional profile ECD managem

ave been waterflooded and only five have experienced CO2 injection. An ongoing US Department of Energy project is studying the use of C
  occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbonate
ated sequences; many thin high-quality sands have been overlooked. These sections can now be discerned using microresistivity measure
eservoirs have been producing with vertical wells.�This paper presents a practical strategy of rejuvenating gas-condensate reservoir prod
 in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs which have previously p
ells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting off t

ure formation and a micro-fine cement system for sealing off the water entries. Based on this study a cost-effective chemical treatment meth
  case history of an oil producer that has shown according to the production data an increasing water production figures. The nature of water p
 s. As a result most exploration and production companies have learned to manage water production up to a tolerable limit which is depende
 et in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to apply
meability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to cha
 entally friendly manner. Some fields in Saudi Arabia use water injection for reservoir pressure maintenance which makes water production a
ucer with 2 440 ft of reservoir contact was drilled and completed in November 2000. The last well production profile was determined by a Flo
 near-wellbore regions and production tubulars. Besides hydrocarbon solids other production hindrance elements include wellbore fluid loadin
 on and droplet size as a function of flow patterns and were used in characterization of the flow and performance evaluation of an oil/water m
 ng tap water and mineral oil with superficial velocities ranging from 0.025 to 1.75 m/s. The experimental results include observations of flow
  a static problem.� They cannot account for the dynamic changes that occur in time in the connected system of reservoirs and wellbore.ï
  into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity fo
  eposits having varying fluid characteristics. To reduce the risk we have adopted a systematic approach to evaluate the potential impact of a
  assurance aspects of a live waxy crude oil from offshore West Africa is investigated. Experimental work included determination of the wax a
 safety of equipment and personnel. The conventional procedure to evaluate the CO2 content in a hydrocarbon bearing formation is to take f
sition. Examples from two such reservoirs one from the Browse Basin in Australia and the other from the Malay Basin in Malaysia will be disc

nes and changes in the specific gravity of the reservoir gas as reservoir pressure declines. No correlations based solely on field data have b
-gas ratio exists in the petroleum literature. Alternatively oil-gas ratio (needed for material balance and reservoir simulation calculations of g
 laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients provid
ed lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. However water zones and second
 ce in the oil field. Furthermore different depletion/development levels and injection and production processes of different reservoir zones or
onditions of the downhole environment limit the DFA-tool measurements to only a small subset of the fluid properties provided by a laborator
n simplifying assumptions in terms of the compositions of flowing fluid phases. These models characteristically assume single-component ph
d phases detection saturation pressure as well WBM & OBM filtrate differentiation and pH which is key for real time contamination monitor

 d sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Resona
  economically make or break a project. Traditionally operators have relied on well tests to determine H2S levels. In addition to the expenses
ements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained from
provided valuable insights into compositional grading but each analytical method relies on different fluid traits and has different implications.
d in the zones of interest is extremely challenging especially when it is associated with overpressured low porosity shaly sandstone reservoir
uniform and free of noticeable impermeable layers. A resistivity log showed an approximate oil/water contact (OWC). Wireline pressure testin
 ion of in-situ fluid type can be difficult. There is also mounting evidence for the presence of compositional gradients in the hydrocarbon colum
 nsity fluid contacts and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA) m
ure/volume/temperature (PVT) properties. A technique of monitoring sample contamination from OBM filtrate uses optical means to monitor t


servoirs which are not in equilibrium but still undergoing for instance a flux of the light components that diffuse. Formation testers supply a w
 measurement and the oil-based mud (OBM) filtrate have been taken into account. Recently an algorithm called the fluid-comparison algorit
ditions of the downhole environment limit the DFA tools to measuring just a small subset of the fluid properties provided by a laboratory. Nev

ms the paper gives full details for a 3-phase oil/gas/water system.� Any number of hydrocarbon components may be present and water m
der the actual production conditions is necessary. This study is an attempt to investigate the effect of water content pressure and temperat




s and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability to
e sampling has always been the trickiest because even little traces of contamination may render the sample useless. Besides that the tool p
 ted for several years now by the industry. Their use in permanent or well testing applications has been growing rapidly. In many cases multi
 t benefits to the ease of deployment especially in harsh regions such as the one encountered in Northern Siberia. One of the past challeng
 stimulation fluids. The advantage for chelating agents is they can complex with calcite and form water-soluble products. Different mathema
 n damage make any stimulation a challenging and detailed process. Water injection is one the most commonly used exploitation method be
tions carried out under controlled conditions as well as within the pore space of sandstone cores. In the controlled reactions solutions of calc
mercial halite inhibitors are only effective at high concentrations (250 – 5 000 ppm). Therefore a more efficient salt inhibitor would need to

Core-flow tests were conducted to generate naphthenate-soap particles and to determine the permeability impairment caused by subsequen
 trix by de-bonding the cohesive inter-granular cementation leading to the creation of a zone of reduced strength called the damage zone. As
ge and maximizing productivity though the mechanism by which it does so is still not very well understood. Underbalance perforating also se
cale precipitation prevention no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been docum
 ntly to be effective in the typical Uinta Basin gas well environment: low permeability (<0.1 md) multi-layered commingled gas reservoirs. Typ
  imise reservoir and asset performance.�They provide the ability to independently control each valve individually from the surface to max
 ervoir and/or wellbore under varying conditions resulting into Strontium Sulfate Scale formation in downhole equipment. While CaCO3 scales
positions has revealed that this is due to much lower sulphate concentrations in the produced brine mix than would be expected purely from
s within a reservoir is not possible unless they are separated by zero permeability streaks or sealing faults. The proposed approach isolates l
ch by validating fracture lineaments and then optimize Injection-Production Ratio (IPR). This study involves the conversion of a finite differenc
 eration periods be they historical (i.e. history-matching phase) immediate (i.e. on-going) or in the future (i.e. prediction phase).� This tech
ent. This paper presents the results of numerical investigation into the water and gas production problems under different reservoir heteroge
   number of wells in AIB (approximately 2000 active wells) and the fact 95% of data is manually captured made the implementation of automa
and modeling tools to measure formation properties at the wells and between wells; this paper discusses the WI pilot. Among the novel techn
  s teams’ “key performance indicators (KPIs) to align injection and production allowables with sound reservoir management principle
 cal submersible pumps (ESPs) became an alternative to handle higher production volumes (Ramos and Rojas 2001). More recently top-driv
  ly greater than 2 000 cp. For the above reasons it is important to decrease the pressure of the reservoirs with primary production techniques
 te core holder packed with crushed limestone premixed with crude oil and water effects of operational parameters like heating time and waiti
D) process geared to increase the recovery efficiency of heavy oil within the Faja reservoirs. The process is based on a repetitive pattern usin
 placement motor with Silicate mud. Many of these wells faced hole cleaning challenges leading to pack off –excessive back reaming and s
  istribution of formation properties which is critical for management of the current pilot project. This study presents several aspects of an inte
 y isolates a small part of the formation from the hydrostatic pressure while the probe enables communication between the tool and formatio
 in less than a year. Horizontal wells were considered as best option for improving the productivity in this small to medium sized heavy oil fiel
ast with the strong mobility and low viscosity of the formation water makes the problem even more pronounced. To temporarily plug the wat


 ezuela has pone of the largest reserve of HO and EHO with more than currently 1.5 trillion of oil in place. Different set of technologies and m

ed with the fluid-formation interactions. This paper presents the results of a laboratory investigation of a single-stage sandstone acidizing flu
onstruction of a pilot gas processing plant (UKPG) and startup of a pilot gas and condensate production. The initial formation evaluation in th

 e systems (at high pressure and temperature) considering impact of fluid characterization effects. Under isothermal conditions and in the ab

en to the degree that near wellbore proppant transport is compromised and the treatment may screenout.� On the other hand a Ti or Zr c
 t also be considered to fully appreciate the challenges imposed by acid fracturing operations. The industry has successfully tried different me

where intervention is very expensive. The down hole gauge system is connected from wellsite to gas plant through SCADA which allows to m
both injector and producer wells. The post treatment results have been excellent with an average increase in Productivity Index (PI) of greate
mical mechanisms the new sandstone acidizing system (1) reduces the multiple stages in traditional sandstone acidizing to one stage; (2)
 samples were studied using coreflood and slurry reactor experiments. Linear coreflood test data show dramatic increases in the formation p
ant pack damage lengthy clean up times and high friction pressures. In recent times polymer-free viscoelastic surfactant-based (VES) fluid
 re also investigated for long-term prevention of water blocks. Contact angle and air-brine imbibition tests are conducted to determine wetta
 pressures current practice involves flashing the single phase water sample analyzing the flashed water and gas phases and then using wa

 ulation is usually required. Conventional OH or cemented and perforated completion alternatives have had various operational and logistic is

dies from North America and the Middle East show applications of this process in two different environments one mature and one emerging
ues were tested on the other. A general east-west orientation of planar fracture geometry was found with a maximum fracture event length o
 of sidetracks and the knowledge of hydraulic fracture orientation of the water injectors well that are fractured by the mere injection process. I
onments to improve the understanding of the induced fracture network and to go beyond the simple assumption of a symmetric bi-wing fractu
ction in produced gas. An integrated engineering process of reservoir and production analyses was used to evaluate the stimulation treatmen


 e contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing tre
y inter-granular small inter-granular and intra-granular dissolved pore. The porosity generally ranges from 4−10%with permeability ranges o
ough primary or secondary methods. Without different techniques of drilling and completion most of the oil in the low permeability intervals w
 d engineering data and interpretation. The stacked multi-pay tight gas sandstone reservoirs and their overpressured conditions were mode
models for each well.� Tools for the validation of the SWM such as production logs pressure measurements and formation micro-imager
 ajor challenges of modeling the field are reservoir upscaling and appropriate representation of the hydraulic fractures. A streamline-based fl
 ances in logging technology and production optimization modeling the thinly laminated gas bearing permeable sands can be discerned from

eep carbonate reservoirs in Kuwait. In the process of exploration and development of these particular reservoirs oil-based mud has been us
 heavy WFT programs and operation issues and at the same time maintain data quality and achieve even better data quality to fully satisfy
able which characterize the properties of a created hydraulic fracture from both the predictive and evaluative standpoint. This is important in
easurements were taken in the Wamsutter Field Wyoming. The observations presented in this case study serve as a model for what can be

of supercharging that can limit the data’s utility or in some cases invalidate the results. New generation formation testing tools that exte
plinary reservoir modeling and simulation effort. The subsequent development was based on oriented waterflooding patterns and massive hy
 Louisiana. Horizontal wells are commonly two to four times more expensive to drill and complete than offset vertical wells yet they are theo
 based on an integral analysis of the structural seismic and borehole data. First of all this is seismic profiling on the regular orthogonal grid w


 water-base mud (WBM) filtrate and connate water thereby avoiding any negative impact on the oil initially in place (OIIP) calculation and on

ulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous unconsolidated with higher viscosity and str
  and other factors. When nominal factors are involved it may be practical for decision-makers to rely on intuition and experience to guide th
 udgment from individual experts and group of experts. A judgment elicitation workflow includes interviewing of experts comparing subjective
 d better quality real time log information to enable the Drilling team to make quick decisions on were to place the well within the structure. Th
 rmation and methods exist in the literature to derive primary drainage capillary pressure data from the NMR log. In carbonates however it h
  requires rescaling the data and that may introduce significant uncertainties. To address these limitations we explored the use of electrode
 osity of a grainstone and responsible for an increase of one order of magnitude in permeability. The dissolution is observed by patchy featur
mages in 9 wells of the study area present a detailed insight into the different architectural elements of the sedimentary environment envisag
can be achieved. This paper describes a methodology that was used to generate a depositional model in the Lower to Upper Triassic reservo
mation water and a hydrocarbon composition in four groups: methane (C1) ethane to pentane (C2–5) hexane and heavier hydrocarbons
 ted lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. �However water zones and sec
us overlooking or under-estimating diagenetic features occurring in micro scale.� It becomes imperative to look at both micro and macro s
 ceptual geological model in the presence of a complex structure a real challenge. The objective of the study was thus to characterize the res
 sistivity- and neutron-based sensors also means that key measurements are being made at the same depth at the same time and on a simil
 ng-While-Drilling (LWD) tool has been developed using innovative technology to provide a complete suite of formation evaluation measure

n hole logs using the commonly used empirical and theoretical shaly sand models. This technique is based on development of water saturat
  open hole logs using the commonly used empirical and theoretical shaly sand models. This technique is based on development of water sa
2 distributions and capillary pressure curves in carbonates. Additional enhancements have been made to this workflow to include estimates o
6% with typical values being from 22% to 24% substantially better than the interbedded carbonate units with typical value of 12% to 15%. Per
bility from porosity alone yields scatter of a factor of 700.� Rock typing using only conventional logs was unsatisfactory due to the poor per
aluating the lithology the geometry and the net producible fraction of these reservoirs: We demonstrate that the partitioning of NMR T2 distr


int exists or when the nearby thick sand-shale is not representative of the sand-shale in the laminations. In producing fields that have underg
ducted to study relationships between true formation resistivity and LWD tool responses. In situations where the time-consuming resistivity m
 ures and conductive faults is of critical importance for the completion decisions in this field. Whole cores enable a comprehensive descriptio
nconsolidated or only weakly cemented. Experience has shown when sampling fluids from such formations sand grains and solids tend to b
 to be reconciled: in an example case it was observed that a large number of fractures seen on the images were absent in the cores. This pa
nt study utilizes twenty two well data in the crestal part of the Khafji structure to generate a semi-regional facies log which is turn up-scaled u

 se of the stationarity and ergodicity assumptions and the multiscale of subsurface heterogeneities. This often causes incorrect frequency sta
n testing and sampling calculate net pay thickness and uncertainty range. The evaluation is complex because of bed geometry and lithology
  a high-resolution antenna 6 in. or 15 cm. Within that distance NMR tools will cumulatively measure all layers of shales and all layers of san

 ely made equal to the driller’s depth which is a static pipe length measurement made by tape at the surface. There is almost always a d

 w over time. The effect of fractures on reservoir sweep and on problems such as early water breakthrough is largely controlled by fracture / s
 itu stresses with depth is estimated using logs with elastic parameters as an essential input.� The focus of this work is on the prediction of
mum and minimum horizontal stress magnitudes by use of cross-dipole dispersions. Borehole sonic data for the case study presented in this
  estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin ef
  estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin ef
  estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation skin ef
mainly has been on the basis of 3D-/2D-seismic data image logs cores and thin sections. The Greater Burgan field consists of the Burgan
oducing well. This workflow is applied on well NWO-1 in the Northwest October Concession in the Gulf of Suez area over the carbonate rese
 ussia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the follo
es on the characterization of different types of fractures and faults identified on high-resolution image logs recorded in this field. The objective
 st project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach inc
oil displacement by injected water in all the permeable zones was conducted in a carbonate reservoir in Saudi Arabia. The field experiment w
  hydrocarbon discovery the production facilities required to produce the resource and the predicted ultimate recovery. Recent advances in w
 tensive evaluation program was undertaken using new generation sonic logs WFT-multi-probe interval pressure transient testing (IPTT) an
 of the rock. This peculiar characteristic of the NMR response in these low porosity reservoirs with complex and variable lithology become f
 However these logs are not able to capture variations in the hydrocarbon column to allow the operator to ensure that all representative fluids
 effects between LWD and Wireline logs. NMR measurements of porosity bound fluid volume pore size distribution and direct fluid identific
at reasonable" logging speeds so full polarization of long T1 fluids is rarely achieved. Additionally the inversion process creates interdepend
s summary of the state of the art in nuclear-magnetic-resonance (NMR) well-logging technology is aimed at nonspecialists who would like to
eservoir bed thickness particularly in the Castillo Formation makes layer-by-layer correlation difficult. Several other factors add to the comp
gas oil and water and cover more cross sectional areas of a wellbore for enhanced characterization of multiphase flow regimes. The new to

(2) how to cope with the uncertainty of the results. An in-house multiphase reservoir simulator is used for the simulation of the formation res
normally enhanced by fractures in the upper Mishrif layers as they act as the main permeability conduit for the main storage below. The seco

rent fluid traits and has its own limitations. With systematic integration of different methods the synergy delivers a more accurate characteriz
wn to be colloidally suspended in the crude oil in agreement with recent laboratory results and settle preferentially lower in the oil column in a
btain estimates of the formation and well completion properties such as effective permeability radial flow steady state damage /stimulation s
 been based on SCAL. PND logging in producing wells has generally confirmed forecast saturations1 and only slight adjustments to the initia
effects on well performance. Moreover the limited lateral extent of these relatively tight gas sands leads to extremely depleted reservoirs alte

ect well completion and reservoir management decisions. A set of wireline formation evaluation tools were used for microfracturing (stress te
e transient tests acquired with a single or multiple probe formation tester. The solution is obtained by successive integral transforms to the go
  en considered drilling reach and anti-collision limitations and finally had the appropriate facilities and regional evacuation constraints impose
n of the project during the appraisal phase.� The context of this case study is the appraisal phase in the development of two fields with he
al benefits and challenges are discussed and an assessment is presented of the life-cycle economics leading to final recommendation. Var
 n this and its companion paper1 (SPE 104034) looked at the technical and business opportunities for two main re-development components
gaining consolidation with depth.� Almost all intervals are produced in non-commingled production mode with dual string arrangements.ï¿
 rs involves very thin and sinuous targets. These targets are the channel sand stringers and contain a substantial amount of hydrocarbons. O
 cate a power water injector in the southwestern flank of the field to support pressures during production from offset wells.� Seismic imped
 e installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas w
tional method incorporates cross-disciplinary software (geomodeling and seismic packages) as well as reservoir production completion and
nifold pressures and the need for artificial lifting technologies but potentially may also lead to the necessity of flaring associated gas if no app
ntelligent completion technology an Integrated Asset Model (IAM) was implemented. This model was divided in two sections: the first section
 letely decoupled from surface and subsurface simulators. The framework has a clearly defined interface for simulators and external FM algo
 nd the availability of lift gas.� In traditional gas lift optimization projects a gathering network model is used to calculate the optimal amoun
s surprisingly isolated from the surrounding aquifers. Prior to its premature shut-in oil production reached 5000 bopd. However a drastic dec
 s. The objectives of this paper are to present (i) how using numerical simulation to support and improve the strategies for production enhanc


ual field operation. A WAG cycle optimization workflow for the Snorre field has been created to demonstrate the advantages of using the SRM
manifold and then tied back via a 60km flow line and riser system. The reservoir is in severe decline with field production well below the orig
  into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity fo
pid execution of integrated studies are cluster computing and unique modular workflows that are based on stochastic concepts. Clusters hav
 5/8-in casing with zones separated by packers and produced commingled through sliding sleeve doors (SSDs). In the past few years more a

 ns Production Optimization and de-bottlenecking of the existing production system was found to be the best cost effective solution.� �
n built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in
ostics to systematically identify layer-by-layer key parameters affecting productivity and to optimize performance based on “present-sta
 make wise investments in such a difficult environment it is crucial to understand the real value of the remaining reserves. The outcome of a
  simulation to appropriately value future information today. We assume that the client company and the service provider share information on
equiring steering adjustments while drilling horizontal wells maximizing well position in the reservoir. This paper shows how thin oil rims fault
  possible to the top of the reservoir to ensure a greater long term field life and given the thin oil column reduce the volume of attic oil. Gener
 l termination of wells as they reach prescribed abandonment criteria.� This method in general results in an irregular well placement patte
mbalier 316 block a delineation well penetrated the steeply dipping B4 reservoir near the oil/water contact. Based on a comparison of down
drainage area and provides a step by step analysis to verify quantify and locate these bypassed reserves.� Further it provides a compreh
  impact the optimum number of infill wells during the concept selection in a field development stage. High resolution geological models toget
 These pseudowells produce or inject at a very low rate and thus have a negligible influence on the overall flow throughout the reservoir. Th
t depict all details of real SAGD processes. In the present work a new analytical model of the SAGD production regime is described. The init
    These equations are applicable to partially penetrating vertical horizontal and fractured wells and take into account superposition effects
mi-analytical solutions are applicable to partially penetrating vertical horizontal deviated and fractured wells where fractures can have infini
ypically depend on either the number of model parameters or the number of data points; and third the calculation of the prior covariance ma
ase of field scale applications of long history. Lastly the solver used for solving the Adjoint system of equations needs to be efficient for large


 tions or the training images for a given depositional environment are obtained. These realizations could be quite different yet they are not co

e Newton-Raphson method. External heat sources and sinks are included in source terms to model the energy interaction with over-burden a
 andles general partitioning of phase-component consumes no extra memory and only has a small amount of CPU overhead. This general
al horizontal well in this field has perforation intervals of about 1 200-2 900 ft penetrating depositional sequences from the bottom up and pr

e used to regulate flow from various perforation intervals or producing laterals. Our recent field studies required the simulation of special we



 servoirs using a production surveillance tool that manages multi-wells effectively in less time is discussed. The last three techniques-type-cu
ess. This three-phase 2D model proved useful for assessing the significance of reservoir capillary pressure broken-gel viscosity yield stress
e in previous studies. A further one related to the cleanup of the cross-linked fracturing fluid with its non-Newtonian characteristics was rare
 t flow regimes can be used to observe and define the various impacting factors of stimulation such as fracture length conductivity orientatio
 computational grid that is used for the whole reservoir with grid refining in fracture domain and couldn’t completely account all phenome
mensional (P3D) hydraulic fracture simulator. In the model the width deformation of a fracture with interfacial slip is calculated using a displa
 ple and fast has been the rationale for using analytical methods in the past. However computer technology has enabled us to run numerica
 umerical analysis restrictions were also imposed on the variables for the correlations to be valid. In this paper the same problem of non-Da
  simulator we systematically used the new technique to investigate the effect of data availability i.e. the number of production logs and dura
 tate flow.� This model has been used to develop predictive and analysis graphical design charts of the dimensionless productivity index fo
 ing did not obey any of the existing 2D models (PKN KGD or Radial). As a consequence job designs remained impossible and optimum pu
 del predicts and evaluates the near-wellbore fracture pinching effect as a function of fracture trajectory perforation misalignment angle cem
diction effectively when there is an underlying relationship between the variables. We have applied this and other methods to determine the f

 uid flow in the reservoir. Third the lateral variation in facies forces to use different saturation functions at different parts of the reservoir. The
he analytical solution can be used to generate the temperature profile in a horizontal injection well for any assumed distribution of injection pr
  of a nominal drainage radius whereas a two-fluid system with a moving fluid is more appropriate. The novel concept of the injectivity produ
defining reservoir compartmentalization and in analyzing the results of material balance (MB) analysis. In particular analysis of the reservoir
hods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir pressur
eover the data may be complete but the formerly used methodologies (e.g. the use of well cluster metering units) and instrumentation may
  multicomponent reservoir fluid are presented. Results show a strong effect of natural convection in species distribution. Results also show t
 servoir simulation studies there is also a growing need to share practical examples of the lessons learned in constructing experimental desi

ence and numerical flux consistency of the scheme for uniform permeability tensor are studied. This discretization scheme is applied to rese
 after proper tuning these models can be used for the simulation of the well production profile in naturally fractured reservoir and of the flow
site porosity composite relative permeabilities and composite capillary pressure relationships. These composite curves can be generated fro
rmation and fracturing the limited applicability of the elasticity assumption and the latent uncertainty in the structural geometry of faults. The

ble fluid phases. Flow simulation of fractured reservoirs is commonly performed using a dual porosity model. The dual porosity system is mo
 to zero. Mass transfer between matrix and fractures is modeled by empirically determined transfer functions. Fracture permeabilities can di
eamlines in combination with a new multiscale mimetic pressure solver with improved capabilities for complex fractured reservoirs. The multi

e show that RML does an adequate job of sampling the a posteriori distribution for the PUNQ problem. In particular the true predicted oil pro
pact that the dynamics of brine mixing in the reservoir has on scale precipitation in situ. Much of this work has been conducted using finite dif


ement strategy is based on the multi-scale wavelet techniques. The one-dimensional solution is decomposed into a set of coarse-grid cell va
 we went further and have treated the thermodynamics in terms of Koldoba & Koldoba approach7. The model allows for receiving phase equ
diction that combines speed and reasonable accuracy. The workflow generates a set of key performance indicators of existing wells derived
  available; a suite of plausible reservoir models (the ensemble set of ensemble members or suite or realizations) is continuously updated to
he reservoir heterogeneity each honoring the data available. The simulated pressure responses from these realizations could be quite differ
tible and explain the necessary modifications to the techniques used to solve the resulting linear system. The effect of simulating flow in bot

n models can be potentially built. Because of global production targets and constraints these models cannot be run in isolation. A multiple re
ductivity of reservoir rock called the ‘connectivity equation’ is provided in the paper.� Similar to Archie's law this simple model has o

To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in general l
 en observed behavior: 1) negative pressure gradients 2) water-like gradients significantly above the free water level 3) significant shifts in
 h good performance being attributed to the highly developed and connected fracture network. The original reservoir pressure was in the rang
ound borehole can produce breakouts and their orientation indicates the direction of minimum in situ horizontal stress (Sh).� In the case o
apply these smart technologies to mature fields with a legacy infrastructure and long production history.� Participants felt that maturity in i
very intereresting EOR experience has been accumulated in the country. It is likely that EOR- produced oil in Russia has not already reached
Alaska’s North Slope started producing oil at about the same time as the United Kingdom North Sea in the mid to late 1970’s. Alask
 with those of finite-element models. More complex situations can be simulated with finite-element models but the input data requirements a


 surveyed with pulsed neutron capture logs. Based on the log results depleted zones were identified and the intervals contributing most to th
 lic flow control valves with advanced downhole two-phase flow and density measurement provided by a Venturi-based flowmeter with a gam
 late 2000 after a successful waterflood pilot program. The wells having water injection are mostly located in the short string section of the du
evelopment of a state-of-the-art electrically powered tractor combined with new surface read out array mini-spinners and optical gas and arra

 ation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and boreh
 ation mobilities are in the low double or single-digits saturation pressure is usually within a few hundred psi of formation pressure and boreh
  and temperature in two stacked carbonate reservoirs. The standard dual-gauge system mandrel architecture requires below packer installa
ector are used to record the dye signal and calculate pH with 0.1-unit accuracy. The pH of a formation fluid alters as the sample is brought t
compared with historical trends to check well performance. For the fields studied the KPIs have proved valuable not only for production mon
such as drilling patterns new well placement and completion practices. Microseismic events were located with a newly developed� locati
 ly the result of insufficient fracture width. This unfortunate circumstance creates an operational strain and productivity underperformance for

 continuously during startup and production. Initial steam circulation and production occurred in 2004. The acquired data shows that large te
nload liquids from the well.� Sub-critical velocities are commonly encountered in low productivity gas wells that produce liquids whether th
nd unload liquids from the well. Sub-critical velocities are commonly encountered in low productivity gas wells that produce liquids whether th
 roduced water to surface. This completion technique makes spinner production logs impossible to run without initially performing a wellsite o
are analysed to determine tracer presence. The presence of one or a combination of unique tracers within the oil sample along with the know
w-rate and cut measurements without slip models even in highly deviated recirculating flow. The physics basis and flow loop tests are discu


 ion from any target would be detected with just monitoring the data collected. Then any good" decision for improvement or optimization wou
 s high as 99%. The horizontal well examples show that stratified flow regimes as expected from flow loop publications vary hugely with cha
  ovided an “once-in-a-lifetime opportunity to carry out a fieldwide pressure data acquisition campaign. Over a period of six months (Nov. 2
 uring this period the gas oil ratio (GOR) steadily increased from 200 scf/bbl to 2 200 scf/bbl. To arrest production decline a chemical treatm
 nd in obtaining better data for decision making. The most important part of well/field production optimization is identifying candidates and to
 laborate operational aspects involved in wireline formation testing success requires detailed upfront planning and procedural design as well
 oduction. The technique employs the use of a rigorous near-well nodal reservoir pressure and thermal model to analyze permanently installe
ormation indicates a discrete deforming region near the toe of the well. The volumetric strain also shows another region near the heel of the
n the periphery of the sand-screen shroud effectively installing it in the gravel-packed annulus. When the gravel pack is completed the fiber
  distributed along a single spoolable bridle. In addition a novel inductive coupling mechanism was developed to pass power and data from th
 ypes of thief zones in the Mauddud carbonate reservoirs using high-resolution image logs with calibration from core and dynamic measurem

volumes at the well level and at intermediate outlets of the production facilities. However for many fields this isn’t a cost effective solution
 at differentiate between Oil Holdup (Yo) Gas Holdup (Yg) and Water Holdup (Yw) as well as providing multiple spinners for revealing stratif

  in the industry and already proven beneficial in many occasions. In favorable conditions this is the most effective methods available to date
 nt of the injected sea water front within the reservoir is important to evaluate the efficiency of pressure maintenance by peripheral water injec
ng deployed in southern part of a complex carbonate reservoir in the middle-east where an uneven flood front advance has been observed in
a higher resolution image of the ongoing flooding processes. The classic EM inversion process determines a coarse (3 to 5 m resolution) re
 and new technologies are being developed with the aim of increasing production rates. Considering this interest and activity level little atten
 tandard log evaluation methods. A CBM well may often penetrate multiple reservoir zones (seams) and properly characterizing the cleats w
 d to significantly increase Coalbed methane (CBM) fracturing efficiency by initiating fractures in lower stress clastic rock adjacent to coal sea
blem encountered when completing horizontal Barnett shale wells. These difficulties have manifested themselves as high-fracture initiation a
 opment in tight gas shale reservoirs results in complex near-wellbore stress concentrations not observed in isotropic rocks.� Using finite
he friction pressure through (CT). Efforts to increase the energy have involved increasing CT size and increasing surface horsepower.� Ec
e.� In most cases evaluation is limited to a gamma ray measurement while-drilling (MWD) �tool and periodically mud log.� While th
 al logs and cores have been used to classify lithofacies and estimate petrophysical and geomechanical properties for well positioning and re
 endous amounts of steam in order to get the crude to flow. Costs to generate and inject steam in a SAGD pad are significant. Finding ways
 ural-gas production from coalbed- and shale-gas reservoirs in the US is approximately 2.7 Tscf which represents 15% of total natural-gas p
e the productivity of existing wells and book additional reserves at reduced cost operators have restimulated their older vertical wells with de
 ptimized wormhole geometry should be functions of reservoir properties such as permeability and pressure as well as fluid types such as oil
avity. All new installations were carried out without interrupting the ongoing production target. The project has completed a four-years operat

 l the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the process a
  only enhancement of individual well production rates but also significantly improved the oil recovery. This goal was achieved through optimi
  to the need for evaluating� the best sand-control solution while considering the cost/benefit ratio. This paper explains why an openhole g
 valves to be placed in a single well without incremental reductions to the internal diameter (ID). This near full bore feature allows normal cem
 en both vertically and horizontally on a well-to-well basis even though the wells are very closely spaced. Sands have different oil retainer cap
 lbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.� The produced liquids considered in
 lbore liquids are produced directly from the formation and/or condensed from the gas in the wellbore.� The produced liquids considered in
as been recently drilled in this reservoir achieving about 5 000 ft of reservoir contact.� This paper details the process followed to achieve th

 control of commingled production from the laterals. Using the variable positions flow control valve the well was managed to improve and su
at downhole control may be used to adjust flow distributions along the wellbore to correct undesired fluid-front movement. In this paper we a
nd downhole control of commingled production from the laterals. The well was managed to improve and sustain oil production by eliminating

ompared to horizontal wells. With a total section exposed to the reservoir equal in both types an experimental model has been built for the pu
 ze operations in wells where the above equipment and operations are required. This paper summarizes practical experience gained during
 proportional hazards (CPHs) (Cox 1972) modeling to determine statistical significance of explanatory variables (EVs). Methods developed to
s create significant conductivity enhancement in treated wells their etched fracture length is typically short because of the high speed at whic
 marine sandstone without hydraulic fracturing until drilling the CD2-37 well in 2003. The poor reservoir quality found in the southwestern edg
ne of 2005 a new technique was introduced utilizing chopped fibers within the fracturing gel slurry to help suspend proppant in the slurry both
ems oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linke
 ration and in-situ gelled acid a polymer-based system have been extensively used in most fracture treatments in an attempt to control exce
 centration up to 1000 kgPA and higher with only 3.0 kg/m3 (25lb/1000gal) guar polymer loading a feat previously only achievable with 3.6-4.
 a specific reservoir is not a simple matter for the end user and the existing literature is full of conflicting claims as to which one may be most
 der the combined effects of modulus contrast and in situ stress contrast on fracture geometry. A pseudo 3D (P3D) hydraulic fracture simulat
 ve length and conductivity and fluid recycling/handling are but a few strategies employed. Additionally operating companies have been seek
ned or requires expensive cleaning or dilution with fresh water to make it a viable solvent base for fracturing fluids. This paper describes the
ous Pin-point Stimulation Techniques) were implemented with an appropriate data collection strategy to evaluate and compare well performa
ng a sand plug with the downhole tool set for circulation to isolate a bottom set of perforations followed by conventional frac-and-pack. Whe
e fracture height growth. The method consists of pumping a predetermined mixture of specialty solid materials. The case study clearly demo
igh permeability streaks that require effective diversion techniques. The efficiency of chemical diverting agents in terms of flow distribution an
r cuts can be a rewarding operation. The treatment can be carried out while providing favorable economics to the entire operation. The ke
 Conventional multistage fracturing techniques including perforating fracture stimulating and isolating stages with a composite bridge plug h

 uff carbonate reservoir some wells have experienced complications during the drilling phase and encountered unexpected reservoir challeng


hat had experienced poor recovery primarily because of poor permeability. There were unique challenges posed by the Gandhar candidate
ized in this study. The mathematical model described in this paper has been used to develop predictive and analysis graphical design charts

h asphaltene and paraffin oil content varying the hydrocarbon properties it is understandable that the extensive knowledge gained in Wester

menting operations. A control line is connected to sequential valves. When the bottom valve opens the control line becomes pressurized and
e cemented sliding sleeve concept by attempting to minimize and predict fracture initiation pressures. Finite Element Analysis (FEA) was c
e of soft rock that is a cohesionless granular impermeable medium. The real problem of hydraulic fracturing in an elastoplastic medium has
ico.�The fluid exhibits enhanced fluid efficiency while still maintaining the high proppant pack conductivity associated with the lack of poly

 ive of low-pressured water sensitive formations high rock Youngs’ Modulus and unpredictable occurrence of water-bearing zones lead


sphalting Onset Pressure (AOP). An engineering solution was urgently needed to enhance the productivity of wells and to mitigate the asphe
oject (JIP) active since the year 2002. The data discussed builds on the initial results published in early 2006 which indicated that the polyme
y execution and results from two offset wells.� The first well was completed with a two stage hydraulic fracture treatment while the succes

ot known accurately and the velocity model is artificially adjusted to locate perforations on assumed positions several milliseconds discrepan

ct of the acid-fracturing process we developed a new surface profilometer to measure the surface profile of a rock sample accurately and ra
f the height but also for p3D model where the height is indirectly obtained from coupling stress profile and fluid flow. Fracture azimuth is trad
al markets. This paper will describe a new patent-pending technology that can generate valuable data on propped fracture height as well as

 s particularly true for the Yamburgskoe gas condensate field where the wells are completed in a series of medium- and low-permeability re
 true if a liquid phase is also flowing. The apparent permeability of the proppant is a function of:    Gas velocity (hence: rate and flowing pre
 e tip zone where the pressure drops below the far-field pore pressure. Moreover the assumptions of the Carter leak-off model do not apply i
s greater than the fracturing pressure of the formation. A new generation of viscoelastic surfactant-based acid was implemented in the field.
  state shape factors under boundary-dominated flow conditions.� Designing the optimum stimulation fracture treatment in this case is mor
 on data. This difference in fracture geometry was attributed to rotations in the direction of minimum principal stress which is consistent with
g an appropriate completion method. The development of a model allowing a quantitative prediction of this process is therefore a very vital ta
 odel is developed to predict the growth of the two intersecting fractures in a variable stress field and the associated pressure response in ord
on fracture propagation. After hydraulic fracture formation terminated the cleanup procedure begins. Fracturing fluid is evacuated from the we
at the wellbore impeding both lateral and vertical extent. Differential cased hole sonic anisotropy (DCHSA) combines the use of cross-dipole
 lprit. The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff a
 mping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm surface pressures were still within the pressure limit of 3000 psi given by t
 n of a horizontal stress map for the studied area and an accurate measurement of the hydraulic fracture heights on the borehole wells togeth
ed 2D hydraulic fracture model. Offsets are geometrically characterized by their angle with respect to the main fracture direction and by their
gas lift systems have been installed at the time of writing of this paper most of them in the Scandinavian sector of the North Sea. Several pap
  techniques used in completing these high rate gas wells as open-hole gravel packs have included both water-packs and shunt-packs. The e
ating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place pe
ating to time savings more efficient fractures faster cleanup and less safety hazards. Conventional methods of cementing a liner in place pe
 esents the case of a gas producing horizontal well in Indonesia completed with a perforated liner. The target reservoir is a clean sandstone r
ce completion system with digital permanent down hole monitoring system. Intelligent completions allows individual lateral testing allocation o
 er breakthrough. This early water breakthrough causes reduction in potential hydrocarbon recovery; the operation of the ICD is minimizing re
ous reservoirs using a single wellbore. Their capability to restrict water or gas production and improve ultimate recovery has helped optimiz
 system with digital permanent down hole monitoring system. Intelligent completions will allow individual lateral testing and allocation of prod
 ggered by permanently installed downhole sensors can enhance production and mitigate reservoir uncertainty across a range of production
were captured by the fixed pressure probes and showed a distinct fluid lag region (i.e. a lower fluid pressure region close to the fracture tip).

well performance prior to the production test. We present an integrated and structured approach for calculating the productivity of a laminate
  problems are expected after depletion increase in water cut and installation of ESPs to optimize production. To accomplish this task a 3D
e perforating and other near wellbore damage therefore perforating design is not important as long as it serves the purpose of puncturing thr
 rmation immediately after perforation and a perforating technique that utilizes the dynamic underbalanced method which cleans perforations
 ed to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed by
ce simulations. The quality and amount of data was recognized to be limited. However a qualitative diagnosis of these results indicated that t
ervoirs are generally of lower porosity and higher compressive strength. Drilling-mud-filtrate invasion also tends to be deeper. Deep-penetrat
or other hardware that can be damaged during perforation. The traditional approach of hiring a workover rig to remove the completion prior to
 e waiting for the multipurpose barge and in some cases eliminate the need for stimulation. This new perforating technique utilizes a unique
ontinuously varies during the surge; (b) the skin factor may decrease substantially during the flow period because the mud cake invaded filtra
 lbore fluid displacement is often deemed insufficient to create effective cleanup of the perforations. This paper outlines a solution to these ch
n their own experiences and previous perforating histories to roughly estimate the swell or damage conditions of similar perforators. In this p

 nly difference of note was the design and composition of the liner. All other charge design parameters were kept constant. For both rock typ
ore they are used for production or injection. In the depleted oil field under study a typical completion is perforated using large diameter high
hallenging areas in Ghawar field where the water will reach the wellbore much faster via the reservoir's fractures. Using the smart completion
 nges presented by the heavy oil and the large geographical extension of the reservoir the decision was made to develop the field with horizo
help ensure high-rate long-life completions the producing zones are frac packed. The average perforated interval during the initial completio
north to south. Production in Hawtah comes from the Unayzah sandstone and consists of Arabian super light (50� API) sweet crude oil. H
were used successfully on the first two wells. The A1ST1BP1 completion failed during initial unloading allowing unacceptable rates of sand p
 ut ten years of production a significant amount of sand was observed during routine sampling of the well. This condition resulted in the closu

ure and even flow distribution throughout the producing interval of the well.� A review of the completion methodology in poorly sorted unc
ntegrated approach was adopted for the design of the fluid systems involving extensive formation damage and fluid compatibility testing. To t

 cking was the common completion in a single sand body however in presence of shales open-hole expandable screens with annular barrier
aused by unpredicted downhole events. In this paper we present a new approach for gravel packing long high angle openhole intervals witho
successfully designing these jobs. This paper presents a pseudo-3D modeling tool which models the complete gravel-pack process and acc
gravel packing in the industry deals primarily with water based fluid environments new challenges for gravel packing of the associated wells
 on tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are
on tunnels and improved the connectivity to the reservoir. Guidelines to surging the formation and executing the perforation packing job are p
 orizontal wells due to traverse several shale and sand bodies of varying quality. Perforation tunnels with optimal “structural stability for th
 heavy and viscous oil of 19� API - 9 cP. This causes sand production high water cut wormhole development and requirement for artificia
ubing intervention matrix acidizing resin consolidation optimized fracturing with proppant flowback control and fines migration prevention. T

particular systematical approach termed as Sand Management Solution (SMS) to properly address the sanding issues it was facing which
 thus provides a basis for designs that achieve appropriate sand management strategies and maximization of economic production and ove
  descriptions of the rock strengths and in-situ stresses in the reservoir formation. Somewhat surprisingly the model backed up by the core la
esses and drawdown conditions. Water was introduced into the flowing stream of either oil or gas at various stages of the tests to simulate w

  production prediction models have focused on predicting the onset of sanding by predicting the drawdown at which failure of the formation
 n pressure 2) mechanical and petrophysical properties of the formations transected by the wellbore and 3) properties of drilling fluid and its
 d form rod-shaped micellar structures under certain conditions. Viscoelastic surfactant-based acid systems have been used in Saudi Arabia
d loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids—an acid viscosified with polym
ary diversion to ensure that multiple sets of perforations are adequately stimulated. Because of their high solubility and highly fractured/vugu
 ed system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. Thes
sed system are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad. Thes
 ges in the production profiles. In one of the wells the formation was stimulated first with 15% HCl through coiled tubing and then with the v
 entation and a moderate-to-low rock strength. Core analysis and rock mechanics assessment revealed that much of the rock is weak and
ke matters worse formation damage in horizontal wells is usually very deep as a result of long exposure times. This paper discusses the ap
stone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling Bullheading Diver

e wells by reducing the skin factor to the lowest possible value in each zone. At the same time the selected optimum acid system placemen
w corrosivity their low dissolving capacity may still limit the wormhole penetration leading to insufficient stimulation of the formation. Therefor


 sands using a variety of different (water- and oil-based) fluids. However many of the wells indicated positive skin factors following the fractu
 tments especially in extended reach and multi-lateral wells. Diversion techniques can be classified as mechanical or chemical.� Mechan
epletion is the increase in filtrate leak-off of drilling completion as well as stimulation fluids. The sensitivity of the formation to wellbore fluids
 es on stimulation treatments.� Some results on the influence of core scale heterogeneities are also presented. Core samples from eight
 tion methodology has focused on underperforming wells. This simplistic approach has yielded disappointing results and has led to a commo
 fects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier comp
astic surfactant (VES) fluid system. It has recently been employed to eliminate the disadvantages of the traditional polymer-based fluid. This
nd evaluation but goes far beyond basic well stimulation which has historically used limited data. Another important feature of the integrate

 ng in higher water cut due to the over stimulation of the water zones instead of the oil bearing zones. The objective of the present field case
stence of poor behind casing cement quality and possibly hydraulically communicating layers was critically and systematically examined by a
  derived from the rigorous solution and are used for developing the basis for the straight-line analysis. A derivative function is utilized to asce
 tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis f
rdingly to the fracture flow periods 3) estimate reservoir and fracture effective properties and 4) evaluate the completion efficiency. The field
 2 and Bentiu-3 formations. These formations are highly variable in terms of the reservoir properties oil types and pressure regimes. A selec
 netration of the total formation thickness. Penetration in naturally fractured reservoirs is usually minimal (10 to 20%) but with the right mud
ge at a distance we will only start to detect a pressure change (drop or increase) after a few seconds or minutes even if we have a perfect p
onitored.� This paper illustrates how real-time data can be used to make decisions on when to invest in pressure transient tests and when
 in a unified manner. The algorithms used in this study for evaluating the von Schroeter et al. and Levitan methods represent our independen

alysis of pressure transient data provides dynamic reservoir properties such as average permeability fracture storativity and fracture conduc
 n testers have been commonly used to acquire formation pressures pressure and reservoir fluid samples for a number of decades. Many ha
ctives of a MiniDST are sampling estimation of reservoir properties such as permeability (k) skin(s) radial extrapolated pressure (p*) and es
 e 95% gas fraction under metering conditions and water cuts often higher than 90 % TOTAL ABK has evaluated different well testing & mon
ating environment of Northern Siberia. The reduced logistics and the ability to monitor in real time the true evolution of the gas and condensa

s types of multiphase flowmeters react quite differently to the measurement challenges of transient flows in high water cut and high gas volum
urgskoe gas-condensate field with low ambient temperature and production rate regulation restrictions this process had to be revalidated an
 allows a traditional multiphase flowmeter to operate in a dual mode either as a multiphase meter or as a wet-gas meter in 90 to 100% gas. T
tors to allow fair comparison of results. More than 50 wells were tested during this campaign. All these wells were selected carefully to repre
en commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter. With the recent dedicated Gas Mod
 more complete approach where a more integrated approach using a common model is advocated. . The benefits of such a workflow can be
 on of the β-derivative function (i.e. the β-integral derivative) for the purpose of estimating reservoir properties contacted in-place fluid and
ability and resolution required to characterize/quantify complexities of the well/reservoir system which may otherwise have gone unnoticed.
ed that the streaming potentials arising from pressure transients can be measured accurately under borehole conditions.�Numerical meth
 d solids across the caprock. This has the triple aim of: verifying the soundness of the complex cementing engineering process evaluating th
are used to constrain principal horizontal stress orientation and magnitudes. Consistency of the stress model is then checked against the occ
ormance management. The approach based on Performance and Risk Management methodology (P&RTM) serves as a decision support t
representation of the fluid production/injection taking into account the constantly changing interaction between systems. The integrated app
 accurate description of physics and chemistry in numerical simulation tools is fundamental for understanding processes as well as designin
es and provide operational experience which all contribute to the development of harmonized regulatory frameworks and standards for CO2
 very (EGR) Food processing applications Mineral products Fertilizer manufacture Algae growth promoter Enhanced plant growth. The c
 onstruction and the calibration of a Mechanical Earth Model of the site through joint analysis of geologic seismic logging drilling and labor


are used as down hole chokes to optimize the production from the separate zones in the reservoir. Subsea developments in combination
ex directional profile ECD management at high ROPs can lead to inefficient motor drilling. The soft formations also create limitations for pu

 ergy project is studying the use of CO2 in enhanced oil recovery operations at the Charlton 30/31 reef which is located in Michigan’s Ot
s been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high conc
 erned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed. A production pred
 ating gas-condensate reservoir production through multilateral sidetrack reentry drilling technology.� Simulation studies show that reentry
e reservoirs which have previously produced with primary recovery mechanisms. The study touches upon the effect of the component group
on. Challenges faced in shutting off these gas zones included: 1) Poor cement bond behind the liner shoe. 2) Massive fractures resulting in lo

  st-effective chemical treatment method was progressively developed. In 2005 the treatments were performed through-tubing with and witho
duction figures. The nature of water problem and the fact that the targeted section is located in-between multiple oil producer zones revealed
  to a tolerable limit which is dependent on the water handling capacity of the installed facilities and also the economic cutoff limits for the we
 ive. This will open the doors to apply similar techniques to liven dead horizontal wells in other fields. Introduction Excess water production in
nt results. This method can fail to change the well production profile and possibly damage oil-producing layers. This paper will discuss the de
nce which makes water production and handling a necessity even at a relatively early stage of some of these fields life cycle. As drilling tech
ction profile was determined by a Flow Scan Image (FSI) log which showed 51% of water cut and the entry of most of the water was from th
elements include wellbore fluid loading fluid slugging inorganics corrosion erosion and emulsions. All these elements adversely affect prod
ormance evaluation of an oil/water model. A high-speed video camera was used to identify flow patterns and measure droplets and ten cond
  results include observations of flow patterns and phase distributions and measurements of water holdups and pressure gradients. A high-s
d system of reservoirs and wellbore.�Once multiphase flow occurs both the change of the fluid mobility in the reservoir and the change o
mpression power or pump capacity for example could impose significant limitations over the well and surface network performance that cou
  to evaluate the potential impact of asphaltene and wax precipitation and deposition. In this field case two distinct layers of hydrocarbon dep
k included determination of the wax appearance temperature (WAT) and rheological studies which included pour point gel strength and she
 carbon bearing formation is to take fluid samples downhole or on surface during a well test and send the fluids to the laboratory for analysis.
e Malay Basin in Malaysia will be discussed in this paper. The CO2 content can vary from very low concentrations in one zone to significantly

ons based solely on field data have been published for any of these properties. The field data required are initial producing gas/condensate
reservoir simulation calculations of gas condensate and volatile oil reservoirs) had to be generated from a combination of laboratory experim
 ponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization) which
s. However water zones and secondary gas cap formation in a few layers are also common. Nonetheless unexpected fluid production such
cesses of different reservoir zones or compartments not only motivate more variations of fluid properties also trigger contacts migration and
 id properties provided by a laboratory. Nevertheless these tools are valuable in predicting other PVT properties from the measured data. Th
stically assume single-component phases in the case of two-phase immiscible formulation or a two-/three-component hydrocarbon phase in
y for real time contamination monitoring at the well �site with the objective of representative sampling and reservoir compartmentalization

 n hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation and fluid saturations. Gas and remaining oil saturatio
2S levels. In addition to the expenses associated with a well test there is the ever-present issue of H2S scavenging. Many days of flow may b
ived gradient and that obtained from wellbore-flow modeling of production-test data. Older-generation formation testers (those from before 1
 traits and has different implications. When these analytic methods are systematically combined and consistently applied the synergy deliver
w porosity shaly sandstone reservoir. It becomes difficult and at times impossible to definitively identify different types of formation fluids from
ntact (OWC). Wireline pressure testing identified three different pressure gradients corresponding to gas oil and water all in hydraulic comm
al gradients in the hydrocarbon columns of some reservoirs – this raises questions about the conventional approach to pressure gradient a
 d by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities. Although these fluid complexities have
trate uses optical means to monitor the buildup of both color- and methane-absorption signals during sampling. The technique provides real


diffuse. Formation testers supply a wealth of information to observe and predict the state of fluids in petroleum reservoirs through detailed p
m called the fluid-comparison algorithm (FCA) was developed to address this issue. The FCA propagates uncertainties in optical measurem
perties provided by a laboratory. Nevertheless these tools are valuable in predicting other PVT properties from the measured data. These pr

ponents may be present and water may exist as a liquid and/or a vapor.� The presence of non-volatile and/or non-condensable hydrocarb
ater content pressure and temperature (i.e. operating conditions on the viscosity of live heavy-oil emulsions). Two heavy oil samples from




aminated reservoir fluid. The ability to secure a totally clean sample of formation fluid at reservoir conditions is a significant advance that prov
mple useless. Besides that the tool pumps gas into the wellbore during the cleanup phase raising issues of well control. Another important f
growing rapidly. In many cases multiphase flow meters have replaced the separator for flow rate evaluation but some fundamental needs fro
 rn Siberia. One of the past challenges of multiphase well testing has been the ability to collect representative fluid samples for analysis.�
 oluble products. Different mathematical models were developed to describe reaction of organic acids (both simple organic acids and polyca
 mmonly used exploitation method because of its favorable results. Sustained injection rate with delimited surface pressure is necessary to m
 controlled reactions solutions of calcium chloride are mixed with solutions containing one of a variety of soluble inorganic or organic carbona
 efficient salt inhibitor would need to reduce both treatment level and production downtime. The inhibition performance of three new chemica

 ty impairment caused by subsequent deposition of these particles in porous media under flowing conditions and different pH values. A powe
 strength called the damage zone. As a result the damage zone extends to a greater depth than the crushed zone. This weakened damage z
 od. Underbalance perforating also serves to remove some or all of the comminuted sand grains that fill the perforation tunnel immediately a
  mulation treatment has been documented. This paper describes the first application of a combined scale inhibitor and hydraulic fracturing tr
ered commingled gas reservoirs. Typically a well completed and placed on production without any scale inhibitor in the Uinta Basin may sho
   individually from the surface to maximise oil production and/or minimise formation water and/or gas production.�However they may also
hole equipment. While CaCO3 scales are possible to be removed by the use of common acids and wireline tools Strontium Sulphate scale r
  than would be expected purely from dilution of seawater with the formation brine.�The question this paper addresses is what has caused
 ts. The proposed approach isolates least correlated and most sensitive regions within a reservoir. The least correlation criterion ensures that
  es the conversion of a finite difference black oil Dual-Porosity Dual-Permeability (DPDP) history matched model into a Dual-Porosity Single-P
e (i.e. prediction phase).� This technology can be used to guide and optimize development strategy. By incorporating streamline technolog
ms under different reservoir heterogeneity conditions pertinent to Cantarel Field. For this purpose some of the typical problem wells have bee
   made the implementation of automatic surveillance particularly challenging. We introduced an automatic surveillance solution that synchron
   the WI pilot. Among the novel techniques applied is the crosswell electromagnetic method which measures the interwell resistivity distribut
 und reservoir management principles. An innovative unified information management system was used to monitor voidage replacement rati
d Rojas 2001). More recently top-drive PCPs have also been installed to produce extra-heavy oil at high rates. Hybrid artificial lift technologi
rs with primary production techniques to facilitate the economical implementation of steam injection based methods. The initial production o
arameters like heating time and waiting period as well as rock and fluid properties like porosity permeability wettability salinity and initial wa
   is based on a repetitive pattern using horizontal wells acting alternatively as oil producers and steam injectors. The recovery mechanism is
 off –excessive back reaming and stuck pipe incidences uneven build rates via sliding in interbedded formation leading to high borehole to
 y presents several aspects of an integrated approach to characterize the 1st Eocene reservoir. The approach includes the quantification and
cation between the tool and formation. This conventional technique is well suited for thick and permeable formations. However for difficult co
   small to medium sized heavy oil field and controlling the sand production due to low drawdown pressure and increased exposure the reser
 ounced. To temporarily plug the water zones and effectively stimulate oil zones with chemical diversion a new surfactant-based chemistry h


 . Different set of technologies and methodologies have been used to overcome the technical production and monitoring challenges in these

 single-stage sandstone acidizing fluid designed to address some of the problems associated with conventional sandstone acidizing fluids. T
n. The initial formation evaluation in the first two “Achimgaz vertical wells included an extended formation logging suite followed by format

 r isothermal conditions and in the absence of recharge gravitation will dominate. However gravitational effects are not always significant for

ut.� On the other hand a Ti or Zr crosslinked gel which crosslinks substantially after exiting the perforations may not have sufficient proppa
try has successfully tried different methods to deal with each or a combination of these problems. However none of them fully address all o

 ant through SCADA which allows to monitor well performance in real time.This data are used for history matching deliverability and transit te
 se in Productivity Index (PI) of greater than 5 times. This study discusses the properties of the various hydrocarbon-producing zones in the B
 andstone acidizing to one stage; (2) minimizes precipitations by delayed and stabilized reaction mechanisms; (3) provides homogeneous di
 dramatic increases in the formation permeability after treatment with the chelating agent-based fluid. The improvement in permeability is asc
 oelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Neverthele
  s are conducted to determine wettability alteration before and after treatment with the chemicals. The results show that chemical A5 gives t
 r and gas phases and then using water chemistry models to predict pH at reservoir conditions. Uncertainties in the thermodynamic models f

 ad various operational and logistic issues that have minimized efficiency and production impact. The system applied involves the use of a se

ments one mature and one emerging. The case from North America illustrates a use of the proposed process in a high-volume field developm
 h a maximum fracture event length of 800 feet. The planer fracturing scheme is consistent with low amounts of acoustic anisotropy recorded
  ured by the mere injection process. It is also known that re-fracturing and pore pressure re-distribution will re-orient the stress field not only i
 umption of a symmetric bi-wing fracture system. To better characterize the induced fracture network a semi-analytical pseudo 3-D geomech
d to evaluate the stimulation treatment carried out for several offset wells throughout the field. The analyses determined the fracture geometr


 ntially executing several fracturing treatments in a single pumping operation. Nevertheless the high direct and indirect costs and the risks a
 m 4−10%with permeability ranges of 0.241−1.116 mD showing a medium porosity and low permeability characteristics. Small reservoir p
 oil in the low permeability intervals will be left unrecovered. A combination of horizontal drilling with geosteering tools and technology for pre
overpressured conditions were modeled and the hydraulic fractures properties were derived from matching initial well performance. The mod
ements and formation micro-imager (FMI) have not only been crucial in model validation but also in order to: Evaluate production contribut
 ulic fractures. A streamline-based flow model was used to upscale geological features. Some practical assumptions were made to apply thi
meable sands can be discerned from clay dispersed in silt and sand. A true net height can now be obtained.� Through production optimiza

servoirs oil-based mud has been used in the drilling process due to the concerns of wellbore stability. Acoustic images and core was acquire
ven better data quality to fully satisfy planned objectives. A recent well (Well B in this paper) drilled offshore Abu Dhabi for ADMA-OPCO pe
ative standpoint. This is important in understanding the impact these properties have in increasing the production from a specific wellbore. Ty
udy serve as a model for what can be achieved in similar fields using these techniques. The conditions and limits of pressure data applicabili

ation formation testing tools that extend the range of pretest rates and volumes have greatly improved the quality of WFT data acquired in lo
aterflooding patterns and massive hydraulic fracturing together with an artificial-lift system equipped with permanent pressure and rate moni
offset vertical wells yet they are theoretically capable of up to three to five times the production. Higher gas prices have lead to potentially be
 filing on the regular orthogonal grid with the employment of modern seismic techniques and technologies and also the study of the distributi


 ly in place (OIIP) calculation and on development decisions. In principle pressure gradients from traditional open-hole point pressure measu

 solidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential rise o
n intuition and experience to guide their decisions. However when multi-criteria exist simplistic intuitive process may not be applicable in wh
wing of experts comparing subjective expert judgment with results of objective data analysis for example related to geological uncertainty pe
 place the well within the structure. This short paper will show the step change bought about in 3 of the wells drilled and the success and bene
NMR log. In carbonates however it has been pointed out that variations exist in the relationship between pore body size and pore throat size
ns we explored the use of electrode resistivity array (ERA) measurements in a carbonate formation for reservoir characterization. The ERA w
 solution is observed by patchy feature on core. Similarly this high level of heterogeneity can be observed downhole by borehole imaging too
 he sedimentary environment envisaged. This study helps in static modeling of the reservoir with better understanding of process sedimentolo
n the Lower to Upper Triassic reservoirs of the Rhourde El-Khrouf field based on subsurface data from six wells including well logs borehole
 ) hexane and heavier hydrocarbons (C6+) and carbon dioxide (CO2). For single-phase assurance it is possible to detect gas liberation (bu
 s. �However water zones and secondary gas cap formation in a few layers are also common. Nonetheless unexpected fluid production
 ve to look at both micro and macro scale heterogeneity for evaluation of such reservoirs which has a direct impact on the production and w
 tudy was thus to characterize the reservoir at wellbore level and conduct realistic inter-well and reservoir-scale geo-modeling for improved o
 epth at the same time and on a similar volume of the formation. These features ensure that all measurements are essentially seeing the sam
uite of formation evaluation measurements without having to use a chemical radioactive logging source. The use of a non-chemical radioac

 sed on development of water saturation error analysis charts for the commonly used water saturation models (Simandoux Indonesian Wax
 is based on development of water saturation sensitivity charts for the most commonly used water saturation models (Simandoux Indonesian
o this workflow to include estimates of relative permeability by modeling invasion of mud filtrate utilizing a fluid flow model in combination with
with typical value of 12% to 15%. Permeabilities over 2 Darcies have been measured in this field. The carbonate can have higher permeabilit
 as unsatisfactory due to the poor permeability estimation.� The effect of geological complexity on the log based prediction is overcome by
e that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay silt and sand. We present the e


 . In producing fields that have undergone several waterfloods water resistivity is often unknown in the swept thick sands and might not be re
here the time-consuming resistivity modeling/inversion is not available LWD apparent attenuation is found to be more representative to true f
  s enable a comprehensive description of fractures (morphology and type) over the cored sections of the reservoir. Meso-scale fractures can
 ons sand grains and solids tend to become mobilized and flow with the fluid being sampled. In some circumstances where significant forma
  es were absent in the cores. This paper describes how geomechanical analyses have been used to address factors leading to the developm
 l facies log which is turn up-scaled using seismic attribute map. As the area is not covered by any well or other form of data a variogram ana

  often causes incorrect frequency statistics of reservoir properties which typically exhibit a non-Gaussian distribution. As a result estimation
 ecause of bed geometry and lithology. The reservoir beds are often thinner than the resolution of the formation evaluation logs. They exhibit
 layers of shales and all layers of sands regardless of their individual thicknesses. Because NMR relaxation time in shales is much faster than

e surface. There is almost always a difference between the actual measured depth (MD) of the LWD sensor downhole and this static pipe m

  gh is largely controlled by fracture / stress reorientation. A systematic study of stress reorientation around horizontal wells and well patterns w
  us of this work is on the prediction of elastic parameters and their variation with the depth of a given reservoir. For an isotropic medium the
a for the case study presented in this paper was acquired by a cross-dipole sonic tool in a deepwater well offshore Louisiana in the Gulf of M
ady state damage /stimulation skin effect and non-Darcy flow coefficient.� In the specific case where the deliverability performance of a ve
ady state damage /stimulation skin effect and non-Darcy flow coefficient.� In the specific case where the deliverability performance of a ve
ady state damage /stimulation skin effect and non-Darcy flow coefficient.� In the specific case where the deliverability performance of a ve
 r Burgan field consists of the Burgan Magwa and Ahmadi structures. The four main reservoir units in the Greater Burgan field are the Wara
of Suez area over the carbonate reservoir. The well was drilled on the peak of anticlinal feature created by fault propagation fold of a normal
  rvoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs process
  s recorded in this field. The objective of this study is to provide a more detailed fracture network to explain the present-day reservoir behavio
 fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BK
  Saudi Arabia. The field experiment was divided into two stages: 1) Selection of the well location coring and logging experimental setup and
mate recovery. Recent advances in wireline formation testers have enabled the determination of several fluid properties including fluid comp
   pressure transient testing (IPTT) and coring. A Sonic Scanner* survey was conducted in Tunu field to investigate possible nearby formation
 plex and variable lithology become fundamentally beneficial at the time of determining an immediate porosity value with less uncertainty in c
 o ensure that all representative fluids are sampled. The most important information a continuous fluids type and property log is still not wide
e distribution and direct fluid identification can be applied to resolve the challenges mentioned above. We demonstrate the use of NMR data
 version process creates interdependencies between T1 T2 and D. These effects conspire to introduce inaccuracies in the reported porosity
ed at nonspecialists who would like to gain some knowledge of the formation-evaluation capabilities of NMR logging tools. The objective is t
 everal other factors add to the complexity of petrophysical evaluations these include: alteration of petrophysical properties in certain zones n
 multiphase flow regimes. The new tool is also more compact to pass through intervals that have high dog legs. In this paper we will briefly re

or the simulation of the formation reservoir-fluid flow during UBD. The model incorporates discrete consideration of the well with appropriate
or the main storage below. The second Mishrif layer unit 2 (M9 & M8) is a fairly high porous peloidal packstone to grainstones sequence tha

 delivers a more accurate characterization of the reservoir. In this paper we link traditional and novel fluid analysis methods to build a more c
 ferentially lower in the oil column in accord with the Boltzmann distribution. Relevant fluid features in this case the asphaltene concentration
w steady state damage /stimulation skin effect and non-Darcy flow coefficient. In the specific case where the deliverability performance of a v
 d only slight adjustments to the initial strategy have been necessary to achieve a recovery factor greater than 40% at the end of the plateau
 to extremely depleted reservoirs alternating with layers with virgin zone pressures. As a consequence the depleted layers face a significant

ere used for microfracturing (stress tests) at several sand and shale formations. The stress tests were performed by isolating 1 m of formatio
ccessive integral transforms to the governing equations and to the associated initial and boundary conditions. Thus a complex phenomenon
 gional evacuation constraints imposed. To achieve this history-matched numerical reservoir models were first run within the framework of an
 the development of two fields with heterogeneous thin shaly sand sequences where potential sand discontinuity exists. The fields are locate
eading to final recommendation. Various lift technologies were considered to replace the existing gas lift system accounting for fluid propertie
  o main re-development components. The first component aims to beat the natural production decline curve via the implementation of a mas
 ode with dual string arrangements.� Most strings require artificial lift due to low reservoir pressures and viscous fluid properties.� Gas
  bstantial amount of hydrocarbons. Optimal well placement is a requirement for these very thin reservoirs in order to drain them in a cost effe
  from offset wells.� Seismic impedance indicated that the target area comprises of beds with high degree of lateral and vertical heterogene
project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost take advantage of highe
  eservoir production completion and drilling software. Linkage between the disciplines is close and conducted iteratively operating in parall
sity of flaring associated gas if no appropriate compression facilities are available. Metering and surveillance facilities as well as reservoir ma
vided in two sections: the first section involves the reservoir model using a reservoir simulator which includes the representation of the ICVs
   for simulators and external FM algorithms. Any black-box simulator or algorithm may become a part of the system by simply adhering to the
   used to calculate the optimal amount of lift gas to inject into each well based on static boundary conditions at the reservoir and processing f
  d 5000 bopd. However a drastic decline in reservoir pressure caused the evolution of a large secondary gas cap and a steeply increasing pr
  the strategies for production enhancement opportunities identified by the standard screening exercises in a brown field and (ii) how to optim


rate the advantages of using the SRM and IAM technology. The optimization process is performed using a SRM able to run a simulation run
h field production well below the original design capacity of the production system and surface facilities. Hence further development options
mpression power or pump capacity for example could impose significant limitations over the well and surface network performance that cou
on stochastic concepts. Clusters have been deployed because of its established advantage in improving performance which in this case tran
(SSDs). In the past few years more and more horizontal wells have been drilled and completed with expandable sand screens and premium

  best cost effective solution.� �For that purpose general optimization and gas lift allocation models have been built and applied for Kha
sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drillin
 rformance based on “present-state analyses. In doing so the program has produced some of the highest productivity wells in the fieldâ€
maining reserves. The outcome of a reserves evaluation depends on the amount and quality of the data the knowledge and experience of t
 service provider share information on reservoir uncertainty. The presence of multivariate reservoir uncertainties typically makes such valuat
s paper shows how thin oil rims faulted reservoirs and those with highly variable structure were able to be developed more efficiently. By red
 reduce the volume of attic oil. Generally the location of the top reservoir is visible on seismic but with significant sub-seismic variations in the
 s in an irregular well placement pattern as it attempts to conform to both time-invariant reservoir properties (e.g. permeability field which ma
act. Based on a comparison of downhole pressure data with data from simulation models the operator concluded that a connected aquifer
es.� Further it provides a comprehensive method to develop a production forecast for a potential sidetrack.� It also presents a set of cr
gh resolution geological models together with reservoir simulation models using parallel computing allow a more sophisticated workflow to op
 rall flow throughout the reservoir. The gradients of NPV over the lifespan of the reservoir with respect to flow rates in the pseudowells are co
oduction regime is described. The initial stage of oil production is considered before SC reaches the production well. The model accounts for
ke into account superposition effects in multi-well and multi-rate scenarios. Notably regarding fractured wells we are able to accurately mod
wells where fractures can have infinite or finite conducting properties. Using the principle of superposition our model fully accounts for interfe
 alculation of the prior covariance matrix (or its inverse) can be time consuming and memory intensive. We propose a fast and robust adapta
 uations needs to be efficient for large-scale applications. We propose an efficient and fast approach for sensitivity calculation based on the


 be quite different yet they are not completely random. In spite of their differences there are characteristic geological patterns which occur i

energy interaction with over-burden and under-burden rocks.� The solution procedure and the treatment of phase transition to achieve sta
ount of CPU overhead. This general formulation approach was developed as part of a next generation reservoir simulation project (DeBaun e
 quences from the bottom up and produces from multiple formations. Wells are placed close to the oil-water contact sufficiently far from the

required the simulation of special wellbore dynamic behavior specific to horizontal/multi-lateral wells. It is a significant challenge to capture su



ed. The last three techniques-type-curves require good understanding of the reservoir model as well as the parameters controlling the well be
ure broken-gel viscosity yield stress formation damage and fracture conductivity on low-permeability-gas-reservoir production with studied
n-Newtonian characteristics was rarely taken into account before and is the subject of the current paper. For this purpose an enhanced th
 acture length conductivity orientation etc. This project investigates the modeling and interpretation of pressure transient responses of mul
€™t completely account all phenomenon within reasonable computational time. New approach for simulation of multiphase multicomponent
 acial slip is calculated using a displacement discontinuity (DD) method. An interface crossing criterion (Renshaw and Pollard 1995) is used
ology has enabled us to run numerical models with nearly the same speed. Although analytical methods have been continuously improving
 paper the same problem of non-Darcy flow in a vertically fractured well is revisited for the cases of rate-controlled drawdown tests. We argu
  number of production logs and duration of production period on the accuracy of the results. Introduction The process of inferring reservoir/
 e dimensionless productivity index for improved fracture stimulation design and evaluation. Other issues investigated in this work were the d
emained impossible and optimum pumping schedules were typically established by trial and error within a given reservoir. The present pape
 perforation misalignment angle cement/formation properties stress contrast and fracturing fluid parameters. The model developed has a li
and other methods to determine the factors controlling and related to fracture spacing in the Lisburne formation northeastern Alaska. By com

 t different parts of the reservoir. The dynamic behavior of pressure and production performance from few wells (total seven wells) producing
 y assumed distribution of injection profile along the length of the well including injection profile that is uniform skewed toward the heel or the
 novel concept of the injectivity productivity index (IPI) has been developed to consider a pair of wells comprising an injector and producer an
n particular analysis of the reservoir production behavior and the fluid contact movement over time is essential in narrowing the uncertainty in
 hen uncertainty on reservoir pressure and PVT data is significant. In this work two different methodologies are proposed. First a sensitivity
ering units) and instrumentation may have an adverse influence on the accuracy of production WC injected water and formation pressure m
 cies distribution. Results also show that there are at least two main rotating cells at steady state: one in the gas cap and one in the oil colum
 ed in constructing experimental designs and using response surface models to interrogate the experimental design outcomes. After extens

 cretization scheme is applied to reservoir simulation on 3D structured grids with distorted geometry highly anisotropic media and discontinu
 y fractured reservoir and of the flow picture in the near wellbore zone in general. Introduction Near wellbore zones are very important areas
 mposite curves can be generated from properly designed laboratory experiments on representative cores or by history matching fine grid sin
the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture modeling

odel. The dual porosity system is modeled by using two coupled grids: one for matrix and one for fracture. The interaction between the two c
tions. Fracture permeabilities can differ in orders of magnitude which results in very different flow velocities in different parts of the reservoi
mplex fractured reservoirs. The multiscale solver approximates the flux as a linear combination of numerically computed basis functions defin

n particular the true predicted oil production lies within the band of predictions generated with the RML method and is not biased. We also a
 k has been conducted using finite difference simulators which are handicapped with regard to these calculations in that numerical dispersio


 osed into a set of coarse-grid cell values and a set of solution details which indicate the smoothness of the solution. This decomposition is r
model allows for receiving phase equilibrium curves and other thermodynamic functions in analytical form thus it achieves the thermodynam
e indicators of existing wells derived from historic dynamic data (fluid production rates pressures etc.) static data (reservoir properties etc.)
alizations) is continuously updated to honor data without rematching data assimilated previously. Because of these features the method is fa
ese realizations could be quite different yet the responses are not completely random. In spite of their differences there are patterns whic
. The effect of simulating flow in both the annulus and the tubing was investigated in two case studies involving ICDs: a synthetic case and a

 nnot be run in isolation. A multiple reservoir simulations coupling controller that dynamically apportions global production targets among diffe
  Archie's law this simple model has only two parameters: An exponent� called the conductivity exponent � and the water connectivity p

 rcy flow in porous media in general literature concerning the theoretical basis of the Forchheimer equation and experimental work on the ide
  e water level 3) significant shifts in the measured pressure potentials between the lower and upper part of the transition zone 4) gradients
nal reservoir pressure was in the range of +/- 7300 psi; however the past decade has seen a marked decline in both pressure and associate
 izontal stress (Sh).� In the case of deviated wells a stress-tensor diagram defines Sh direction with reasonable accuracy provided wells c
 � Participants felt that maturity in itself made a challenge for deployment and enforces the need for effective Change Management. Deplo
 oil in Russia has not already reached its peak level and that it will increase above the current production rates because of improvement of ec
a in the mid to late 1970’s. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980 but UK
 ls but the input data requirements are far greater. Typically in the modeling papers little information is included on how the input data is obta


 d the intervals contributing most to the water production were isolated. Water cut was significantly reduced. In some wells the saturation an
 Venturi-based flowmeter with a gamma ray source and detector. Real-time data were used to optimize the settings of the downhole chokes
 d in the short string section of the dual completions. The monitoring of the water breakthroughs and finding the bypassed oil became crucial
mini-spinners and optical gas and array resistivity water holdup sensors provided a viable logging alternative with a 40 000 ft cable specificall

  psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetratio
  psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud. In the course of several penetratio
 ecture requires below packer installation of the gauges which in turn increases the risk of leakage in the electric lines of the system. In this p
 luid alters as the sample is brought to surface from the high-temperature and -pressure conditions downhole owing to acid gases and salts
 valuable not only for production monitoring but also as an investigative tool for larger-scale problems such as compaction subsidence dep
ted with a newly developed� location technique based on S-wave back-azimuth. While originally a couple of hundreds of induced events p
 d productivity underperformance for wells. Various methods have been used to evaluate fracture height prior to the fracture treatment. Thes

 he acquired data shows that large temperature gradients exist across the wellbore during startup and early production which is consistent w
wells that produce liquids whether they are produced directly from the formation and/or condensed well fluids water and hydrocarbons. This
  wells that produce liquids whether they are produced directly from the formation and/or condensed well fluids water and hydrocarbons. Th
without initially performing a wellsite operation to lift the tubing shoe above the reservoir requiring either a workover rig or a snubbing unit. Ru
 in the oil sample along with the known location of each tracer downhole allows qualitative information to be generated about fluid flow in the
 s basis and flow loop tests are discussed. Introduction Well monitoring surveillance and problem diagnosis are critical parts of the product


 for improvement or optimization would be taken based on this data. However the answer to questions such as "how good is the decision?" o
 op publications vary hugely with changing inclination. The ability to measure low oil rates and small holdups in this stratified flow is determin
n. Over a period of six months (Nov. 2006-May 2007) 127 static bottom-hole pressure (SBHP) surveys 26 pressure buildup (PBU) tests (inc
production decline a chemical treatment to remove suspected emulsions and polymers during drilling was conducted. Immediate post treatm
ation is identifying candidates and to recognize potentials we need to have efficient reservoir/production data. Because the whole process st
 nning and procedural design as well as real-time operational and interpretational support. It is becoming increasingly critical for operating an
model to analyze permanently installed distributed temperature measurements. By modeling a range of typical flowing scenarios we demonst
s another region near the heel of the well although the area is too far from the microseismic observation well for any associated microseismi
e gravel pack is completed the fiber responds to the reservoir temperature plus the effect of Joule-Thomson warming of the flowing oil cause
 oped to pass power and data from the upper to the lower completion. In a recent subsea deployment in the SouthEast Asia such a coupler
 n from core and dynamic measurements and by integrating image logs with nuclear magnetic resonance (NMR) and conventional openhole

 this isn’t a cost effective solution. Building non-parametric (Artificial Intelligence) production rate models based on pressure and tempera
 multiple spinners for revealing stratified velocities travelling inside highly deviated completions. Pulsed-neutron (PNL) technology provides tw

 t effective methods available to date for saturation monitoring as being the deepest through casing measurement in terms of radial investiga
maintenance by peripheral water injection also considered an important step in tuning simulator parameters and optimizing the Field Develo
  front advance has been observed in different reservoir units. �It has been observed that water front has advanced much faster in the hig
nes a coarse (3 to 5 m resolution) resistivity distribution from a basic initial static reservoir model built from logs. This study refines the mode
s interest and activity level little attention has been paid to the CBM completion fundamentals. Perforating is a critical part of this process es
  properly characterizing the cleats will help in determining which of these seams should be completed to optimize the production. In addition
 ress clastic rock adjacent to coal seams and allowing these induced fractures to connect and grow into the coal seams. This paper presents
emselves as high-fracture initiation and propagation pressures which lead to low injection rates and high treating pressures. These losses re
ed in isotropic rocks.� Using finite element analysis (FEA) and numerical modeling with continous mechanics and transverse anisotropic
creasing surface horsepower.� Economics and logistics practically limit the pipe size to 2 7/8 in. for deeper wells and 3� in. for shallow
 d periodically mud log.� While these tools can identify significant structural changes and hydrocarbon shows along the lateral they provi
 properties for well positioning and reserve calculations. The seismic survey is not only interpreted for structure horizons and faults but also a
GD pad are significant. Finding ways to use steam more effectively in these operations should result in increased production efficiency and im
 epresents 15% of total natural-gas production. Approximately 1.7 Tscf of this gas comes from more than 40 000 coalbed gas wells complete
 ated their older vertical wells with demonstrable success. This success is providing compelling opportunities to enhance refracture treatmen
 ure as well as fluid types such as oil or gas. To generate wormholes of various diameters and penetration depths different acid types and vo
ct has completed a four-years operating cycle while continuously maintaining the field production rate with an acceptable ESP failure and run

m the wellbore is lost in the process and cannot be utilized for some other operation. This paper describes a new technique of artificial lift wh
his goal was achieved through optimization of the development system and improved development of oil-water zone reserves and the reserv
 is paper explains why an openhole gravel-pack completion was the best option in spite of some challenges such as large vertical net pays a
ar full bore feature allows normal cementing operations to be preformed with a special cement wiper plug. A control line is connected betwee
 Sands have different oil retainer capacity and flow from clean to dirtier sands. The lower most units comprise of unconsolidated sands that a
½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization technique f
½ The produced liquids considered in the analysis can be water and/or liquid hydrocarbons. This paper presents an optimization technique f
ails the process followed to achieve this milestone for the first time in Kuwait. A multi-disciplinary team consisting of Geology Petrophysics G

well was managed to improve and sustain oil production by eliminating water production. Monitoring the rate and the flowing pressure in real
-front movement. In this paper we address several technical issues related to downhole controls. We consider a single system comprising t
 sustain oil production by eliminating water production by use of the variable-positions flow-control valve. Monitoring the rate and the flowing

mental model has been built for the purpose of studying the production performance of the abovementioned well configurations. Production pe
s practical experience gained during the development and deployment of this system. Introduction During the completion process of a well
  riables (EVs). Methods developed to facilitate EV factor collapsing are also discussed (the partitioning of levels of each factor into nonempty
  rt because of the high speed at which acid spends upon contact with the high temperature reservoir. The quest to increase the effective half
 quality found in the southwestern edge of the field required stimulation to produce at economic rates. A hydraulic fracture treatment was perf
p suspend proppant in the slurry both during the fracture pumping and also during fracture closure. The primary goal was to be able to create
 linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yar
atments in an attempt to control excessive leak-off during the treatment. The vertical well treatments target several reservoir sub-layers with
previously only achievable with 3.6-4.2 kg/m3 (30-35lb/1000gal) gel loading in similar geological conditions.� In addition to reducing dama
  claims as to which one may be most appropriate. This paper compares four different flowback aids: microemulsion two water-wetting flowb
 o 3D (P3D) hydraulic fracture simulator with a rigorous layered modulus formulation is used in this study. The fracture height calculated base
operating companies have been seeking other cost-control measures including reducing the number of additives in fracture fluids and minim
 ring fluids. This paper describes the process to properly design fracturing fluids using flowback and produced water. The importance of flow
 evaluate and compare well performance. Micro seismic data tracer logs and pump-in data were used to calibrate and constrain appropriate
 by conventional frac-and-pack. When this procedure is followed the fracture is forced to propagate along the upper intervals. This novel tec
aterials. The case study clearly demonstrates the challenges encountered in the attempt to increase the fracture half-length in order to impro
agents in terms of flow distribution and uniform coverage is limited when it comes to treat such complex wells with long openhole intervals (s
mics to the entire operation. The key fluid for treating high water cut wells is a Viscoelastic fluid that provides self-diversion from water to oi
 ages with a composite bridge plug have been applied in some cases with limited success. The time consumed in the completion operations

ntered unexpected reservoir challenges which has kept them from achieving their production targets. These wells require stimulation to rega


es posed by the Gandhar candidate wells. Earlier attempts to fracture wells had been unsuccessful. In addition the water bearing sand posed
 and analysis graphical design charts of the dimensionless productivity index and pseudosteady state shape factors for use in improved hydr

tensive knowledge gained in Western Siberia can not be translated to the less frequent but well engineered and planned stimulation campaig

control line becomes pressurized and transfers this pressure to a piston in the valve immediately above. This piston squeezes a C-ring and m
 Finite Element Analysis (FEA) was conducted to estimate the stresses in the cement and formation near the wellbore with sliding sleeve. FE
ring in an elastoplastic medium has been represented in the model as brittle hydraulic fracture growth in a quasielastic medium. The medium
 tivity associated with the lack of polymer damage.� In this paper laboratory test results for the new fluid are presented along with three

urrence of water-bearing zones lead to the selection of foamed VES fluids.� This technology was successfully applied in the Morrow Sand


 ity of wells and to mitigate the aspheltene deposition issue by allowing the wells to produce above the AOP. The option of acid fracturing was
2006 which indicated that the polymer concentrates only in the filter cake and that flow along the fracture encounters significant yield stress w
 c fracture treatment while the successive offset was completed via a single-stage fracture treatment.� The evaluation tools utilized to dete

itions several milliseconds discrepancies between measured and modelled SH-P-wave traveltime differences may appear along the receive

 le of a rock sample accurately and rapidly and used the instrument to characterize fracture surfaces after acidizing. The profilometer measu
nd fluid flow. Fracture azimuth is traditionally provided by the horizontal stress anisotropy from open hole sonic logging. Unfortunately in Wes
on propped fracture height as well as insight into propped fracture width. In this new technology a non-radioactive tagging additive is incorpo

s of medium- and low-permeability reservoirs. Some wells cannot maintain stable production rates and have either been shut-in or are on in
 velocity (hence: rate and flowing pressure) Ratio of free liquid rate to gas rate Stress on the proppant Type of proppant Thus appa
e Carter leak-off model do not apply in this zone. This work presents a fundamental study of fracture tip behavior in high permeability formati
 d acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells could
 fracture treatment in this case is more heavily weighted on the achievable Stimulation Index (SD) for a given set of reservoir parameters and
cipal stress which is consistent with observed differences in the injection pressures. Introduction The effectiveness of hydraulic-fracture stim
his process is therefore a very vital task. In this paper we present a quantitative model to predict proppant flowback. The model is based on tr
  associated pressure response in order to obtain an insight into the refracture process. The modeling results show that a refracture treatmen
 cturing fluid is evacuated from the well and fracture being displaced by the oil and gas flow under the influence of pressure differential. The q
SA) combines the use of cross-dipole shear sonic analysis carried out before and after hydraulic fracturing and adequately supported by othe
w polymer concentration via leakoff and measurements of flow initiation gradients. The paper will discuss the experimental set-up and som
  pressure limit of 3000 psi given by the Floating Production Storage and Offloading (FPSO) facilities. However the injection rate was decrea
e heights on the borehole wells together with a representative Mechanical Earth Model (MEM). In these mature fields an accurate evaluation
e main fracture direction and by their length. Quantitative comparisons on fracture length width and injection pressure are made for several o
  sector of the North Sea. Several papers have discussed this technology but so far none has presented a rigorous analysis or solution of the
  water-packs and shunt-packs. The experiences gained from these operations have now become part of BP’s open-hole gravel pack be
hods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time cons
hods of cementing a liner in place perforating fracturing and repeating the process for the number of stages required can be very time cons
arget reservoir is a clean sandstone reservoir. The horizontal drain is 1155 feet (ft) long. The reservoir permeability is ranging between 0.1 an
 s individual lateral testing allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along with
 operation of the ICD is minimizing reserves left behind. If water breaks through in a well without ICD these hydrocarbons are lost and canno
 ultimate recovery has helped optimize overall drilling completion and production costs. Electric Submersible Pumps play a key role in produ
 lateral testing and allocation of production rates to optimize each lateral contribution and the overall commingled well rate. Along with real tim
ertainty across a range of production scenarios. We assess the implementation of an intelligent horizontal well in a thin oil rim reservoir in the
sure region close to the fracture tip). The controlled laboratory experiments showed planar fracture propagation trends as expected from thre

culating the productivity of a laminated clastic reservoir and we illustrate the method with a field example from Malaysia. A single well predicti
uction. To accomplish this task a 3D full field model was created. First several 1D Mechanical Earth Models (MEMs) were developed. These
 serves the purpose of puncturing through the casing.� This paper presents recent research that looks into the impact of perforating on m
ed method which cleans perforations with more efficiency than conventional static underbalanced perforating method. In addition a passive
 ation pressure and BHT followed by high CO2 H2S production and improper well clean up contributed in the increase of operational risks an
 nosis of these results indicated that the static underbalanced condition and the shaped charges used were not enough to effectively clean th
 o tends to be deeper. Deep-penetration perforating charges are required to perforate past the damaged zone. Experience indicates that und
  rig to remove the completion prior to perforating is in many cases not cost effective leading to foregone opportunities to extend production
 rforating technique utilizes a unique job design process and specific�equipment to ensure the guns are detonated in the correct environm
 because the mud cake invaded filtrates and particulate pore plugging are progressively removed at the vicinity of the sandface region; (c) t
s paper outlines a solution to these challenges. For a CT perforation campaign in the South China Sea a CT string equipped with fiber optic
 itions of similar perforators. In this paper we analyze the failure modes of continuously phased perforators for both gas well and oilwell appli

 ere kept constant. For both rock types the reactive liner charges produced perforations with lower productivity than the baseline convention
perforated using large diameter high shot density tubing conveyed (TCP) guns with deep penetrating charges shot underbalanced using the
ractures. Using the smart completion with the conventional rate testing (the plant's testing facility) required longer time to reach the best poss
  made to develop the field with horizontal openhole gravel packs for both producers and injectors. Fifteen production wells and eleven injecto
ed interval during the initial completion program was 310 ft with a maximum perforated interval of 571 ft. The typical production-casing strin
  light (50� API) sweet crude oil. Hawtah field is a mature and depleted reservoir and in order to maintain economical levels of production
allowing unacceptable rates of sand production. The well was worked over and the tubing with eight control lines and a premium-sand-contro
 ll. This condition resulted in the closure of the well for high sand production. To restore production from the well current economic realities f

 ion methodology in poorly sorted unconsolidated sands with high fines content in Brunei also indicates that the situation is not much different
ge and fluid compatibility testing. To translate the robust design into a fluid system which can be applied effectively in the field a thorough fit

 andable screens with annular barriers and blanks between each section of sand is the only completion option except in fine sand environme
 g high angle openhole intervals without the need for alternative flow path screens but retaining the advantages of high gravel concentration s
omplete gravel-pack process and accounts for fluid flow and gravel settling in different flow paths. The presented simulator tracks the fluid flo
 avel packing of the associated wells are thus introduced. A significant level of progress has been made in recent years towards overcoming
uting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel pa
 ting the perforation packing job are presented. This study also discusses the current practices commonly employed in cased-hole gravel pac
h optimal “structural stability for the given inherent material strength of the formation rock can be achieved by targeting perforations in the
elopment and requirement for artificial lift increase drainage area and improve sweep efficiency. In the early stage of field development a re
  rol and fines migration prevention. The proper candidate selection treatment design treatment execution production management and co-

 sanding issues it was facing which involved prediction prevention monitoring and if required remediation activities. The first step in the S
 on of economic production and overestimates or underestimates of sanding risk increase the chances of serious economical loss. This rais
  the model backed up by the core laboratory test data observations from core inspection and thin section analyses revealed the rocks to b
ious stages of the tests to simulate water cut. The failure and sand-production processes were observed and recorded using a borescope in

own at which failure of the formation will start. A further development are models which try to predict the total volume which can be expecte
 d 3) properties of drilling fluid and its interaction with shale formations. The likelihood of wellbore instability and sand production for the deve
ems have been used in Saudi Arabian fields in matrix acid stimulation and in leakoff control acids during acid-fracturing treatments. These s
uids—an acid viscosified with polymer an emulsified acid system and an acid viscosified with surfactants—at elevated temperatures of 20
 h solubility and highly fractured/vugular nature carbonate reservoirs in the Permian Basin show excellent response to acid fracturing treatme
 nating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and
 rnating stages of polymer pad. These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and
ugh coiled tubing and then with the viscoelastic diverting acid system bullheaded down the production tubing; production logs were acquired
 d that much of the rock is weak and potentially prone to deconsolidation after acid stimulation. Weakening of the rock matrix often leads to
  times. This paper discusses the application of a new viscoelastic-surfactant (VES)-based self-diverting acid system for stimulation of more
g Tubing Pickling Bullheading Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid syste

ted optimum acid system placement and diversion techniques need to be applicable in the field in a simple manner without impacting the o
timulation of the formation. Therefore opportunity exists to mix HCl with an organic acid to achieve productivity enhancement by optimizing


 sitive skin factors following the fracture treatments irrespective of the fluid system used. In at least one case a well stopped producing after
mechanical or chemical.� Mechanical control of treating fluid placement can be accomplished by coiled tubing with an inflatable packer or
ty of the formation to wellbore fluids the impact of the wettability changes and near wellbore damage is not fully evaluated on all formations a
 resented. Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy textu
nting results and has led to a common misconception that restimulations “don’t work. Production statistics of a well alone may not off
e of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cau
 traditional polymer-based fluid. This VES-CO2 fluid system combines the benefits of viscoelastic surfactant-based fluid—such as low forma
her important feature of the integrated solutions is a proper risk assessment based on available data. Often especially in old fields informa

 e objective of the present field case study was to place the stimulation fluid equally throughout all intervals of the oil bearing layers while tem
lly and systematically examined by a dedicated team of ZADCO and Schlumberger technical professionals. The criteria used to judge the us
  derivative function is utilized to ascertain if the data contains any portion of reservoir-dominated flow. Two synthetic data examples are pres
 in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with re
e the completion efficiency. The field examples presented in the paper demonstrates the application of the production optimization methodo
 ypes and pressure regimes. A selective inflow performance (SIP) test was carried out during production logging (PL) jobs in some of these w
 (10 to 20%) but with the right mud it can reach 50% and in some cases 100%.� Such well completions are referred to as limited-entry re
  minutes even if we have a perfect pressure gauge with 0.0 psi resolution. After the initial propagation pressure starts to diffuse or propagat
in pressure transient tests and when a test is run how to minimize the downtime.� The case studies presented here are for wells on elec
n methods represent our independent implementations of their methods based on the material presented in their papers not the original algo

acture storativity and fracture conductivity. An infusion of geological knowledge helps reducing uncertainty associated with any well-test interp
 s for a number of decades. Many hardware technologies and interpretation methods have been developed to acquire better quality reservoir
 ial extrapolated pressure (p*) and estimating AOFP. AOFP is an important gas well flow parameter and is used to determine the commercia
evaluated different well testing & monitoring strategies based on multiphase metering use. A compact dual-energy gamma-ray Venturi multi
ue evolution of the gas and condensate wells provide an in-depth view of the actual well performance. The evolution of the real dynamics of

  in high water cut and high gas volume fractions (GVF).� Some meters can be unreliable in measuring oil rates in certain conditions which
 his process had to be revalidated and the operational capabilities confirmed with all of the logistical challenge of this environment. A number
a wet-gas meter in 90 to 100% gas. The new interpretation model was developed for a commercially available multiphase flowmeter consistin
wells were selected carefully to represent anomalies that need to be investigated for possible proactive actions. Some of these wells were tes
   With the recent dedicated Gas Mode developed by Schlumberger it is now possible to test both gas and oil wells with the same hardware.
 e benefits of such a workflow can be summarized as follows: •�� Improved well test interpretation by using simulation models that h
perties contacted in-place fluid and reserves. Our main objective is to introduce a new practical tool for the analysis/interpretation of the prod
 ay otherwise have gone unnoticed. In this paper we endeavor to reconcile the advances in well-test interpretation and in measurement tech
ehole conditions.�Numerical methods have been developed to interpret these measurements to offer distributed characterization of matrix
 g engineering process evaluating the capacity of cement to provide short-term zonal isolation and providing measures that can be used to p
 odel is then checked against the occurrence of breakouts using a mechanical earth model built along CRC-1 well. We conclude that the max
RTM) serves as a decision support tool. The major steps are (i) identifying the system and the sources of degradation through characterizati
etween systems. The integrated approach has been used to integrate multiple reservoirs with common and advanced surface facilities to pro
 nding processes as well as designing appropriate injection or mitigation strategies. We present simulations of CO2 injection into saline aqu
 y frameworks and standards for CO2 geological storage. The preparatory phase of the project involved a baseline geological site exploratio
moter Enhanced plant growth. The capture and storage of CO2 continues to accelerate as new projects are initiated and existing projects co
c seismic logging drilling and laboratory test data. Such a model consistently describes ambient stresses fluid pressures and poro-mecha


ubsea developments in combination with ERD wells can increase oil production and lower total development cost. The drilling progress was
mations also create limitations for push-the-bit rotary steerable systems to deliver the required directional performance to land wells. To ove

which is located in Michigan’s Otsego County. This field was discovered in 1974 by Shell and produced 2.6 million bbls of oil during its pr
eed 90% purity. Due to the high concentrations of CO2 some wells were shut-in 60 years ago others have been developed for CO2 product
 an be employed. A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysic
  Simulation studies show that reentry drilling through vertical wells can help break the condensate bank damage and significantly increase w
 on the effect of the component grouping for fluid characterization. A preliminary work consisted of reducing the original 14 components ident
oe. 2) Massive fractures resulting in loss circulation. 3) Uncertainty with fractures volume estimation. 4) Fracture shut-off in open-hole section

 ormed through-tubing with and without isolation packers. Two Candidate wells were having 6.5 open-hole size at approximately 4 200 mete
   multiple oil producer zones revealed the necessity of a complex thru tubing zonal isolation solution before performing the water shut-off trea
  the economic cutoff limits for the wells in question. The reason for this type of water management is the lack of confidence in the water shu
  oduction Excess water production in oil well is always a cause of concern. There are many side effects of this bad water production: It adds
  ayers. This paper will discuss the development implementation and results of an innovative solution for water shutoff that was engineered
  these fields life cycle. As drilling technology advanced in the past years horizontal wells became the norm in many fields managed by Saudi
ntry of most of the water was from the toe of the horizontal section. Based on economical and technical feasibility fiber optic telemetry enable
 these elements adversely affect production assurance in deepwater systems and are key risk factors in assessing deepwater developments
s and measure droplets and ten conductivity probes were used to obtain phase distributions. This paper provides new experimental data on
ups and pressure gradients. A high-speed video system was used to observe the mixing status between oil and water and to determine the fl
 lity in the reservoir and the change of the choke performance cannot be correctly addressed.�Moreover the large number of uncertaintie
urface network performance that could impact long term field management plans if they are not properly identified and solved. PEMEX E&P
 wo distinct layers of hydrocarbon deposits are considered marginal from reserves point of view; the upper deposit is a gas condensate layer
ded pour point gel strength and shear-dependent viscosity measurements under both dead and live oil conditions. The wax deposition tend
e fluids to the laboratory for analysis. Both methods are compromised by the reactive nature of CO2 whose concentration can change signif
 entrations in one zone to significantly high in others in the same field. In addition accurate quantification of CO2 from reservoir fluid samples

 are initial producing gas/condensate ratio from the first-stage separator initial stock-tank liquid gravity in �API specific gravity of the initia
 a combination of laboratory experiments and elaborate calculation procedures using EOS models. In previous work we found that Whitson
osed to compartmentalization) which is key to the efficient economic development for many deepwater projects. � Introduction In the pa
ss unexpected fluid production such as water or excessive gas is an undesirable outcome. A formation tester equipped with an extra large
  also trigger contacts migration and unexpected injection fluids channeling or breakthrough. A large number of Downhole Fluid Analysis (DF
operties from the measured data. These predictions can be used in real time to optimize the sampling program to help evaluate completion
ee-component hydrocarbon phase in cases of black-oil/extended black-oil formulations. In turn compositional interactions are entirely neglec
 and reservoir compartmentalization analysis. This process is not limited to light fluid evaluation or sandstones. The combination of DFA Flu

 tions. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas composition
 scavenging. Many days of flow may be required in order to sufficiently passivate the metals so that an accurate H2S concentration can be de
ormation testers (those from before 1990) although yielding comparable results had larger error bars because of system limitations in repea
nsistently applied the synergy delivers a much more accurate and robust picture of the reservoir and the fluids therein. In this paper we revi
 ifferent types of formation fluids from the well logs alone. This paper presents challenges of fluid identification process during the exploration
s oil and water all in hydraulic communication. However the pressure testing did not indicate a gradient in hydrocarbon composition. Fluid w
 onal approach to pressure gradient analysis and uncertainties in inferring fluid properties and contacts from pressure gradients. In this contr
 hough these fluid complexities have been largely recognized conventional pressure-depth plot and pressure gradient analysis are still perfo
 mpling. The technique provides real-time analysis of sample contamination. Methane detection is essential for condensates and lightly color


 roleum reservoirs through detailed pressure and fluid analysis measurements. With the correct understanding of fluid characteristics in the
tes uncertainties in optical measurement and contamination into uncertainties in fluid properties such as color composition and GOR. The
es from the measured data. These predictions can be used in real time to optimize the sampling program help evaluate completion decision

e and/or non-condensable hydrocarbon components is treated. Introduction Reservoir simulators require a robust means to evaluate both th
sions). Two heavy oil samples from South America were used for this study. The stock tank oil (STO) samples were recombined with the co




ons is a significant advance that provides accurate fluid information for characterization of the reservoir flow assurance facility design prod
 s of well control. Another important factor to consider if the dew point is close to the formation pressure is that pressure drawdown has to be
tion but some fundamental needs from operators were not addressed properly such as the ability to collect representative samples for phas
 tative fluid samples for analysis.� The paper presents a solution to this problem and results obtained in number of well tests performed in
both simple organic acids and polycarboxylic acids) with calcite. All of these models were described in detail and compared with each other.
d surface pressure is necessary to maintain the operational and economical advantages; however formation damage severely impacts the i
  soluble inorganic or organic carbonates and the reaction generates calcium carbonate particles. The resulting particles were characterized
 n performance of three new chemicals and two commercial products were evaluated under static conditions along with performance assess

 ons and different pH values. A power-law expression was proposed and verified for the precipitation rate of the naphthenate-soap particles.
shed zone. This weakened damage zone is an important factor in crushed zone removal and in the onset of sand production. An essential fi
   the perforation tunnel immediately after penetration of the rock by the shaped charge jet. Predictions of the required underbalance to remo
  le inhibitor and hydraulic fracturing treatment in Western Siberia. It allowed the operator to place significant amount of scale inhibitor within t
e inhibitor in the Uinta Basin may show signs of scale buildup in as little as 30 days. The effects of the scale accumulation can be seen every
 oduction.�However they may also be used to address other produced water management issues such as inorganic scale control.�
  ine tools Strontium Sulphate scale requires special techniques to remove chemically and/or mechanically and present the most challenges
  paper addresses is what has caused this reduction in sulphate concentration. The formation brine Mg/Ca ratio is < 0.1.�Over geologica
east correlation criterion ensures that there is a minimal effect of changing one parameter in one region to the responses from the other regi
 d model into a Dual-Porosity Single-Permeability (DPSP) streamline simulation model and history match results are improved. Based on field
By incorporating streamline technology into existing and new reservoir development planning we are able to demonstrate significant benefits
 of the typical problem wells have been identified from the production data as well as well registries and their sector models have been extrac
 tic surveillance solution that synchronizes the data collected daily in more than 200 wells. Conventional production tools including Nodal mo
 sures the interwell resistivity distribution between observation wells at the pilots. Interwell resistivity data can be used to infer the water satura
d to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. Extensive surveillance operations provides the data ne
    rates. Hybrid artificial lift technologies such as bottom-drive progressive cavity pumping which combine features of the ESP and the PCP
ed methods. The initial production of heavy and viscous oils can be accelerated by the adequate use of downhole heaters that by providing
bility wettability salinity and initial water saturation were studied.� Introduction Crude oils whose API gravity smaller than 20 are called h
 jectors. The recovery mechanism is a combination of horizontal steam flooding between wells and cyclic steam stimulation of each of the ho
  ormation leading to high borehole tortuosity. It is significant to note that due to these difficulties one of the planned horizontal wells was sidet
 roach includes the quantification and distribution of the evaporite minerals and porosity analysis of a possible dual porosity system and eva
 e formations. However for difficult conditions such as laminated formations or formations with low matrix permeability and formations satura
re and increased exposure the reservoir. This paper discusses about comprehensive geological study identification of target oil pools well
  a new surfactant-based chemistry has been introduced. When mixed in brine it forms a high viscous gel. The gel maintains its viscosity wh


  and monitoring challenges in these lifted or pumped wells. Petroleos de Venezuela (PDVSA) at the opposite of Canada companies is curre

entional sandstone acidizing fluids. The application of the fluid system is sandstone reservoirs with bottom hole static temperatures greater th
ation logging suite followed by formation testing and downhole PVT sampling achieved using a wireline formation tester (WFT) that had a du

  effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization

 ations may not have sufficient proppant transport capability to complete the treatment successfully. Varying treatment conditions such as mi
 ever none of them fully address all of the challenges discussed. This paper describes a detailed laboratory evaluation of an innovative solid

 matching deliverability and transit testing. Included in the paper are equipment selection design development details installation procedur
hydrocarbon-producing zones in the Bach Ho field. A general discussion of reservoir properties and damage mechanisms is included which
nisms; (3) provides homogeneous dissolution of formation; (4) has a much lower emulsion and sludge tendency than conventional fluids as
e improvement in permeability is ascribed to the removal of carbonate minerals and soluble clays without secondary metal precipitation. Slu
over polymer-based fluid. Nevertheless VES were known up to now for their limitation to withstand elevated temperatures. Detail laboratory
results show that chemical A5 gives the best wettability alteration at high temperature with minimum formation damage. The improvement in
 nties in the thermodynamic models for formation waters at high temperature and pressure as well as uncertainties associated with the flash

 stem applied involves the use of a series of mechanical openhole packers deployed on the production liner with a frac port located between e

ocess in a high-volume field development and the value of applying new technology to optimize the process until it reaches a “SMART-fa
 unts of acoustic anisotropy recorded. Increasing treating and bottom hole pressures with time observed in this study indicate fracture length
will re-orient the stress field not only in the near well bore area but also in the far field. Theoretical modeling and world experience suggest th
semi-analytical pseudo 3-D geomechanical model was developed based on considerations of the conservation of injected fluid mass and the
ses determined the fracture geometry: fracture length fracture conductivity and permeability. The results were then used to calibrate a log-d


ect and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology to
lity characteristics. Small reservoir pore throat structure and low permeability nature of the rocks makes normal gas production with convent
 steering tools and technology for precise lateral placement in the low permeability reservoirs in addition to a low fluid loss drilling fluid system
ng initial well performance. The model was calibrated with well and field performance data through 2006. The calibrated model was used to f
er to: Evaluate production contributions based on backpressure Evaluate drainage area (from multiple production logs) Understand geolo
 assumptions were made to apply this technology in our study. Multiple models were generated using different upscaling scenarios and techn
ned.� Through production optimization modeling it is possible to assess the economic viability of completing and stimulating highly lamina

 coustic images and core was acquired in the early stages of the field development. After the invention of a micro-resistivity imaging tool it wa
hore Abu Dhabi for ADMA-OPCO penetrated the main three reservoirs and presented a rare opportunity to address these challenges and im
 oduction from a specific wellbore. Typically we characterize these hydraulically induced fractures in terms of fracture height length width a
and limits of pressure data applicability in this environment are set forth. In tight gas reservoirs new generation wireline tools which employ e

he quality of WFT data acquired in low permeability reservoirs. Job design and planning has always been important for the proper acquisition
h permanent pressure and rate monitoring for evaluation and real-time production enhancement. The optimization of operational practices a
 as prices have lead to potentially better economics for horizontal wells (Mulder et al. 1992). However research shows that in practice many
 s and also the study of the distribution of fractures in-situ (directly in the location of the deposition) with the integrated use of equipment and


onal open-hole point pressure measurements should help define accurate fluid gradients and contacts. However this procedure is inadequate

mance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx in ti
 process may not be applicable in which case a more detailed and robust process is required. The process of multicriteria decision-making s
e related to geological uncertainty performing reality checks making a decision and reviewing and evaluation of the judgments. Proper use
 ells drilled and the success and benefits realized by using long gauge PDC bits combined with a specialized short bearing pack motors not
n pore body size and pore throat size. NMR is believed to reflect the former while the latter controls capillary pressure. Hence the applicabili
  eservoir characterization. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in pre
  d downhole by borehole imaging tool. The heterogeneous porosity map from the image tool is then converted into a single curve representin
  nderstanding of process sedimentology that controls the reservoir properties of sands. The study area has been interpreted from Lower to U
six wells including well logs borehole images cores and the regional knowledge of the basin. Structural and sedimentary dip analyses were
  possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore before filling a samp
heless unexpected fluid production such as water or excessive gas is an undesirable outcome. A formation tester equipped with an extra la
rect impact on the production and water injection scheme of such reservoirs. The NMR data and image based secondary porosity estimatio
 r-scale geo-modeling for improved oil-field development by means of a comprehensive interdisciplinary approach. The Jaipur area is mainly
 ments are essentially seeing the same amount of invasion thus removing a major complication in conventional LWD interpretation. Introduc
   The use of a non-chemical radioactive source significantly reduces the environmental and operational risks normally involved with tradition

 odels (Simandoux Indonesian Waxman & Smits Dual Water and Effective Medium) due to the uncertainty in the different input parameters
ation models (Simandoux Indonesian Waxman & Smits Dual Water and Effective Medium) due to the uncertainty in the different input para
a fluid flow model in combination with array resistivity logs. Analyzing relative permeability in conjunction with formation permeability and capi
arbonate can have higher permeability calculated1 from flow tests as a result of fractures within the carbonate. Borehole imaging provided
e log based prediction is overcome by including pore size distribution data from a combination of NMR and borehole electrical image logs.�
 lay silt and sand. We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminate


wept thick sands and might not be representative of the water in the unswept thin sands. As discussed previously NMR offers useful insight
nd to be more representative to true formation resistivity than the apparent phase shift resistivity thus can be used in formation water saturat
  reservoir. Meso-scale fractures can also be identified oriented and characterized (open vs. cemented) on high resolution borehole images
rcumstances where significant formation solids and sand are mobilized deposition of suspended solids can result in the premature ending o
dress factors leading to the development of drilling-induced features in a borehole and to explain why some fractures on the electrical images
or other form of data a variogram analysis followed by sequential indicator simulation method was used to derive a facies model between Tay

n distribution. As a result estimation of the hydrocarbon in-place and recoverable reserves can be grossly inaccurate and hundreds of million
mation evaluation logs. They exhibit a silty lithology and fine grain texture and require high quality borehole resistivity images to characterize
 on time in shales is much faster than in the productive sands thin sand-shale laminations appear on NMR logs with the characteristic bimod

nsor downhole and this static pipe measurement because downhole the drillpipe is subject to an environment that is not representative of th

nd horizontal wells and well patterns will allow an operator to (a) select candidate wells for fracturing (b) choose appropriate operating conditio
 ervoir. For an isotropic medium there are two independent elastic parameters viz. Young’s modulus and Poisson’s ratio.� Gene
 ll offshore Louisiana in the Gulf of Mexico (GOM). The logged interval spans 1 000 ft below the casing shoe. In addition the Modular Dynam
  the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fracture
  the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fracture
  the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fracture
  e Greater Burgan field are the Wara Mauddud Burgan Third and Burgan Fourth sands. The deeper reservoirs--namely the Lower Cretace
  by fault propagation fold of a normal fault that located nearby the well. The main objective was to determine the structural geology features (
 pecial technique of BKZ logs processing 2) Spectral imaging and high-resolution inversion of the seismic data 3) structural analysis of the fi
ain the present-day reservoir behavior. A uniform classification scheme of fracture types was devised and specific properties namely density
wells using a special technique of BKZ logs processing 2) Spectral imaging and high-resolution inversion of the seismic data 3) structural an
  and logging experimental setup and completion designs cleanup production profiles pressure transient buildup tests water injection and s
  fluid properties including fluid compositions in real time. In addition mini-DST or Interval Pressure Transient Testing (IPTT) can be carried o
 nvestigate possible nearby formation alteration followed by MDT*-multi-probe IPTT. �The Sonic Scanner dipole radial profiling showed so
  rosity value with less uncertainty in comparison to the one from conventional logging tools such as the Neutron the Density and the Sonic w
 type and property log is still not widely used in the industry. Modern NMR logging tools can deliver – in addition to conventional porosity a
 e demonstrate the use of NMR data to calculate total and effective porosity and volume of irreducible water in productive reservoir sands an
 inaccuracies in the reported porosity. We investigate the influence of acquisition parameters inversion parameters and noise on the determ
NMR logging tools. The objective is to explain the basic measurement principles and interpretations needed to understand NMR formation-e
 physical properties in certain zones near faults variation of tuffaceous material content formation damage invasion of drilling fluids zones w
og legs. In this paper we will briefly review the new technologies available today for production logging with examples of evaluating horizonta

deration of the well with appropriate time-varying UBD boundary conditions. Capillary forces which facilitate countercurrent imbibition of the
ckstone to grainstones sequence that is highly fractured at the upper 15 feet of the layer’s “dual porosity system. The fracture corrido

id analysis methods to build a more complete interpretation of the reservoir fluids and provide greater insight into reservoir architecture. This
s case the asphaltene concentration gradient are then integrated in a geologic model and used to predict crude oil properties and DFA logs
e the deliverability performance of a vertically fractured well is considered estimates of the effective fracture half-length and average fracture
 than 40% at the end of the plateau phase. However recent infill drilling allowed for the first time an investigation of recovery efficiency in sw
he depleted layers face a significant overbalance while drilling with an oil-base mud system. Given these complexities fluid identification and

erformed by isolating 1 m of formation using the dual packer module of the wireline formation tester (WFT) and creating a hydraulic fracture b
 tions. Thus a complex phenomenon can be modeled using some valid simplifying assumptions with sufficient accuracy for the purpose of te
re first run within the framework of an infill well-location optimization software package. Then drilling constraints were imposed with drilling p
continuity exists. The fields are located in the Intra-Latrobe formations of the Gippsland Basin offshore Australia. Accurate field description a
   system accounting for fluid properties well depths productivity index and economic benefit.� Ultimately ESPs were selected. A rigorous
urve via the implementation of a massive infill drilling program; the second component aims to maintain production through the integration of
 nd viscous fluid properties.� Gas lift is the artificial lift method used in the field. The field gas source is supplied from a nearby field and co
s in order to drain them in a cost effective manner. Conventional well placement has met with limited success in stringers and thus resulted
gree of lateral and vertical heterogeneity.� The team decided first to drill the well utilizing a conventional logging while drilling (LWD) tool to
capital cost take advantage of higher gas prices at the time and gather data for proper design and sizing of the compressors. Following s
  ducted iteratively operating in parallel instead of the common sequential and decoupled approach. The method has been successfully teste
  nce facilities as well as reservoir management infrastructure are often basic and represent the technology available at the time of the platfor
 ludes the representation of the ICVs through the multi-segment wells option; the second section represents the fluid flow in the well and pipe
  the system by simply adhering to the FM interface which is discussed in this paper. The FM framework capabilities are demonstrated on se
ons at the reservoir and processing facility.� However as reservoir conditions change over time lift gas requirements will change as will o
y gas cap and a steeply increasing producing gas-oil ratio. The recovery factor for this reservoir stands at 25% significantly less than for the
 in a brown field and (ii) how to optimize redevelopment plan for maximum recovery. First several increased well production opportunities we


g a SRM able to run a simulation run in a matter of minutes and hence being suitable for sensitivity analysis and optimization. The optimized
 Hence further development options are being investigated for this asset.�A new nearby reservoir has been discovered. A reservoir sim
urface network performance that could impact long term field management plans if they are not properly identified and solved. PEMEX E&P
g performance which in this case translates into a significant reduction in simulation times.� A modular workflow enables the various tasks
pandable sand screens and premium screens. Most of the wells produce 10 000 to 15 000 BFPD using electrical submersible pumps (ESPs)

s have been built and applied for Khafji field as presented by Ghoniem et al1 2. This paper is an extension to the previous papers for Khafji
pplied during well planning and drilling executions such as optimum well designs specific LWD/MWD tool selections low fluid loss drilling flu
 ighest productivity wells in the field’s history. Oman has developed into a fast-paced fracturing arena with challenges similar to those
a the knowledge and experience of the evaluators and the methodology and workflow used during the evaluation process. Although we dea
  rtainties typically makes such valuations non-trivial and mostly intractable to current modeling schemes. We demonstrate the approach with
be developed more efficiently. By reducing uncertainties about the reservoir the new technology helped optimize production eliminate sidetr
 nificant sub-seismic variations in the top reservoir topography. Therefore to help optimal well placement Oilexco used a new deep and direc
ties (e.g. permeability field which may be nonuniform) and time-varying properties (e.g. pressure and saturation field).�As such it is a we
   concluded that a connected aquifer was present and estimated its size. This information was sufficient for the operator to know that the we
 track.� It also presents a set of criteria to select the most suitable well to sidetrack.� Finally it allows leveraging all associated uncertain
 a more sophisticated workflow to optimize horizontal well placement. Interactive well planning was initially used to optimize the horizontal w
  flow rates in the pseudowells are computed using an adjoint method. These gradients are used subsequently to approximate improving dire
duction well. The model accounts for mass and heat transfer during the process of heavy oil recovery and establishes a significant correlation
 wells we are able to accurately model the case of a finite conductivity fracture with non-Darcy flow as well as those of infinite conductivity.
 n our model fully accounts for interference effects between wells as well as multiple rate effects. Using solutions in Laplace space we are ab
We propose a fast and robust adaptation of the Bayesian formulation for inverse modeling that overcomes much of the current limitations an
  sensitivity calculation based on the Adjoint method to overcome much of the current limitations. First we use a commercial finite difference


 tic geological patterns which occur in theses realizations. Such patterns could be extracted out by means of a mathematical tool called Princ

 ent of phase transition to achieve stable non-linear iterations are discussed. The simulator is verified by comparing results from problem No.
eservoir simulation project (DeBaun et al. 2005) for “next generation is the ability to accommodate fluid models currently used in reservo
water contact sufficiently far from the gas-oil contact to reduce the effects of gas coning and channeling. Due to the large heterogeneity of re

s a significant challenge to capture such behavior in a simulation model. This paper covers the following issues of horizontal/multi-lateral well



the parameters controlling the well behaviour. To effectively use any of these techniques for forecasting future production it is imperative to d
 as-reservoir production with studied permeabilities ranging from 0.005 to 5 md. The observed trends may not carry over to nanodarcy reser
r. For this purpose an enhanced three-phase cleanup numerical model is developed. A generalised non-Newtonian fluid flow model for po
 pressure transient responses of multiple hydraulic fractured horizontal wells (MHFHW) using a numerical reservoir model. After validating th
 ation of multiphase multicomponent steady state flow around the hydraulic fractured well is proposed. The approach is based on the splitting
Renshaw and Pollard 1995) is used to determine if the hydraulic fracture crosses a particular bedding plane during height growth. Two interf
  have been continuously improving there are a number of parameters and effects which are not fully taken into consideration by these met
-controlled drawdown tests. We argue that the relationships between the apparent fracture conductivity and the true conductivity is a function
 n The process of inferring reservoir/completion parameters from the commingled production data in a multistage hydraulically fractured gas
s investigated in this work were the development of a general relationship for evaluating the pseudosteady state shape factor of a vertically f
 a given reservoir. The present paper offers the required equations to correctly design transverse fracturing treatments or collinear fractures
eters. The model developed has a limitation: it does not take into account the leakoff and pore pressure changes in near-wellbore zone duri
mation northeastern Alaska. By comparing the RBF results with those from other ANN methods we find that the former method gives a sub

ew wells (total seven wells) producing from this field show severe vertical discrepancy in pressure gas and water production. This adds anoth
niform skewed toward the heel or the toe or exhibits some discontinuity (e.g. leakoff into a high permeability streak or fracture). This paper
mprising an injector and producer and replaces the use of II and PI. The IPI method helps to quantify waterflood issues in the presence of p
 sential in narrowing the uncertainty in the parameters used in the model. In building the MB model two new techniques were proposed and s
gies are proposed. First a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate th
cted water and formation pressure measurements. The problems associated with decision supporting instruments e.g. a 3D dynamic mod
 the gas cap and one in the oil column. Introduction Proper initialization is an important aspect of reliable reservoir simulations. The use of t
ental design outcomes. After extensively applying these concepts for over 18 months in identifying the major sub-surface uncertainties expl

hly anisotropic media and discontinuities in the permeability tensor. Simulation results are presented and compared with results from other tw
bore zones are very important areas of the formation because they account for well deliverability. So the ability of precise and reliable simula
es or by history matching fine grid single porosity simulations.� Kossack et al1 discussed this for water-oil systems.� Since the displace
nto geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for histo

 e. The interaction between the two continua is modeled using matrix-fracture transfer functions. Until now there were no mathematical mod
cities in different parts of the reservoir. This circumstance is advantageous for simulating the reservoir numerically with the streamline method
 rically computed basis functions defined over a coarsened simulation grid consisting of collections of cells from the geological model. Here w

method and is not biased. We also apply the ensemble Kalman Filter (EnKF) method to the PUNQ data set and show that this method also
 culations in that numerical dispersion effects can be orders of magnitude greater than physical dispersion. The introduction of chemical rea


 the solution. This decomposition is recursively applied to the resulting representation until the coarsest mesh level is reached. From this mu
m thus it achieves the thermodynamic agreement of system and greatly reduces the required computing resources. Introduction In recent ye
static data (reservoir properties etc.) and predicted data (simplified production forecasts). The wells are then grouped according to the simila
se of these features the method is far more efficient for history matching dynamic data than automatic history matching based on optimizatio
 differences there are patterns which occur in theses simulated responses. Such patterns can be identified by means of a mathematical too
nvolving ICDs: a synthetic case and a sector of a North Sea field model. Results showing significant differences between the inflow profiles o

global production targets among different reservoirs is used for the purpose.� Compositions from different reservoirs are needed for surfa
ent � and the water connectivity parameter Cw. Under some conditions Cw can be equal to zero and the equation becomes identical toï¿

 on and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of the F
 t of the transition zone 4) gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be unimp
 cline in both pressure and associated production with today’s reservoir pressure averaging in the range of +/- 1800 psi. With such a ma
easonable accuracy provided wells cover wide range of deviation angle and azimuth The current study indicates that Sh in GoS is aligned a
 ffective Change Management. Deployment and Change Management are seen as the major challenges facing the creation of Smart Fields
  rates because of improvement of economic situation in the country on the one hand and increasing of mature fields on the other hand. The
approximately equal in 1980 but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. The
ncluded on how the input data is obtained. Because of this several papers have been published that have proposed ways to obtain the input


ced. In some wells the saturation analysis revealed that the stacked reservoir zones had variable levels of depletion and that the depletion w
 the settings of the downhole chokes to obtain a balanced production from the two horizontal wellbores. The completion provides the capabili
  ing the bypassed oil became crucial for the field development. Understanding of the reservoir required logging these sections. The conventio
ative with a 40 000 ft cable specifically manufactured to avoid splice induced weakness.� This new logging technology detects and measur

d. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation sample
d. In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation sample
  electric lines of the system. In this paper we describe an innovative and potentially reliable digital permanent monitoring solution that uses t
nhole owing to acid gases and salts coming out of solution and changes in water-chemistry equilibria. To obtain an accurate pH the measur
uch as compaction subsidence depletion and fines migration. This paper summarizes case histories from two fields where reduction in kh o
uple of hundreds of induced events per stage were mapped this new processing technique leads to the detection and location of several tho
t prior to the fracture treatment. These methods can be as simple as height estimates based on sensitivity studies of fracture height growth f

arly production which is consistent with data from the observation wells. The injector-producer interval between SAGD wells was modeled w
fluids water and hydrocarbons. This paper presents a sub-critical velocity analysis that has been implemented in a Pulsed Neutron producti
 fluids water and hydrocarbons. This paper presents a sub-critical velocity analysis that has been implemented in a Pulsed Neutron produc
a workover rig or a snubbing unit. Running a slickline containing an optical fiber to the bottom of the tubing and producing the well up the ann
o be generated about fluid flow in the well. Chemical tracers for flow profiling were chosen for ENA03L1 an oil well intersecting a number of
 nosis are critical parts of the production business and many production parameters are monitored in the process. Of these flow rate and flu


 uch as "how good is the decision?" or "how does the production engineer know that it is operating at the best performance possible?" is not
dups in this stratified flow is determined by the physical distance of the production logging sensors from the top of the hole the geometric size
 26 pressure buildup (PBU) tests (including buildup tests for 2 active wells of the interference test program) and 3 interference tests were con
as conducted. Immediate post treatment production increased to 2 200 bbl/d but dropped dramatically and stabilized at pretreatment rates s
  data. Because the whole process starts with formation inflow performance which determines how far we can go with this formation without h
g increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Web-ba
 ypical flowing scenarios we demonstrate that distributed temperature measurements respond to changes in production caused by depletion
n well for any associated microseismicity to be recorded. The central portion of the well pair did not have significant deformation indicating po
mson warming of the flowing oil caused by the pressure drop (drawdown) in the near-wellbore region. Thermal mixing of the oil with flow from
 the SouthEast Asia such a coupler was attached to the top of a sensor bridle and both deployed as part of an openhole gravelpack complet
 e (NMR) and conventional openhole logs. The Mauddud carbonates are Early Aptian in age and consist of grainstones wackstones and m

odels based on pressure and temperature measurements has proven to be a valid and cost effective solution. Several processes are necess
 neutron (PNL) technology provides two services related to measuring water production: 1) the Water Flow Log (WFL) measures the speed o

 surement in terms of radial investigation. The case study presented in the paper describes a successful water shutoff operation and improve
 ters and optimizing the Field Development Plan (FDP). Although there is strong water salinity contrast between the injected and original res
 has advanced much faster in the highly permeable upper reservoir units as compared to lower reservoir units. In order to understand the hor
om logs. This study refines the model by adding variable resolutions to encompass the small-scale heterogeneities common to carbonate res
  g is a critical part of this process especially considering the PRB development migration from single-coal open-hole completions into multi-
o optimize the production. In addition through better seam characterization a technical basis for a preferred completion method (horizontal w
  he coal seams. This paper presents several examples of the application of indirect fracturing for the stimulation of coal seams in the Rockie
h treating pressures. These losses reduce the efficiency of proppant placement and stimulation. As drilling activity has increased over the pa
echanics and transverse anisotropic elasticity we provide insights on the stress concentration resulting from various conditions of stress (nor
eeper wells and 3� in. for shallow wells using CT fracturing technique. This paper discusses the development of a technique which initially
 n shows along the lateral they provide little stratigraphic information no natural fracture information and no stress information. One log eva
  ucture horizons and faults but also analyzed for 3D property evaluations such as lithofacies distribution discrete fracture network and stres
ncreased production efficiency and improved financial return on these projects. By strategically placing steam injectors and by controlling the
 n 40 000 coalbed gas wells completed in at least 20 different basins. The remaining 1.0 Tscf comes from more than 40 000 shale gas wells
 nities to enhance refracture treatment coverage by targeting bypassed and ineffectively stimulated zones in additional vertical wells and even
on depths different acid types and volumes have to be used. Acidizing for optimized productivity requires first determining what is desired wo
  h an acceptable ESP failure and run life. So far 41% of the originally installed ESP systems are operating more than 4 years and 20% are o

bes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to create
 -water zone reserves and the reserves contained in the zones with poor reservoir properties. The use of the horizontal completion allows dev
 ges such as large vertical net pays and high hydrostatic pressures of the sodium formate-based reservoir drill-in fluid and the sodium-potas
g. A control line is connected between sequential valves. When the bottom valve opens the control line becomes pressurized and transfers t
mprise of unconsolidated sands that are thinly distributed. These unconsolidated sands are normally completed using cased hole gravel pack
 presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore
 presents an optimization technique for determining the most efficient production tubing string setting depth design that will keep the wellbore
 onsisting of Geology Petrophysics Geophysics Drilling and Service Company was instrumental in utilizing state-of-the-art 3D seismic inter

 rate and the flowing pressure in real time allowed producing the well optimally. The appraisal and acceptance loop of the completion has be
  onsider a single system comprising the reservoir the completion the measurement and the feedback algorithm that adjusts flow-control de
 . Monitoring the rate and the flowing pressure in real time allowed for optimal well production. The appraisal and acceptance portions of the

ned well configurations. Production performance in both systems has been compared using numerical and physical model. Results have pr
 ng the completion process of a well certain operations are performed to enable the well to produce by creating an unobstructed flow path for
 f levels of each factor into nonempty subsets of statistically similar response) so that an acceptable degree of parsimony is achieved. Essen
 e quest to increase the effective half-length of the fracture and enhance production led to the search for novel effective technologies capable
hydraulic fracture treatment was performed resulting in a 200% production increase. Over the past three years a stimulation program has ev
primary goal was to be able to create a more even distribution of proppant in the created fracture while reducing the polymer requirement for
height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC m
 get several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by lithological strea
 ns.� In addition to reducing damage with lower polymer concentrations other advantages of degradable fiber usage were anticipated to b
 croemulsion two water-wetting flowback additives and an oil-wetting additive. Careful laboratory testing was done to look at surface tension
 . The fracture height calculated based on uniform modulus versus layered modulus under the same in situ stress contrast conditions is com
 additives in fracture fluids and minimizing disposal costs of produced waters by recycling and by using them as the base for completion and
duced water. The importance of flowback water analysis is highlighted for optimizing fluid performance downhole. Recent developments in p
to calibrate and constrain appropriate fracture evaluation models (P3D and 3D).� Rate-transient production analysis techniques together
ng the upper intervals. This novel technique is particularly useful for wells with water-producing zones near the bottom of the target zone bec
 fracture half-length in order to improve the fracture treatment and the increasingly difficult task of simultaneously controlling fracture height g
  wells with long openhole intervals (see Fig. 1). This paper illustrates a case history where an innovative technique was used on stimulating
ovides self-diversion from water to oil bearing formations. At the same time this same fluid can be used on long intervals to divert matrix st
 sumed in the completion operations extends over weeks making wells uneconomical. In addition the prolonged time over which the frac flui

hese wells require stimulation to regain their productivity but the available choices to achieve effective stimulation in horizontal open hole com


 ddition the water bearing sand posed a risk to successful execution; the fracture had to be contained within the zone of interest. High Pressu
hape factors for use in improved hydraulic fracture stimulation design and evaluation.� Example applications of the dimensionless product

 red and planned stimulation campaigns in the Volga-Urals basin. This paper presents a summary of the knowledge gained in Samara fields

  This piston squeezes a C-ring and makes the ID smaller. At the end of the fracture treatment to the lower valve a dart is dropped during the
 ar the wellbore with sliding sleeve. FEA was used to adjust valve parameters that increased tensile stress in the cement and formation. Uns
n a quasielastic medium. The medium resistance to fracture development is determined by variable apparent fracture toughness which is a f
  fluid are presented along with three high-permeability case histories.�The estimated reservoir permeabilities were as high as 167 mD an

cessfully applied in the Morrow Sands in Eddy County of SENM.� Fracture geometry analysis using surface treating pressures radio-activ


OP. The option of acid fracturing was evaluated and found to be feasible to alleviate the problems. The paper details an optimization workflo
e encounters significant yield stress when the filter cake cumulative thickness dominates the width of the fracture. The new results presente
½ The evaluation tools utilized to determine the resultant fracture attributes include microseismic hydraulic fracture monitoring hydraulic fract

ences may appear along the receiver array. These traveltime discrepancies may then be misinterpreted as an effect of TI anisotropy and us

er acidizing. The profilometer measures the distance to the rock surface with a laser device that measures distance with an accuracy of 0.00
 sonic logging. Unfortunately in West Siberia at depth of 2500-3000 meters there is negligible tectonic and open hole sonic dipole did not pr
 adioactive tagging additive is incorporated into the resin coating of the proppant. This non-hazardous environmentally safe coated proppan

have either been shut-in or are on intermittent production. Factors may include low reservoir quality reservoir pressure and specific produc
ant Type of proppant Thus apparent proppant permeability will vary with distance from the wellbore increasing towards the tip of the fra
  behavior in high permeability formations. We consider a steadily propagating fracture taking into account the flow within the fracture filtrate
post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in-s
given set of reservoir parameters and job sizes and on optimization of the flow rate and cumulative production. We discuss the reasons for a
effectiveness of hydraulic-fracture stimulations is critical for optimal economic production of tight gas. Deformation associated with fracturing
nt flowback. The model is based on treating both the proppant pack and the reservoir as poroelastoplastic media. It allows for solid productio
 sults show that a refracture treatment can undergo three distinct periods of fracture growth: ����Period I: Dominant orthogonal fr
 luence of pressure differential. The quality of fracture cleanup determines in the long run the effectiveness of oil recovery measures. Fracturi
ng and adequately supported by other logs (ultra-sonic cement evaluation) to infer the change in anisotropy; the latter anisotropy includes the
 ss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data.�The results highlight th
owever the injection rate was decreased with increase in pressure and skin factor was found to be increased. Another observation was that
mature fields an accurate evaluation of the hydraulic fracturing operations is vital to enhance the effectiveness of the fracturing treatments a
ction pressure are made for several offset angles and lengths. Large increases in net pressure and associated increases in overall fracture v
  a rigorous analysis or solution of the wells’ production from a gas lift perspective. This paper presents the basic theory behind auto ga
 f BP’s open-hole gravel pack best practices. The paper details the completion evolution in BP’s offshore Trinidad and Tobago high
 ages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been
 ages required can be very time consuming with added expense of removing the frac plugs with coiled tubing after the operations have been
ermeability is ranging between 0.1 and 5 millidarcies (mD) An engineered oil-based mud was used as drill-in fluid to prevent any damage to
 rall commingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to res
ese hydrocarbons are lost and cannot be drained subsequently. This paper covers the design and application of new open hole sand face c
rsible Pumps play a key role in producing from oil wells that are incapable of producing naturally at commercially viable rates. ESPs are com
mmingled well rate. Along with real time monitoring sustainability of well rate will be extended by timely reacting to any changes to reservoir a
al well in a thin oil rim reservoir in the presence of reservoir uncertainty and evaluate the benefit of using two completions in conjunction with
agation trends as expected from three-dimensional modeling. Introduction Since the inception of the hydraulic fracturing technique as a me

  from Malaysia. A single well predictive model incorporates logs rock and PVT data and formation tests to build a flow simulation model at t
 dels (MEMs) were developed. These 1D MEMs were calibrated using drilling data laboratory measurements well tests and other field meas
 s into the impact of perforating on matrix acid stimulation.� Large scaled single-shot perforating tests were conducted using real shaped c
 ating method. In addition a passive gun-orienting system was used to optimize the perforating process and enhance the well’s performa
 n the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual root c
ere not enough to effectively clean the perforation tunnel and surpass the near wellbore damaged zone. Dynamic underbalanced perforating
 zone. Experience indicates that underbalance perforation provides better productivity compared to overbalance perforation. Although conve
ne opportunities to extend production by perforating new intervals or reperforating existing producing zones. With casingless completions ev
re detonated in the correct environment to create�a dynamic underbalance immediately after perforating. Laboratory tests show how this
e vicinity of the sandface region; (c) the crashed layer of the perforation tunnels is cleaned up. The existing pressure transient analysis metho
a CT string equipped with fiber optic cable inside was used coupled with a bottomhole assembly capable of measuring both bottomhole tem
ors for both gas well and oilwell applications. Important factors concerning carrier serviceability are discussed. A method based on energy co

ductivity than the baseline conventional charge. The reduction in the normalized Productivity Ratio (PRn) ranged from 29% to 66%. Furtherm
 arges shot underbalanced using the classic “shoot and pull technique. After shooting before the guns are pulled the well is killed. Perfo
ed longer time to reach the best possible setting for the downhole flow control valves to achieve the optimum flow rate. Using the combinatio
 n production wells and eleven injector wells were drilled and completed in the field. As a result of the perceived technical complexity of the d
 . The typical production-casing string for the wells consists of 10 3/4-in. casing with an 8 1/16-in. production liner. Drift diameter through the
ntain economical levels of production a combination of several technologies is being applied. Due to the poor natural production from the ver
 trol lines and a premium-sand-control screen with shunt tubes were retrieved/fished from the well with minimal problems. The retrieved scre
  the well current economic realities favored through tubing intervention. Two major types of through tubing remedial sand control solutions w

hat the situation is not much different from above demanding to lower production drawdowns while delivering production quotas.� The low
effectively in the field a thorough fit for purpose QA/QC system for all drilling and completion fluids was developed requiring extensive fluid

option except in fine sand environment. In this paper we present experimental data of shale stabilizer treated-brine and three open-hole gra
ntages of high gravel concentration slurries. This is supported by 2 field case histories from a field in India where two gas wells were drilled
 resented simulator tracks the fluid flow and gravel concentration from the wellhead down through the workstring crossover ports open-hole
  in recent years towards overcoming the challenges through new developments in fluids application tools and techniques. These developm
 ly employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing of
 y employed in cased-hole gravel packing to pack perforation tunnels and the potential limitations of these practices. Incomplete packing of p
 ieved by targeting perforations in the most stable direction with respect to the in-situ stress field. For high angle wells this normally equates t
 early stage of field development a reservoir failure was observed. A documented investigation indicated that the failure mode appeared to be
 on production management and co-ordination of all services are essential to the success of the screenless completion. In this paper the co

ation activities. The first step in the SMS was to obtain a clear understanding of the cause and the mechanism for the sand production. This k
of serious economical loss. This raises the question of how accurate and reliable sanding predictions might be achieved without overcomplic
ion analyses revealed the rocks to be extremely hard and strong and therefore highly unlikely to sand. These findings contradicted with initi
d and recorded using a borescope in real time. The results showed that the effect of water cut on perforation strength and sand production d

e total volume which can be expected to be produced by assessing the geometrical extend of the failed zone. These volumetric estimates
 ity and sand production for the development wells was assessed using in-house developed wellbore stability and sand production prediction
g acid-fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical long horizontal and multilateral we
nts—at elevated temperatures of 200�F and 275�F. The acid fracture conductivity apparatus is similar to a standard API fracture cond
nt response to acid fracturing treatments. However inadequate diversion can leave substantial portions of the reservoir untreated. Different a
 with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertica
s with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertic
ubing; production logs were acquired after each treatment. The results from comparison of pre- and post-job production logs clearly show
 ing of the rock matrix often leads to borehole instability and loss of wellbore integrity at the anticipated drawdown required to meet completi
g acid system for stimulation of more than 20 horizontal openhole wells in carbonate reservoirs in Kuwait. The application also deployed a ne
orty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are

mple manner without impacting the overall treatment logistics. The use of a hydrochloric acid system containing a viscoelastic surfactant sys
ductivity enhancement by optimizing the wormhole penetration and profile. Organic acids that are utilized in stimulating carbonate formations


 case a well stopped producing after being treated. A core study revealed that despite the relatively low clay content in the formation the crit
ed tubing with an inflatable packer or with conventional straddle packers or ball sealers.� Although mechanical techniques are very effecti
 not fully evaluated on all formations and fields. It is though evident that the volumes of wellbore fluids lost to the reservoir impact final produc
 e characterized for mineralogy texture fabric porosity and density distribution using Nuclear Magnetic Resonance (NMR) Computed Tomo
  statistics of a well alone may not offer an effective restimulation candidate selection methodology. Other parameters such as high BHP (rem
he reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of
tant-based fluid—such as low formation damage superior proppant transport and low friction pressures—with carbon dioxide advantages
 ften especially in old fields information is out of date limited or unavailable. Combining together available pieces of information through th

als of the oil bearing layers while temporary protect the zones suspected to be mainly contributing with water from the stimulation fluid using
als. The criteria used to judge the usefulness of these logs was the present or not of communication behind casing as determined by the phy
wo synthetic data examples are presented to illustrate the process. �Important contributions made in this study are as follows: The anal
oiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful dev
 the production optimization methodology in practice. The approach permits quantification of the reservoir and fracture properties on a layer-b
  logging (PL) jobs in some of these wells and it indicated that the productivity index (P.I.) of the individual layers varies widely ranging from 1
ons are referred to as limited-entry restricted-entry or partially penetrating wells. The transient flow behavior in these types of completions is
 ressure starts to diffuse or propagates as diffusion and we start to observe pressure change at a given space and time above the pressure g
 presented here are for wells on electrical submersible pumps in various types of reservoirs across Latin America. The paper briefly discusse
d in their papers not the original algorithms implemented by von Schroeter et al. and Levitan. Three synthetic cases and one field case are c

 y associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture distribution fracture ape
ped to acquire better quality reservoir information. Dual packer wireline formation testers offer an alternative an additional way to selectively s
 is used to determine the commerciality of discovered prospects. We use a two step approach in establishing commingled AOFP of gas well
 ual-energy gamma-ray Venturi multiphase flow meter (MPFM) was selected and placed under field trial to assess whether this technology co
 he evolution of the real dynamics of the wells stabilization after a change of choke can be observed and monitored accurately with the in-line

 g oil rates in certain conditions which leads to inaccurate estimation of the wells' potential and associated uncertainty in plans for production
 lenge of this environment. A number of recommendations to prevent and mitigate the impact of the hydrate and document major benefits of
ailable multiphase flowmeter consisting of a venturi and a dual-energy composition meter. This combination results in excellent predictions of
actions. Some of these wells were tested more than once to qualify and validate the production test results by the MPFM. Production test res
nd oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi and
 on by using simulation models that have been built using geological geophysical petro-physical and dynamic data. •�� Improved h
 the analysis/interpretation of the production data using a new diagnostic rate and pressure drop diagnostic function. This paper provides the
erpretation and in measurement technology. Specifically we describe a new technique for differentiating well-test-pressure data the digital p
  distributed characterization of matrix permeability at various depths of investigation and effective fracture transmissibility. While streaming p
iding measures that can be used to predict the evolution of cement and casing over the long term. This paper will focus on an in-depth evalu
RC-1 well. We conclude that the maximum horizontal stress direction is oriented N141 +/- 9oE. To first order principal horizontal stress mag
of degradation through characterization and system analysis; (ii) quantifying their criticity through modeling in terms of probability and severit
and advanced surface facilities to properly model the fluid flow behavior of the asset. Different injection variables facilities well completion n
 ions of CO2 injection into saline aquifers with a fully compositional code that has been expanded and enhanced to include specific phenome
  a baseline geological site exploration and the drilling in 2007 of one injection and two observation wells as well as the acquisition of a geoph
s are initiated and existing projects confirm the development scenarios.� A crucial element in CO2 storage is reliable monitoring of CO2
 es fluid pressures and poro-mechanical and strength properties of the formations. It is linked to a reservoir model to achieve initial equilibriu


ment cost. The drilling progress was 108 m/day from seabed to total depth according to the Rushmore drilling performance definition and
al performance to land wells. To overcome these drilling challenges a new point-the-bit rotary steerable system with a high dogleg capability

ced 2.6 million bbls of oil during its primary production phase from a reservoir that may be typical of the other reefs in these trends. The reser
ave been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy oil fie
del used here employs a petrophysically consistent high-resolution permeability estimate fracture geometry prediction and formation pressu
  damage and significantly increase well productivity. Sensitivity analysis of fluid type reservoir permeability lateral length and reentry drillin
 ing the original 14 components identified in the existing Pressure/Volume/Temperature (PVT) analysis into 2 and 3 pseudocomponents and
Fracture shut-off in open-hole sections. 5) Treatment execution under sub-hydrostatic conditions. To overcome these challenges a robust ch

ole size at approximately 4 200 meter TD and 150 deg C reservoir temperature. The water cut were 95% in one well and 30% in the other w
 re performing the water shut-off treatment. Temporary coiled tubing conveyed straddle system was created using two thru tubing inflatable p
e lack of confidence in the water shutoff remedial operations. From a survey carried out in the early 90s it was estimated that only 35% succ
  of this bad water production: It adds to oil production cost by way of increased lifting separation and disposal cost. It leads to scaling in we
or water shutoff that was engineered for the complex completion methods mentioned. The solution involves three key stages; the temporary i
rm in many fields managed by Saudi Aramco especially in the giant Ghawar filed the largest oil filed in the world. Some of these wells starte
feasibility fiber optic telemetry enabled coiled tubing (CT) was selected for an accurate and effective way to isolate the water producing inter
 assessing deepwater developments.� The production assurance risk factor can create game-changing impact on field development plann
  provides new experimental data on pressure drop holdup phase distribution and droplet-size distribution in oil/water flows that can lead to
  oil and water and to determine the flow patterns at various flow conditions. Quick closing valves were used to measure the phase holdups a
 ver the large number of uncertainties from reservoir to wellbore behavior that influence the performance of those advanced wells cannot be
 identified and solved. PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13 100 BOPD from 10 fields (mostly gas
 er deposit is a gas condensate layer and the lower is a black oil layer.� Because of marginal reserves mono-bore commingle production w
 conditions. The wax deposition tendency of the dead crude oil was also investigated. The experimental data were used for a case study to d
 ose concentration can change significantly by reaction with formation waters mud filtrates etc. before reaching an analysis facility. Optimizin
  of CO2 from reservoir fluid samples can be difficult especially if some water is also present in the collected samples. This is due to the natu

n �API specific gravity of the initial reservoir gas reservoir temperature and selected values of reservoir pressure. The dewpoint pressure
 evious work we found that Whitson and Torp method for generating Modified Black Oil (MBO) PVT properties yielded best results when com
 projects. � Introduction In the past a presumption of fluid homogeneity in the reservoir prevailed. In part this assumption was made bec
n tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in newly d
mber of Downhole Fluid Analysis (DFA) stations coupled with several DFA directed sampling stations throughout all interested zones toward
rogram to help evaluate completion decisions and to understand flow-assurance issues. The petroleum industry has devoted much effort to
 itional interactions are entirely neglected or represented through simplistic empirical correlations. Such conventional models are deemed suf
stones. The combination of DFA Fluid Mapping with pressure measurements has shown to be very effective for compartmentalization chara

real time analysis of gas compositions are also compared for verification and confidence. � Two field examples in low porosity/low mobilit
ccurate H2S concentration can be determined. Wireline formation testers have historically been regarded as a non-viable alternative. In this
ecause of system limitations in repeatability of both pressure and depth measurements. We developed a yield/temperature correlation to fill
  fluids therein. In this paper we review two case studies in which we have combined multiple techniques for the assessment of composition
 cation process during the exploration/appraisal campaign in such reservoirs offshore Malaysia where the operator needs to gather as much
 t in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid-sampling-analyzing tool string that included the
 om pressure gradients. In this contribution using several field examples we discuss and review formation pressure measurement technique
ssure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as fluid
ntial for condensates and lightly colored crude oils; for such fluids the color buildup becomes difficult to detect but the high methane content


 anding of fluid characteristics in the reservoir reserve calculations and adequate development plans can be prepared. Additionally flow barr
s color composition and GOR. The output of the FCA is the probability that two fluids are statistically different. Real-time application of the F
m help evaluate completion decisions and understand flow assurance issues. The petroleum industry has devoted much effort to developing

e a robust means to evaluate both the state of a multi-component multi-phase fluid and the vapor-liquid equilibrium (VLE).� In contrast to
amples were recombined with the corresponding flash gases to reconstitute the original reservoir oil compositions. Live oil/water emulsions w




  flow assurance facility design production strategies and defining reserves. The application of this new focused sampling technology is pre
  is that pressure drawdown has to be controlled while pumping – this is imperative in order to be able to sample the fluid at downhole rese
llect representative samples for phase-behavior characterization. Moreover metering accuracies has been questionable in many cases (at v
 in number of well tests performed in Russia complemented with experiences from operations in other countries. This paper documents new
etail and compared with each other. The mechanism of calcite dissolution includes acid dissociation mass transfer and surface reaction. Th
 ation damage severely impacts the injection trend. Conventional stimulation systems such as acid outsidephase emulsion and regular mud
esulting particles were characterized using both light scattering and scanning electron microscopy (SEM). The reaction rate and size distribut
 ions along with performance assessment after aging. Both sea salt and pharmaceutical-grade sodium chloride were used in the tests. All thr

e of the naphthenate-soap particles. The parameters of the rate equation were correlated with respect to pH and temperature. This also allow
et of sand production. An essential first step in modeling perforation clean-up is to characterize the extent and magnitude of both the permea
of the required underbalance to remove the damage zone or remove the comminuted fill are at best uncertain. In this paper we describe the
 ant amount of scale inhibitor within the propped fracture and into the adjacent formation. The case history delineates the detailed sampling a
 ale accumulation can be seen everywhere from an exaggerated production decline to scale deposition on production equipment. This paper
uch as inorganic scale control.� This paper describes the potential risks posed specifically to intelligent completions by scale deposition
 lly and present the most challenges to achieve complete removal. This work will describe ZADCO scale management strategy to monitor a
 /Ca ratio is < 0.1.�Over geological time frames the reservoir rock and formation brine will come into chemical equilibrium the Mg/Ca an
  to the responses from the other regions. Further since the regions are least correlated with each other each region can be history matched
h results are improved. Based on field-wide streamline flow patterns map the field is divided into several independent regions. Within these r
  e to demonstrate significant benefits and added value. This paper will conclude with an analysis and discussion of some of the results accru
 heir sector models have been extracted from the calibrated full field model. The vertical resolution for these sectors has been increased to b
production tools including Nodal modeling Turner’s equation Decline Curve Analysis or Pressure Survey were individually validated an
  can be used to infer the water saturation distribution because of the sharply different electrical resistivity between injected water and oil bear
ance operations provides the data necessary to monitor individual pattern balance watercut performance optimize areal sweep efficiency by
ne features of the ESP and the PCP systems have recently been successfully evaluated in the Orinoco belt to exploit extra-heavy oil reserve
  downhole heaters that by providing energy to the vicinity of the well decrease oil viscosity and increase the oil production rate. A consequen
 I gravity smaller than 20 are called heavy oil that can be produced by using thermal recovery techniques.� In these techniques heat is inje
c steam stimulation of each of the horizontal wells in the pattern. Properly implemented HASD could be more efficient than classical cyclic st
he planned horizontal wells was sidetracked thrice after stuck pipe incidences and finally completed as a 30 deg deviated well with an AFE ov
 ssible dual porosity system and evaluation of permeability using a new porosity partitioning technique. Data used in this study includes conv
 x permeability and formations saturated with high viscosity fluids or fractured limestones application of a single probe technique is limited. U
  identification of target oil pools well design selection of fit for purpose technologies and the complete well placement cycle including detaile
 el. The gel maintains its viscosity when contacting water and breaks down when contacting oil thus temporarily plugging the zones of high w


 posite of Canada companies is currently producing most of the Heavy Oil from cold and therefore non thermal production methods due to his

 m hole static temperatures greater than 200�F. Core flow tests demonstrated that the single acid system minimized the potential for prec
 ormation tester (WFT) that had a dual packer to test a large area of open hole. Formation testing and sampling objectives were: reservoir ev

 rading is sensitive to characterization methodology for some systems experimental data from a specially designed centrifuge system is esse

 ying treatment conditions such as mixwater composition and temperature tubular shear rate and transit time and reservoir temperature pos
 tory evaluation of an innovative solid-based acid fracturing system to address the above-stated limitations of conventional systems. Extensiv

 opment details installation procedures and “lessons learned after installation of the fully welded digital permanent down hole monitoring
 age mechanisms is included which demonstrates the potential for stimulation and the associated benefits. The methodology adopted in the
 endency than conventional fluids as well as lower corrosion rate; and (5) stimulates sandstone reservoirs at high temperature by effective d
 ut secondary metal precipitation. Slurry reactor tests elucidated the kinetics of mineral dissolution in mechanically ground field samples. Trea
 ated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given condition
 mation damage. The improvement in water block removal after treatment with A5 is tested by injecting gas into brine-saturated cores at diff
 ncertainties associated with the flash process and possible precipitation of salts can propagate as errors into scale and corrosion models. It

 ner with a frac port located between each set of packers and a process of subsequent multistage stimulation of the entire interval.� The m

 ess until it reaches a “SMART-factory-like workflow. With our new process new technology can be integrated with adaptive modification
  in this study indicate fracture length growth for each stage. 11 and 12 stages were chosen for the two well completion program based on da
 ling and world experience suggest that the hydraulic fractures do re-orient under the influence of pore pressure changes because of fluid
 rvation of injected fluid mass and the mechanic interactions both between fractures and injected fluid as well as among the fractures. The hy
 s were then used to calibrate a log-derived permeability and stress models. An advanced petrophysical analysis using these models improve


 ctors in spreading this technology to offshore applications. Sometimes the misplaced perception of hydraulic fracturing as risky and costly o
  normal gas production with conventional perforations very restrictive and will require proppant fracturing stimulation treatments to produce
 to a low fluid loss drilling fluid system have resulted in significant incremental oil recovery that would not be produced by existing or additiona
 . The calibrated model was used to forecast well performance estimate reserves; investigate optimal well spacing and infill-well patterns. P
  production logs) Understand geological setting and production mechanism Detect scaling problems and optimize treatment solutions Und
 ferent upscaling scenarios and techniques. The models were set up with the same boundary conditions (injector/producer pairs injection/pro
mpleting and stimulating highly laminated interval.� In this paper we will show a case study from a South Texas tight gas sand field. Severa

 f a micro-resistivity imaging tool it was used in combination with the acoustic imaging for integrated and enhanced formation evaluation whic
y to address these challenges and implement a newly proposed solution. The tested intervals contain multiple thin zones which make it diffic
ms of fracture height length width and conductivity. These fracture characteristics are estimated using a variety of techniques including pre
eration wireline tools which employ extremely precise pretest mechanisms can achieve the required data acquisition objectives more efficien

n important for the proper acquisition of formation test data. Several new options made available through the enhanced capabilities of the ne
ptimization of operational practices and introduction of fit-for-purpose technologies enabled a production increase from an intermittent hundre
esearch shows that in practice many of these wells typically produce only 10 to 30% more than offset vertical wells. With costs more than do
 the integrated use of equipment and technology of formation micro-scanners and dipole sonic tools. This new approach consists on high-po


However this procedure is inadequate to identify and characterize the transition zones. Supercharging capillary effects changing wettability a

 tion is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing wells
ess of multicriteria decision-making starts with eliciting judgment concerning corporate decision-making policy in particular identifying levels
uation of the judgments. Proper use of judgment elicitation techniques together with objective data analysis will lead to significantly better de
 ized short bearing pack motors not only in the quality of the real time and recorded logs but in the over all bore hole quality as well. Introduc
llary pressure. Hence the applicability of NMR derived capillary pressure curves in carbonates has been questioned. In a well in a complex
emented outside the casing as in previous applications. This notable difference introduced particular issues in the ERA data acquisition and i
verted into a single curve representing the secondary porosity. This secondary porosity log is added to the conventional logs as input of the n
has been interpreted from Lower to Upper Cretaceous. The major lithofacies identified are sandstone (massive laminated and cross-bedded
  and sedimentary dip analyses were performed both on borehole images and oriented full-bore core photos that provided at least twice as m
  to the wellbore before filling a sample bottle. In this paper a new DFA tool is introduced that substantially increases the accuracy of these
 ation tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in new
e based secondary porosity estimation recorded in this well were used for partitioning the porosity into micro meso and macro porosity.� B
 approach. The Jaipur area is mainly characterized by a Tertiary terrigenous sedimentary sequence comprising of fluvial to deltaic deposits o
entional LWD interpretation. Introduction A new-generation LWD tool has been developed that integrates measurements of gamma ray pro
  risks normally involved with traditional LWD tools. The data delivered by this service include not only the traditional measurements such a

ainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to develo
 uncertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to
with formation permeability and capillary pressure leads to new insights in log-based rock typing for comparison with Special Core Analysis (
bonate. Borehole imaging provided is a new way of the characteristics of reservoirs drilled with oil-base-mud. Complicated structures were r
nd borehole electrical image logs.�� This data is sufficient to partition the porosity according the pore size compute permeability and as
te the thin sand fraction of a laminated reservoir from NMR free fluid volume.� The results of this method are compared to the sand count


previously NMR offers useful insights into the petrophysics of thin sand-shale laminations. Typically 1D high-resolution data is acquired to e
n be used in formation water saturation estimation. An alternative measurement of formation fluid saturation is by pulse neutron (PN) after w
on high resolution borehole images over the entire open-hole section. When combined with pressure transient analyses and production data
can result in the premature ending of formation testing and sampling jobs or require multiple trips into the well to acquire the required sampl
me fractures on the electrical images were also seen in the cores whilst others were not. This method allows differentiation between natural
o derive a facies model between Tayarat and Bahra Formation of Lower Cretaceous age. A volume extraction method was used to extract c

ly inaccurate and hundreds of millions of barrels of hydrocarbons can be lost or fictitiously added in a reservoir model. An accurate reservoir
 ole resistivity images to characterize their geometry. The exploration well offers the best chance to evaluate the prospect but operational an
MR logs with the characteristic bimodal relaxation distribution. The thin laminations are often below the resolution of conventional logs that h

nment that is not representative of the derrick (e.g. varying drilling mechanical conditions and temperature changes). Here we demonstrate

choose appropriate operating conditions to avoid early water breakthrough and achieve better reservoir sweep (c) choose the right time wind
 us and Poisson’s ratio.� Generally logging data consisting of density compressional and shear wave velocities are used to estimate
shoe. In addition the Modular Dynamic Tester (MDT) (�Schlumberger) minifrac tests were performed at three depths in shale thus yieldin
ure half-length and average fracture conductivity may be derived from the analysis.� In cases where the multi-rate deliverability tests are p
ure half-length and average fracture conductivity may be derived from the analysis.� In cases where the multi-rate deliverability tests are p
ure half-length and average fracture conductivity may be derived from the analysis.� In cases where the multi-rate deliverability tests are p
 servoirs--namely the Lower Cretaceous Ratawi and Minagish limestone--and the Jurassic Marrat formation contain significant oil reserves b
mine the structural geology features (i.e. fractures) its orientation and the diagenetic features (i.e. vugs) using formation micro imaging tool. A
 c data 3) structural analysis of the field 4) construction of the reservoir properties model 5) construction of the fracture distribution model u
 d specific properties namely density orientation apertures and porosity of each fracture type wherever applicable were generated. These
n of the seismic data 3) structural analysis of the field 4) construction of the reservoir properties model 5) construction of the fracture distrib
 nt buildup tests water injection and subsequent production of all injected water and collection of all relevant data that include time-lapse pre
nsient Testing (IPTT) can be carried out at Downhole Fluid Analysis (DFA) stations to provide more representative and accurate mobility/perm
nner dipole radial profiling showed some radial property change at several zones.� The altered zone radial extent was quantified. �The
Neutron the Density and the Sonic where there is a need to assume variable values of density and transit time for the matrix. To corrobora
 n addition to conventional porosity and permeability information – a continuous fluid log of oil gas water and OBM filtrate (OBMF) at multi
 ater in productive reservoir sands and in shales to validate the petrophysical model. We also present a method based on NMR analysis to e
parameters and noise on the determination of porosity from NMR data. A key focus is on fluids exhibiting the extremes of T1 T2 or D such
eded to understand NMR formation-evaluation techniques and to discuss a few examples of these methods. Introduction of pulsed-NMR lo
ge invasion of drilling fluids zones with viscous oil low and variable formation water salinity. During this study a two step petrophysical eva
with examples of evaluating horizontal wells with barefoot smart completions diagnosing water entries flow profiles and fluid break-through.

 tate countercurrent imbibition of the drilling mud into the formation are taken into account. The production rates during UBD depend on the
 porosity system. The fracture corridors within the layer improve permeability thereby making it a good potential for horizontal well placemen

sight into reservoir architecture. This leads to improved understanding of structural history hydrocarbon migration and entrapment reservoir
ct crude oil properties and DFA logs for all hydraulically connected sections of the reservoir. Predicted and newly acquired DFA log data mat
ture half-length and average fracture conductivity may be derived from the analysis. In cases where the multi-rate deliverability measuremen
estigation of recovery efficiency in swept but previously un-drilled parts of the reservoir. Higher than expected the remaining oil saturations
e complexities fluid identification and pressure measurements have a significant impact in resolving key uncertainties of such reservoirs. Th

FT) and creating a hydraulic fracture by injecting drilling fluid using the downhole pump. Combination of the wireline dual packer and standard
 fficient accuracy for the purpose of test design or interpretation. The rationale for the initial and boundary conditions deployed here which ar
nstraints were imposed with drilling planning software and facility constraints were included via a surface coupling system for multiple-reservo
Australia. Accurate field description and reserves estimation was critical for the outcome of the full field development project. Logging-while-d
 tely ESPs were selected. A rigorous selection process identified three trial wells on the crest of the shallow ‘A’ sands.� These wel
production through the integration of Improved Oil Recovery (IOR) methodologies. A multi-disciplinary team studied and recommended the i
  s supplied from a nearby field and compression facilities in Bokor.� However with ageing compressors and fluctuation in gas availability
 ccess in stringers and thus resulted in low production figures. PeriScope has persistently proven that a proactive well placement technology
 al logging while drilling (LWD) tool to geosteer the well in the horizontal section.� The LWD was unable to trace the sand while drilling acr
ng of the compressors. Following studies were carried out as part of the project: 1) Compare the response of wells in high-pressure area
e method has been successfully tested in a brown field with 165 stacked reservoirs. Reserves increased significantly compared to the offset f
 gy available at the time of the platform installation. The current paper discusses optimization techniques using dynamic simulation with a co
ents the fluid flow in the well and pipelines from the couple point to the sink including the artificial lift system (Electrical Submersible Pump ES
k capabilities are demonstrated on several examples involving diversified production strategies and multiple surface/subsurface simulators. O
 as requirements will change as will operating constraints.� The design of the processing facilities will need to accommodate these change
at 25% significantly less than for the best reservoirs in the field. After more than a decade shut-in secondary and tertiary recovery methods
ased well production opportunities were identified based on the standard methodology. Then to reduce uncertainties and risks associated w


ysis and optimization. The optimized WAG injection and production cycle is then carried forward to an IAM in order to accurately determine th
has been discovered. A reservoir simulation model has been constructed for the new discovery. This second reservoir is a gas condensate
 identified and solved. PEMEX E&P San Manuel complex produces in excess of 276 mmscf/d and 13 100 BOPD from 10 fields (mostly gas
 r workflow enables the various tasks in an integrated study to be assigned to project team members facilitates the flow of task outcomes be
electrical submersible pumps (ESPs). In these commingled completions the water cut rises from a few percent to 80% to 90% within the firs

 ion to the previous papers for Khafji Field cited above.� The optimization approach presented in this paper is based on a field-wide produc
ool selections low fluid loss drilling fluids real-time geosteering data monitoring and the cleaning of the pay zone during completions were ap
ena with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly depe
evaluation process. Although we deal with dry gas reservoirs the challenge lies in the difficulty of solving relatively simple equations that resu
  We demonstrate the approach with an example involving a decision to be made for a marginal asset on where to place an injector well rela
 optimize production eliminate sidetracks and minimize well construction cost and risk. One of the main challenges of maintaining a horizon
   Oilexco used a new deep and directional LWD measurement in the Bottom Hole drilling Assembly in order to map the relative position of th
 aturation field).�As such it is a well placement strategy governed purely by reservoir drainage objectives rather than infrastructure conside
  for the operator to know that the well would not be needed as a water injector and to justify a sidetrack from the downdip location to an upd
 s leveraging all associated uncertainties by linking the economic analysis to a Monte Carlo simulation which is critical for a sound managem
 ally used to optimize the horizontal well location within the 3-D reservoir model ensuring a smooth trajectory near placement to the current o
quently to approximate improving directions (i.e. directions to move the wells to achieve an increase in NPV) on the basis of which improving
 d establishes a significant correlation between production rate and the dynamic of SC evolution. The model that was developed was compar
 well as those of infinite conductivity. The generality of our method allows any continuous function of position and time to be used to treat eith
solutions in Laplace space we are able to model naturally fractured reservoirs wellbore storage non-Darcy flow factors as well as constant w
 es much of the current limitations and is well suited for large-scale field applications. Our approach is based on a generalized travel time inve
we use a commercial finite difference simulator ECLIPSE as a forward model which is general and can account for complex physical behav


ns of a mathematical tool called Principal Component Analysis. These characteristic geological patterns can then be combined in different co

  comparing results from problem No. 3 of the Fourth SPE Comparative Solution Projects� and a cyclic steam injection case with other com
 luid models currently used in reservoir simulation as well as models that will be developed in the future. With this general formulation approa
   Due to the large heterogeneity of reservoir properties in different layers complexity of the geological feature and the dynamics within the h

 issues of horizontal/multi-lateral well simulation. Special horizontal well flow dynamics exist that are associated with undulations in the wellb



  future production it is imperative to determine the dominant flow regime from the production data. This paper focuses on concepts that ena
 ay not carry over to nanodarcy reservoirs such as the gas shales. The three phases included gas water and fracturing gel. Introduction H
 on-Newtonian fluid flow model for porous media is derived and implemented in a reservoir simulator capturing the yield stress of common
al reservoir model. After validating the numerical model using an analytical solution applied to a simpler reservoir/well model complex reserv
 he approach is based on the splitting the thermodynamic and hydrodynamic problems of multiphase and multicomponent fluids flow. It is als
 lane during height growth. Two interface properties of a coefficient of friction and a shear stiffness required by the model are defined and th
  ken into consideration by these methods and therefore result in unrealistic production forecasts. These factors include non-Darcy effects
 and the true conductivity is a function of time and that the restrictions on variables can be relaxed. In addition the issue of flow convergence
multistage hydraulically fractured gas well involves the solution of an inverse problem. Such inverse problems for production analysis are typic
  dy state shape factor of a vertically fractured well in a closed rectangularly bounded reservoir along with a review of appropriate applications
ring treatments or collinear fractures with short perforation intervals. As compared to previous models it only replaces the line source and lin
e changes in near-wellbore zone during fracturing treatment. However we believe that this limitation is not essential as it does not affect the q
nd that the former method gives a substantially smaller error than many of the alternative methods. For example the errors in predicted fractu

 nd water production. This adds another challenge in the dynamic modeling and leads to dividing the field into three main reservoirs that are c
ability streak or fracture). This paper also presents comparison of temperature profiles obtained with the analytical solution given in this pape
aterflood issues in the presence of poor mobility. This paper will cover three main areas: The simple background theory of IPI. The conseq
new techniques were proposed and successfully used: moving linear regression for generating the input pressure for the MB model produc
ressure and PVT data to evaluate their effect on material balance calculations. Second a more robust approach was proposed using experim
 instruments e.g. a 3D dynamic model or reservoir engineering analysis used for elaboration of recommendations. This paper illustrates th
 le reservoir simulations. The use of the Gibbs segregation condition generally cannot provide reliable initialization in hydrocarbon reservoirs.
major sub-surface uncertainties explaining observed production performance and in prescribing additional development options for fifteen re

d compared with results from other two-point and multipoint flux approximations. 1. Introduction. The two-point flux approximation (TPFA) is
 ability of precise and reliable simulation of the fluids flow inside of these zones is very important to forecast the production profile and field d
er-oil systems.� Since the displacement of oil from vugs by gas involves very different mechanisms from water-oil systems and is very com
bine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient frac

ow there were no mathematical models of dual porosity three-phase compressible flow for streamline simulators. To realize this model it was
umerically with the streamline method [1 4 6 7 8 9 11 17 18 21]. Indeed in the streamline method the transport part is solved along a set of o
 ls from the geological model. Here we use a mimetic multipoint flux approximation to compute the multiscale basis functions. This method h

 set and show that this method also gives a reasonable quantification of the uncertainty in performance predictions with an uncertainty range
on. The introduction of chemical reaction calculations into streamline simulation models presents a very significant opportunity for improving


mesh level is reached. From this multi-resolution representation of the solution an adaptive grid is constructed by thresholding of negligible d
g resources. Introduction In recent years the streamline simulation methodology has attracted a lot of attention from the research and the oil
  then grouped according to the similarity of their KPIs. The production profiles of the wells within the same group are combined to a type curv
 istory matching based on optimization algorithms. Moreover the set of realizations provides a way to evaluate the uncertainty in reservoir de
 ified by means of a mathematical tool called Principal Component Analysis. The classical face recognition technique is then used to rank
erences between the inflow profiles of horizontal wells with and without packers in the annulus are presented. Introduction Advanced well co

erent reservoirs are needed for surface facility design and operation. �Compositional simulation is prohibitively computationally expensive
 the equation becomes identical to� Archie's law in its simplest form (n = m = �). However in the general case the model is fundamenta

e insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond the F
 arging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considered. It
ange of +/- 1800 psi. With such a marked reduction in reservoir pressure coupled with complex geology intricate vertical and deviated fractu
 indicates that Sh in GoS is aligned along two major trends. The main NNE – SSW trend with average orientation of N10degE exists in m
s facing the creation of Smart Fields. During the Forum it became apparent that companies do not have a common vision of what a truly S
mature fields on the other hand. The paper presents an overview of EOR field experiences in former Soviet Union and Russia for the last 25
more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities but differ in several key areas in
ve proposed ways to obtain the input data in particular the mechanical parameters of the set cement. Because typically these papers have a


 of depletion and that the depletion was not necessarily related to the distance to the original oil-water contact. In these wells the water shuto
The completion provides the capability to control and measure in real time flow contributions from both laterals and is the first installation of
ogging these sections. The conventional wireline logging was regarded as a difficult and unsafe operation due to complicated nature of the p
gging technology detects and measures stratified flow and lower flow rate fluid entry than conventional axial symmetric production logging too

uire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamin
uire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamin
 anent monitoring solution that uses the state-of-the-art welded system that aims to eliminate the risk of leakage. Included in the paper are th
o obtain an accurate pH the measurement must be made downhole at reservoir conditions. Unlike potentiometric methods in which fouling o
om two fields where reduction in kh over time and increasing skin over time led to a more in-depth study of the reservoir geomechanics. The
detection and location of several thousands of events per stage. This increase of mapped microseismic events provides following insights in
ity studies of fracture height growth for different fluids pumping rates etc. using a derived rock stress profile within a fracturing simulator to

 etween SAGD wells was modeled with a thermal reservoir model to understand the influence of fluid viscosity water cut and permeability on
mented in a Pulsed Neutron production logging technique in order to have the capability to reliably evaluate the formation inflow into wells in
emented in a Pulsed Neutron production logging technique in order to have the capability to reliably evaluate the formation inflow into wells in
 ng and producing the well up the annulus for a short period allows the temperature profile of the well to be measured and therefore the inflo
  an oil well intersecting a number of fault blocks in the south of the Enfield field to: Provide direct proof of fluid flow from different fault bloc
e process. Of these flow rate and fluid type (phase) are two of the most fundamental measurements. Over the years many instruments hav


e best performance possible?" is not easy because a reference for comparison is needed. Performance efficiency can be defined as the rat
 he top of the hole the geometric size of the sensors and the measurement resolution of the sensor at high water cut. These specifications a
 m) and 3 interference tests were conducted. Each interference test involved one active well and 3-6 observation wells. This paper describes
and stabilized at pretreatment rates soon after. Formation of emulsions and asphaltenes were believed to be the cause of the production dec
 e can go with this formation without having production problems such as; water conning erosion induced by solid production etc. In this pap
 surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be oversta
es in production caused by depletion in individual reservoir layers. We also show that in addition to flow rate determination layer pressure cha
 significant deformation indicating poor steam conformance during this warm-up phase. A comparison of the temporal response of the micro
ermal mixing of the oil with flow from below only occurs once the flow has passed through the sand-screen wire-wrap. Thus a direct measure
t of an openhole gravelpack completion. Standard packers and gravel-pack service tools were used. The system became activated when a
t of grainstones wackstones and mudstones deposited in a ramp setting. Observations from production logging tool (PLT) and production d

 ution. Several processes are necessary to measure and validate oil production at the well level as follows: Virtual Rate Measurement (VRM
ow Log (WFL) measures the speed of the water flow while 2) the Three-Phase Holdup Log (TPHL) confirms the available multi-phase holdup

 l water shutoff operation and improved oil recovery from the Bahariya formation in the western desert Egypt. The well was drilled in early 20
between the injected and original reservoir water in this field resistivity-based methods can be affected by variations in the reservoir rock cem
  units. In order to understand the horizontal and vertical fluid flow behavior an inverted 5-spot water injection pilot pattern is being implement
 ogeneities common to carbonate reservoirs. Incorporating geological data derived from seismic attributes core descriptions and detailed log
 al open-hole completions into multi-zone cased-hole completions Whereas the industry has substantial knowledge of perforating characteri
rred completion method (horizontal well hydraulic fracture open hole or cavity) can be ascertained. High cleat density in coal seams is an e
mulation of coal seams in the Rockies. This paper evaluates production results fracture pressure analysis as well as micro seismic results a
ng activity has increased over the past couple of years fracture-initiation problems are now a substantial source of expense and downtime.
 rom various conditions of stress (normal and reverse faulting) and material properties.� We also provide a simplified methodology for first
elopment of a technique which initially eliminates the CT friction limits on transferring energy to coalface.� A large-volume pressure pulse i
 d no stress information. One log evaluation tool that is being used more frequently in horizontal wells is the formation imager.� It produce
   discrete fracture network and stress field. On the operation side longer horizontal wells are drilled and massive multistage multicluster hyd
team injectors and by controlling the amount of steam injected it may be possible for these results to be achieved. A study was conducted to
m more than 40 000 shale gas wells completed in five primary basins. While the pace of coalbed-gas drilling is starting to slow shale gas con
s in additional vertical wells and even some horizontal wells. Because of the heterogeneous nature of this unconventional gas reservoir the r
  s first determining what is desired wormhole pattern. Currently the numerical models focus on computer rendered wormholing pattern by pr
 ing more than 4 years and 20% are operating in the range of 3-4 years run life. The cumulative average run life of operating ESPs is 2.7 yea

 velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by pre
 the horizontal completion allows development of the reserves which would have never been possible to produce with vertical wells because
ir drill-in fluid and the sodium-potassium formate completion brine. Compared with other alternatives such as cased hole gravel-pack or fra
becomes pressurized and transfers the bore pressure to a piston in the valve immediately above. This piston squeezes a Cring and makes t
 pleted using cased hole gravel pack. In order to select optimal completions it required both identification and estimation of the radial extent
pth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under thos
pth design that will keep the wellbore continuously unloaded of produced liquids yet result in the maximum gas recovery possible under thos
zing state-of-the-art 3D seismic interpretation LWD resistivity at bit real-time imaging and distance to boundary measurements to place this

ptance loop of the completion has been closed by having this well completed put on production and tested. Approval of the concept was ach
algorithm that adjusts flow-control devices with quantitative models for each of the components. Both pressure and flow-rate control systems
aisal and acceptance portions of the completion process were achieved when this well was completed put on production and tested. The co

and physical model. Results have proven that the dual-lateral well configuration accelerates the oil recovery by 90% in the early stage of pro
 reating an unobstructed flow path for the oil and lifting it to the surface. This process is intended to realize actual production that measures u
gree of parsimony is achieved. Essential definitions necessary for preliminary data structure are also covered. We demonstrate the practical
  novel effective technologies capable of achieving this goal. One such technology is the solid acid system which was field tested for the first
  years a stimulation program has evolved with improvements in candidate selection performance and predictability. Future plans include co
 educing the polymer requirement for the fracturing gel slurry. A secondary goal was to use slugs of the fiber to bridge at the fracture entry fac
ng fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhance
  are often divided by lithological streaks that make vertical communication challenging. Hence in many instances acid fracturing ends up ove
able fiber usage were anticipated to be proven after proppant fractures geometries and production parameters (including PI and Jd) evaluatio
  was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drainag
situ stress contrast conditions is compared. The results are analyzed and explained based on fracture mechanics fundamentals as well as
hem as the base for completion and fracturing fluids. Because of the uncertainty of the produced water impurity composition and concentra
downhole. Recent developments in proper selection of fluid additives and viscosifiers for slickwater and crosslinked fluids are discussed. We
uction analysis techniques together with statistical data techniques were incorporated to evaluate stimulation techniques (proppant & fluid vo
 ar the bottom of the target zone because it induces selective growth of the fracture along the upper intervals and mitigates the risk of growin
aneously controlling fracture height growth. In addition to the risk of the post-frac increase in water-cut the uncontrolled fracture height grow
e technique was used on stimulating a naturally completed horizontal well that experienced a production drop to zero shortly after the comple
  on long intervals to divert matrix stimulation treatments from stimulated to un-stimulated intervals or from high permeability intervals to low
 olonged time over which the frac fluid remains in the formation before being flowed back often affects well productivity. This paper describe

 imulation in horizontal open hole completions have traditionally been limited at best. Previous stimulation attempts with coiled tubing have yie


 thin the zone of interest. High Pressure and high temperature operations posed additional challenges that had to be addressed. For Fracture
 cations of the dimensionless productivity index and pseudosteady state shape factor solutions developed in this work are provided for fractur

 e knowledge gained in Samara fields of the Volga-Urals basin with emphasis on the results obtained and highlighting the differences with the

 er valve a dart is dropped during the flushing operation. This dart lands on the C-ring and seals the bore inside the sliding sleeve. Pressure
ss in the cement and formation. Unstressed cement tests were then conducted on a variety of sliding sleeve valve shapes to verify the FEA
arent fracture toughness which is a function of the fracture length and is found from the analysis of energy dissipation in the plastic zone. Th
 eabilities were as high as 167 mD and reservoir heights ranged from 30 -90 feet.�In all cases the entire propped fracture design was suc

 urface treating pressures radio-active tracers and production data showed height growth containment and longer effective fracture half-leng


  paper details an optimization workflow and integrated evaluation process that improve the treatment performance. Detailed fluid system use
e fracture. The new results presented here demonstrate successful strategies that mitigate the effects of excessive filter cake thickness. Exp
 ic fracture monitoring hydraulic fracture surface treating pressure-history matching and tracer and production log interpretation in addition to

  as an effect of TI anisotropy and use of such an anisotropic model may lead to the mislocation of the detected fracture(s).� The uncertai

 es distance with an accuracy of 0.001 in. The rock sample is mounted on a servo-table that automatically moves the sample in selectable in
 and open hole sonic dipole did not provide obvious fracture orientation. Fracture height growth affect mostly fracture job size and cost. Heigh
 nvironmentally safe coated proppant can be transported and applied without any of the restrictions associated with radioactive tracers. Once

 servoir pressure and specific production conditions. A reliable methodology for selection of candidate wells for stimulation treatments was c
e increasing towards the tip of the fracture where liquid ratio and velocity are lower. This variation of permeability was explicitly modeled in
 nt the flow within the fracture filtrate leak-off across the fracture faces and kinetics of filter cake growth. The flow within the reservoir due to
 oelastic diverting acid versus the in-situ gelled acid.1 However the wells treated with viscoelastic surfactant based acid did clean out in a sho
 uction. We discuss the reasons for and alternatives to conductivity impairment within the fracture; fracture cleanup width changes conducti
  formation associated with fracturing results in small-magnitude microearthquakes that can be used to image the stimulated fracture network
 ic media. It allows for solid production from the proppant pack but also from the formation itself in case the fracture was created in a very we
½ï¿½Period I: Dominant orthogonal fracture propagation. It exhibits a rapid pressure increase due to the stress increase at the tip of the ortho
 ss of oil recovery measures. Fracturing fluid being left entrapped in the fracture decreases its effective oil collecting area. Thus stability and q
 opy; the latter anisotropy includes the creation of a propped width. While the methodology has been used in carbonates very few cases of its
  able data.�The results highlight the crucial role played by the filter cake and present new data that would significantly change the commo
 eased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress. Possible explanat
veness of the fracturing treatments and improve the production results. Multiple hydraulic fracturing operations were evaluated in five differen
  ciated increases in overall fracture volume are shown which can result in increased treatment costs slower fracture growth and shorter ove
 ents the basic theory behind auto gas lift and how to apply it. The components of the theory are well known and commonly used in nodal ana
s offshore Trinidad and Tobago high rate gas fields and the relative performance of these completion types from sand control and well produ
  bing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the horizon
  bing after the operations have been completed. When drilling a horizontal well there are two preferred completion options. First the horizon
  rill-in fluid to prevent any damage to the reservoir. A carbonate particle-based filtercake was used to create a thin and reliable filter cake. Wh
 imely reacting to any changes to reservoir and well conditions. Using variable positions flow control valve early water breakthrough can be
 cation of new open hole sand face completion architectures equipped with Inflow Control Device technology (first in Ecuador) in Block 15. Th
mercially viable rates. ESPs are commonly used in wells which cannot lift the oil to surface due to low reservoir pressure high water cut and
eacting to any changes to reservoir and well conditions. Using variable-position flow control valves early water breakthrough can be delayed
g two completions in conjunction with surface and downhole monitoring. Three control strategies are tested. The first is a simple passive app
ydraulic fracturing technique as a means to improve productivity of oil and gas wells the hydraulic fracturing community has determined certa

s to build a flow simulation model at the resolution of the petrophysical analysis. By calibrating the high resolution flow model with dynamic te
ments well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D mod
  were conducted using real shaped charges to perforate carbonate core samples under downhole conditions.� Acid was then injected into
 and enhance the well’s performance. The new technique was applied in 2003 to horizontal Well-1 which was drilled by in the Tadrart sa
 alyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures. CTU with 1.5 CT reel w
  Dynamic underbalanced perforating coupled with high performance charges was selected as the technology that would improve productivity
 balance perforation. Although conventional underbalance perforation can be performed using pipe-conveyed or tubing-conveyed perforation
nes. With casingless completions even this option is not available. A downhole orienting and imaging platform has the unique capability to o
 ing. Laboratory tests show how this fast acting dynamic underbalance created across the perforated interval is used to clean�perforation
 ng pressure transient analysis methods to determine the skin were almost exclusively developed with an assumption that the skin factor rem
e of measuring both bottomhole temperature internal and external CT pressure and in addition casing collar locator. The primary objective
ussed. A method based on energy conservation is used to establish a swell model to predict the post-detonation conditions of the perforator.

 ranged from 29% to 66%. Furthermore the reactive liner charges produced characteristic “dynamic overbalance conditions in the wellbo
ns are pulled the well is killed. Perforation and kill related damage severely impacts these wells leading to high skin and rapid production dec
mum flow rate. Using the combination of smart completion and portable MPFM (Multiphase Flow Meter) resulted in reducing the water cut (W
erceived technical complexity of the development and requirement to maximize completion efficiency the operator chose to maximize the in
ction liner. Drift diameter through the tapered production casing is 9 1/2 and 6 1/2 in. respectively. The 6 1/2-in. drift diameter allows using co
 poor natural production from the vertical cased and perforated completions in Hawtah and little associated gas electrical submersible pump
minimal problems. The retrieved screens had collapsed around the perforated base pipe. The well was reperforated new screens run and a
ing remedial sand control solutions were considered namely mechanical and screen-less (chemical consolidation) methods. A proprietary HD

 ering production quotas.� The lower drawdown extends the integrity of sand control completion jewelry reduces water influx fines migrat
 developed requiring extensive fluids testing and reporting at the well site. The paper describes in detail the reservoir completion philosophy

reated-brine and three open-hole gravel packing case histories from one UGS field in Italy. In the three case studies the wells were gravel pa
 ia where two gas wells were drilled with an oil-based drill-in fluid and gravel packed with a viscous water-based fluid. The packing mechanis
orkstring crossover ports open-hole and screen-washpipe annuli and then back to the surface through the washpipe and casing-workstring
 ols and techniques. These developments have resulted in successful gravel packing of wells drilled with oil-based (OB) fluids which have y
se practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid (w
 e practices. Incomplete packing of perforation tunnels is mostly encountered in gravel-pack jobs completed with brine as the carrier fluid (w
h angle wells this normally equates to shooting in the vertical plane through the well path. Over a decade of production experience with this t
  that the failure mode appeared to be wormhole-like failure2. To date there have been several failures with similar characteristics occurred in
ess completion. In this paper the common sequence of events for a screenless completion is presented as well as the key technologies inv

 anism for the sand production. This knowledge was required because attempts to run new completion designs without knowing the cause of
 ght be achieved without overcomplicating the analyses and without requiring complex lab and field data that in most instances will be unav
 These findings contradicted with initial impression and previous expectation on this sandstone that it should have been sand-prone formation
 ation strength and sand production depends on the mineralogical composition of the sandstone and the degree of residual water saturation.

d zone. These volumetric estimates of sand production are often based on rock mechanical models which predict the extent of a yielded zo
bility and sand production prediction tools. Mud weight stability profiles showing the variation of lower and upper bound mud weights with de
l long horizontal and multilateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They
milar to a standard API fracture conductivity cell but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long
of the reservoir untreated. Different acid systems have been developed to counter the problems in acid fracture stimulations. Chemical and m
or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest
 or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest
ost-job production logs clearly show a change in the production profile after the stimulation with the viscoelastic diverting acid system with a
 drawdown required to meet completion objectives. The two exploratory wells in this study were cased with a perforation density of about 5
t. The application also deployed a new nonparticulate material that forms a highly viscous plug when it contacts water and that degrades whe
. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of

ntaining a viscoelastic surfactant system that allows upon acid spending the development of viscosity in situ has shown that significant skin
d in stimulating carbonate formations include formic acetic and more recently citric and lactic. Selecting a suitable organic acid for a specifi


 clay content in the formation the critical velocity was less than one cc/min. Moreover the retained matrix permeability after performing a stat
 echanical techniques are very effective they are more expensive and time consuming than chemical techniques and they are often not appli
st to the reservoir impact final productivity. It equally affects the possibility to flow the well back after stimulation treatment. Hydraulic fracturin
Resonance (NMR) Computed Tomography (CT) scanning Scanning Electron Microscopy (SEM) mercury injection as well as resistivity mea
er parameters such as high BHP (remaining reservoir energy) recoverable reserves f-h1 and favorable response to original fracture jobs (IP
 nmental and economical benefits of using a water-based fracturing fluid a novel visco-elastic surfactant based CO2-compatible high foam
 s—with carbon dioxide advantages of enhanced cleanup and better hydrostatic pressure. This fluid was recently selected for the fracturing
 able pieces of information through the structured process helps put together the “big picture which subsequently provides the support fo

 ater from the stimulation fluid using two different types of viscoelastic surfactant (VES) polymer free diversion systems placed with coiled tu
hind casing as determined by the physical test. For the twenty-eight wells examined twenty-five of the cement log interpretations matched th
  this study are as follows: The analysis procedure is simple enough to implement in a spreadsheet but is more accurate than the currently
erpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as qu
 ir and fracture properties on a layer-by-layer or frac stage-by-stage by evaluating the production well history as an extended drawdown and
al layers varies widely ranging from 1.5 to 15 b/d/psi. This illustrated the need for a method to estimate the permeability and skin of each laye
 vior in these types of completions is different and more complex compared to that of a fully penetrating well. This paper proposes a method
space and time above the pressure gauge resolution and natural background noise which could be as high as 0.1 psi. One of the constant b
  America. The paper briefly discusses the three pillars of digital oilfield; technology processes and people and how they work together to ac
 thetic cases and one field case are considered for the investigation. Our results identify the key issues regarding the successful and practica

 as fracture distribution fracture aperture matrix block size and fracture porosity can be obtained from processing of Image Log data. Simu
tive an additional way to selectively straddle a section of a reservoir and provide the capability to conduct controlled local production and inte
shing commingled AOFP of gas wells. First we conduct a multiple station MiniDST run and interpret the data to estimate reservoir paramete
to assess whether this technology could reduce the uncertainty on oil production by removing any impact of imperfect separation. 20 tests w
 monitored accurately with the in-line Venturi – Dual Energy gamma ray multiphase flowmeter. The importance of the hydrate detection an

 d uncertainty in plans for production optimization. For example the inaccuracies in measured oil rates could be greater than the gain expecte
rate and document major benefits of multiphase well testing are based on the accumulated operational experience from the operations of va
  ion results in excellent predictions of the gas flow rate; the liquid rate prediction is made with acceptable accuracy and no additional measure
 lts by the MPFM. Production test results were carefully analized and compared with the results of test separators for fair evaluation and inter
   simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and ben
ynamic data. •�� Improved history matching of simulation models by incorporating transient pressure data. •�� Use commo
stic function. This paper provides the following contributions for the analysis and interpretation of gas production data using the β-integral
   well-test-pressure data the digital pressure derivative technique. This approach produces the most accurate and representative dp/dt curve
  e transmissibility. While streaming potentials have been observed in many laboratory rock experiments we believe these are the first stream
 paper will focus on an in-depth evaluation of the annular material on the Otway
order principal horizontal stress magnitudes both follow a linear trend
ng in terms of probability and severity and (iii) establishing a risk mitigat
variables facilities well completion number of wells have been include
nhanced to include specific phenomena such as drying-out and saltin
  as well as the acquisition of a geophysical baseline and geochemical monitoring in Ketz
storage is reliable monitoring of CO2 migration behavior and storage volumes. An i
rvoir model to achieve initial equilibrium and also to furth


 drilling performance definition and the payback time for this well was less th
 system with a high dogleg capability has been utilised for successful l

 other reefs in these trends. The reservoir is composed of a limestone matr
 s lift operations in nearby heavy oil fields. Recently a plan of acquisition of inf
metry prediction and formation pressure. The methodology identified several sa
 bility lateral length and reentry drilling time on production
 nto 2 and 3 pseudocomponents and comparing the stability and results using bo
 ercome these challenges a robust chemical shut off methodology had

% in one well and 30% in the other well. It was found that these two
ated using two thru tubing inflatable packers isolating the top an
  it was estimated that only 35% success was achieved worldwide in water s
sposal cost. It leads to scaling in we
ves three key stages; the temporary isolation of the producing layers the perm
the world. Some of these wells started cutting water and as the water
 y to isolate the water producing interval reduce water cut a
ng impact on field development planning especially when dealing with marg
 on in oil/water flows that can lead to better modeling and design of
sed to measure the phase holdups and to demonstrate the slippage be
ce of those advanced wells cannot be accurately dealt with using traditional
00 BOPD from 10 fields (mostly gas and condensates but also oil fields) thr
   mono-bore commingle production was thought to be an option. Also in-
 data were used for a case study to demonstrate the effect of live oil d
eaching an analysis facility. Optimizing the fluid sample acquisition program to m
cted samples. This is due to the nature of CO2 which easily reacts wi

voir pressure. The dewpoint pressure correlation is based
perties yielded best results when compared with compositional simulati
 part this assumption was made because dynamic calculatio
  to identify reservoir fluids in newly drilled wells. Two fluid analyzers we
 oughout all interested zones toward a ‘Continuous Downhole Fl
m industry has devoted much effort to developing computational methods to mode
conventional models are deemed sufficient for pre-job planning and inte
 ctive for compartmentalization characterization. The ability of thin barriers to

 examples in low porosity/low mobility zones are presented showing the id
ed as a non-viable alternative. In this paper we are challenging t
 a yield/temperature correlation to fill in the information void for reservoirs that fall
 s for the assessment of compositional grading in different settings. We
he operator needs to gather as much
analyzing tool string that included the fluid-composition an
on pressure measurement techniques and data quality and comp
 may however be misleading as fluid compositional changes and
detect but the high methane content of these fluids makes possible a


n be prepared. Additionally flow barriers may then be revealed as a
ferent. Real-time application of the FCA can optimize capture of downhole-fluid
as devoted much effort to developing computational methods to model phase b

d equilibrium (VLE).� In contrast to black oil and compositional PVT calculations thermal
mpositions. Live oil/water emulsions were prepared in a con




w focused sampling technology is presented in four case st
 to sample the fluid at downhole reservoir conditions
een questionable in many cases (at very high GVF or in wet gas conditions high p
  ountries. This paper documents new type of sampling device that allows co
ass transfer and surface reaction. The chelating effect of or
 idephase emulsion and regular mud acids have been used in the past on Algyo injec
 ). The reaction rate and size distribution of calcium carbonate
 hloride were used in the tests. All three new chemicals showed improved inh

o pH and temperature. This also allowed the determination of the critical pH valu
nt and magnitude of both the permeability and strength impairment. An indir
 ertain. In this paper we describe the development of mathematical
 ry delineates the detailed sampling and pretreatment analys
on production equipment. This paper outlines the learning procedu
 ent completions by scale deposition. The potential benefits to sca
 e management strategy to monitor and remove Strontium Sulfate scale in Upper Zakum pr
 chemical equilibrium the Mg/Ca and Na/Ca ratios in the brine being
  each region can be history matched independ
  independent regions. Within these regions the fluid flow patt
scussion of some of the results accrued from the incorporation o
 ese sectors has been increased to be able to track the fluid
 Survey were individually validated and subsequently implemented as a sequen
y between injected water and oil bearing reservoir rock. By al
 e optimize areal sweep efficiency by adjusting injection and production a
 belt to exploit extra-heavy oil reserves economically. A typical co
e the oil production rate. A consequential advantage of usi
 .� In these techniques heat is injected into the formation which r
 more efficient than classical cyclic steam injection and more effe
  30 deg deviated well with an AFE over run of 300
Data used in this study includes conventional open-hole we
a single probe technique is limited. Under these conditions
well placement cycle including detailed analysis on the dr
mporarily plugging the zones of high water saturation. Whe


hermal production methods due to historical reasons. Recently Orocual fie

stem minimized the potential for precipitation due to seconda
ampling objectives were: reservoir evaluation formation pressure profiling

 y designed centrifuge system is essential for calibration and

 time and reservoir temperature pose difficult cha
 ns of conventional systems. Extensive laboratory studies which

 ital permanent down hole monitoring system. Using HPHT permanent sys
 its. The methodology adopted in the design execution and evaluation of th
 rs at high temperature by effective damage removal and further matrix dis
chanically ground field samples. Treatment with acidic chelant fluids gener
s also feasible for the given conditions of this high temperature formation
gas into brine-saturated cores at different pressure gradient
s into scale and corrosion models. It is proposed that the direct pH measuremen

 ation of the entire interval.� The multistage OH completions have resulte

 ntegrated with adaptive modification to the factory mode. This approach will
  ell completion program based on data from an open hole logging and geomechanics. S
 ressure changes because of fluid
   well as among the fractures. The hydraulically stimulated volume is represented by a hor
  analysis using these models improved the identification and charac


 raulic fracturing as risky and costly operation prevented rather th
 g stimulation treatments to produce the gas economically. The conve
  be produced by existing or additional vertic
 ell spacing and infill-well patterns. Production for old wells and infill wells
nd optimize treatment solutions Understand limited entry Identify water producing zones
 (injector/producer pairs injection/production rates etc.) and their resu
uth Texas tight gas sand field. Several wells were evaluated using micro-resis

 enhanced formation evaluation which allowed reduced co
 ultiple thin zones which make it difficult to predict reservoir fl
  a variety of techniques including pressure transient
a acquisition objectives more efficiently than long-established metho

 h the enhanced capabilities of the new generation of tools ma
  increase from an intermittent hundreds of BOPD to more than 75 000 BOPD
 rtical wells. With costs more than double those of vertical wells the eco
 is new approach consists on high-potential zone localiza


 apillary effects changing wettability and saturations and pressure

 g the producing life of existing wells resulting into declin
policy in particular identifying levels of risk tolerance. By inter
ysis will lead to significantly better decisions related to
 all bore hole quality as well. Introduction It was long rec
n questioned. In a well in a complex carbonate reservoir
ues in the ERA data acquisition and interpretation b
he conventional logs as input of the neural network model. T
massive laminated and cross-bedded) shale (thin laminated and slump
otos that provided at least twice as many dips than borehole im
ally increases the accuracy of these measurements. The tool uses
used to identify reservoir fluids in newly drilled wells. Two fluid analyzer
 icro meso and macro porosity.� Borehole image logs hav
mprising of fluvial to deltaic deposits overlying the Precambr
es measurements of gamma ray propagation resistivity gamma-gamma density and thermal-neutron por
 he traditional measurements such as gamma ray resistivity density a

 lysis techniques were used to develop these charts and hence used as a
 ror analysis techniques were used to develop these charts and hence use
mparison with Special Core Analysis (SCAL) data. This workflow i
 -mud. Complicated structures were resolved utilizing the dip data gathered wi
ore size compute permeability and assess the rock types independently of
 hod are compared to the sand counts from a high resolution bor


  high-resolution data is acquired to estimate sand volume f
 ation is by pulse neutron (PN) after well comple
ansient analyses and production data borehole image logs prov
he well to acquire the required samples and fluid profiling stations.
 lows differentiation between natural and drilling-induced fractures wh
raction method was used to extract channel events and integra

servoir model. An accurate reservoir characterization should
uate the prospect but operational and economical
resolution of conventional logs that have a typical vertical

ure changes). Here we demonstrate the applications of the method which allows dynam

sweep (c) choose the right time window for fractur
wave velocities are used to estimate these parameters.� However the
  at three depths in shale thus yielding two minimum horizontal stress magn
 he multi-rate deliverability tests are performed under boun
 he multi-rate deliverability tests are performed under boun
 he multi-rate deliverability tests are performed under boun
ation contain significant oil reserves but are of less importance. However
 using formation micro imaging tool. Also to quantify
 n of the fracture distribution model using the Continu
er applicable were generated. These fracture pr
  5) construction of the fracture distribution model usin
 vant data that include time-lapse pressure production and inject
esentative and accurate mobility/permeability distribu
 adial extent was quantified. �The MDT-IPTT tests quantified the virgin zon
 sit time for the matrix. To corroborate that the obtained effective NMR p
 ter and OBM filtrate (OBMF) at multiple depths
  method based on NMR analysis to estimate net producible pay and its
ng the extremes of T1 T2 or D such as light hydrocarbons gas water at h
hods. Introduction of pulsed-NMR logging tools in the 1990s pro
 s study a two step petrophysical evaluation
 low profiles and fluid break-through. Production flow profiles are a

 ion rates during UBD depend on the format
potential for horizontal well placement. It was impossible to rea

 migration and entrapment reservoir connectivity
 nd newly acquired DFA log data matched for the first produc
 multi-rate deliverability measurements are obtained und
pected the remaining oil saturations lead to the suspicion
y uncertainties of such reservoirs. The main challenges

 he wireline dual packer and standard probe modules provided estimates o
 y conditions deployed here which are unique to a supercharged
   coupling system for multiple-reservoir models. Uncertai
development project. Logging-while-drilling logs wirelin
 llow ‘A’ sands.� These wells are currently produced through g
eam studied and recommended the implementation of a program to drill a
ors and fluctuation in gas availability it is
proactive well placement technology can be translated into maximum reserv
ble to trace the sand while drilling across the heterogeneous sa
sponse of wells in high-pressure area and low-pressure areas of the reservo
  significantly compared to the offset field development plan (FDP) while wat
s using dynamic simulation with a coupled surface
em (Electrical Submersible Pump ESP) through a network simul
 iple surface/subsurface simulators. One real field case that requires advance/compl
 need to accommodate these changes while taking
 ndary and tertiary recovery methods investigated
 uncertainties and risks associated with proposed activities fu


M in order to accurately determine the well performance and the rese
econd reservoir is a gas condensate system much smaller than the
00 BOPD from 10 fields (mostly gas and condensates but also oil fields) thr
cilitates the flow of task outcomes between project team members and creates
percent to 80% to 90% within the first 2 years of production. Typically sidetrac

paper is based on a field-wide production plann
pay zone during completions were applied to maximize res
 ates. Well productivity is highly dependent on hydraulic fract
  relatively simple equations that result from a combination of compl
n where to place an injector well relative to a fault. The exampl
  challenges of maintaining a horizontal wellbore inside a thin hyd
 rder to map the relative position of the drainhole to the ov
 es rather than infrastructure considerations which may favor a mo
  from the downdip location to an updip location. When
which is critical for a sound management decision. Whereby
  tory near placement to the current oil-water contact an
NPV) on the basis of which improving well locations can be determined.
odel that was developed was compared with simulation done by commercial reserv
 ition and time to be used to treat either pressures o
 rcy flow factors as well as constant well pr
ased on a generalized travel time inversion and utilizes the adj
  account for complex physical behavior that dominates mos


 can then be combined in different combinations to obtain

 c steam injection case with other commercial simulators. We also demonstrate the p
 With this general formulation approach we can model most reservoir physics with a
 ature and the dynamics within the horizontal

 sociated with undulations in the wellbore traj



  paper focuses on concepts that enable engineers determi
 r and fracturing gel. Introduction Hydraulic fracturing has been used as
apturing the yield stress of common polymer gel. The mode
 reservoir/well model complex reservoirs are simulated and
d multicomponent fluids flow. It is also assumed that conductive fracture coul
 ired by the model are defined and the application of
se factors include non-Darcy effects along the fracture mult
 dition the issue of flow convergence near the perfor
  ems for production analysis are typically undetermined an
h a review of appropriate applications of the apparent wellbore radius
 t only replaces the line source and linear flow assumptions (a c
 ot essential as it does not affect the quality of result
example the errors in predicted fracture spacing for the Lisburne format

d into three main reservoirs that are compl
 analytical solution given in this paper and those
ackground theory of IPI. The consequences of IPI for
ut pressure for the MB model production-derived relative perm
 pproach was proposed using experimental design and analysis of vari
mendations. This paper illustrates the authors’ approach to the mature f
tialization in hydrocarbon reservoirs. This is caused in part b
 al development options for fifteen reservoirs situated in four different

wo-point flux approximation (TPFA) is used in commercial r
cast the production profile and field development manage
 om water-oil systems and is very complex the simulation of this pro
eloping an integrated yet efficient fracture modelin

mulators. To realize this model it was necessary to reformulate the mat
 nsport part is solved along a set of one-dimensio
iscale basis functions. This method has limited sensitivity to grid distorti

 predictions with an uncertainty range similar to the one obtained with RML. In
 significant opportunity for improving the accuracy of such calculati


ructed by thresholding of negligible details. Then a sec
tention from the research and the oil and gas industry. The reason for this interest l
me group are combined to a type curve that is described by
 aluate the uncertainty in reservoir description and performance predictions.
nition technique is then used to rank the geostatistical reservoir models.
 nted. Introduction Advanced well completion solutions

ohibitively computationally expensive for a multi-scenario prod
 eneral case the model is fundamentally different from Archie's la

  packs. Models for flow beyond the Forchheimer regime are also s
 nd oil based mud are considered. It is shown
   intricate vertical and deviated fracture networks undefined faulting regime
e orientation of N10degE exists in most of the region.The sec
ve a common vision of what a truly Smart Field will look like and this contributes to th
viet Union and Russia for the last 25 years an analysis of recent effo
 ties but differ in several key areas including government policy. This paper examines
ecause typically these papers have addressed only one or two


 ntact. In these wells the water shutoff leaves oil behind a
 laterals and is the first installation of its type. This capability is critical
on due to complicated nature of the production strings and the risk of
 xial symmetric production logging tools in ERD well bores.�

ed the fluid or by excessive contamination levels that render
ed the fluid or by excessive contamination levels that render
leakage. Included in the paper are the design criteria deployment methodolog
ntiometric methods in which fouling of electrode surfaces by oil and mud is a poten
y of the reservoir geomechanics. The geomechanical characterization of the res
  events provides following insights into reservoir management. First initial gaps i
 rofile within a fracturing simulator to the most robust

 cosity water cut and permeability on fluid flow an
 ate the formation inflow into wells in which the velocities are
uate the formation inflow into wells in which the velocitie
be measured and therefore the inflow distributi
of of fluid flow from different fault blocks;
 ver the years many instruments have been used to collect and process flow data


e efficiency can be defined as the ratio between theoretical result from a model
high water cut. These specifications are tested by
 ervation wells. This paper describes a systematic methodology to select we
 o be the cause of the production decline. However with inadequate inform
d by solid production etc. In this paper we are illustrating the v
 uisition objectives cannot be overstated given the high cost
 ate determination layer pressure changes smaller than 10 psi
of the temporal response of the microseismic deformation with the surface
een wire-wrap. Thus a direct measure of each individual reservoir
 e system became activated when a mating inductive coupler was landed as part of
n logging tool (PLT) and production data indicated that there are a few thief zones

ws: Virtual Rate Measurement (VRM): ensuring accuracy of the volum
irms the available multi-phase holdups. When water velocity and water holdup ar

 gypt. The well was drilled in early 2006 followed by logging and test
by variations in the reservoir rock cementation factor while
 ction pilot pattern is being implemented. The pilot will address th
es core descriptions and detailed log analyses into the
l knowledge of perforating characteristics in sandstones and to a lesser extent carbonates
  h cleat density in coal seams is an essential requirement for bett
 is as well as micro seismic results and frac tracer analysis
 l source of expense and downtime. This field study examines 256 ho
vide a simplified methodology for first-pass calculation of
 � A large-volume pressure pulse is released downhole during the f
  the formation imager.� It produces electrical images of
   massive multistage multicluster hydraulic fracturing tr
  achieved. A study was conducted to examine several completion strategies
 lling is starting to slow shale gas continues to be one of the hott
is unconventional gas reservoir the restimulation of horizonta
 r rendered wormholing pattern by pre-selected acid formulation and volume f
  run life of operating ESPs is 2.7 years and that o

wdown is transmitted downhole by pressure
 o produce with vertical wells because of poor economics. Another cru
 uch as cased hole gravel-pack or frac-pack completions the openhol
 iston squeezes a Cring and makes the ID smaller. At the end of the fracture
 n and estimation of the radial extent of the near-wellbore mech
um gas recovery possible under those conditions.�
um gas recovery possible under those conditions.�
boundary measurements to place this first MRC w

 ed. Approval of the concept was achieved when the anticipated benefits were reali
 essure and flow-rate control systems are discussed. Downhole contro
put on production and tested. The concept was approved when the anticipated bene

 very by 90% in the early stage of production compared to the horizontal well. Thu
ze actual production that measures up to the forecasted potential of the we
 ered. We demonstrate the practical utility of this methodology on a c
m which was field tested for the first time in the world in a Saudi Aramco
predictability. Future plans include continuing to stimulate candidate well
 iber to bridge at the fracture entry face and divert the treatmen
ogy combination additionally enhances fracture placement succes
 nstances acid fracturing ends up over-stimulating the hig
meters (including PI and Jd) evaluation. Analyses of the fracturing trea
 oncentrations. Imbibition and drainage tests were done which
 mechanics fundamentals as well as the coupled fluid pressure effect in hydraulic
mpurity composition and concentration it is extremely challen
crosslinked fluids are discussed. We will describe in detail ho
 lation techniques (proppant & fluid volumes) and to validate the diff
ervals and mitigates the risk of growing the fracture into the water-pr
 he uncontrolled fracture height growth into the water zone
  drop to zero shortly after the completion in 2004 due t
 rom high permeability intervals to low permeability
  ell productivity. This paper describes the experience of three operators in Latin

 n attempts with coiled tubing have yielded modest improvements ma


at had to be addressed. For Fracture containment Schlumberger’s Sonic Scanner tool
d in this work are provided for fracture stimulation design.� A produ

 d highlighting the differences with the Western Siberian approach to hy

 e inside the sliding sleeve. Pressure is then increased until the next
 leeve valve shapes to verify the FEA study and to selec
 gy dissipation in the plastic zone. The dependence of the apparent
 tire propped fracture design was successfully pl

and longer effective fracture half-lengths.� Results also indicated successful stimulation past


 rformance. Detailed fluid system used in the treatment is discussed i
 f excessive filter cake thickness. Experimental dat
duction log interpretation in addition to production analysis.� The resul

 etected fracture(s).� The uncertainty of the relative positions between t

 ly moves the sample in selectable increments
ostly fracture job size and cost. Height growth has also
ociated with radioactive tracers. Once the proppant is placed in

wells for stimulation treatments was clearly needed.
permeability was explicitly modeled in t
 . The flow within the reservoir due to leak-of
 tant based acid did clean out in a shorter period of time. The ma
ure cleanup width changes conductivity degradation with
mage the stimulated fracture network. Microseismic
 he fracture was created in a very weak reservoir formation. Acc
 stress increase at the tip of the orthogonal
oil collecting area. Thus stability and quality of displacem
 d in carbonates very few cases of its application in t
 ould significantly change the common industry pra
 ed closure stress. Possible explanations for such b
 ations were evaluated in five different boreholes providing a di
ower fracture growth and shorter overall fracture length develo
 wn and commonly used in nodal analysis and conven
pes from sand control and well productivity standpoints. Characteristics of bp Trinidad & Tobag
 completion options. First the horizontal section can be completed
 completion options. First the horizontal section can be completed
 ate a thin and reliable filter cake. While drilling this well
ve early water breakthrough can be delayed to increase
 logy (first in Ecuador) in Block 15. The design and well preparation p
servoir pressure high water cut and high back pressure
y water breakthrough can be delayed to increase rec
ted. The first is a simple passive approach using a fixed contro
ring community has determined certain containment mecha

esolution flow model with dynamic test data from a
MEMs were distributed in the 3D model using Gaussian sequential simulati
 tions.� Acid was then injected into the perforations to create wormhol
 which was drilled by in the Tadrart sandstone formation of the Berkine
 procedures. CTU with 1.5 CT reel was used to convey 14
ology that would improve productivity in the challenging wells of Santa Ana. This tec
veyed or tubing-conveyed perforation (TCP) depth uncertainties and the time req
 atform has the unique capability to orient guns along
erval is used to clean�perforation tunnels and produce low to zero damage perforatio
n assumption that the skin factor remains constant during a te
collar locator. The primary objective of the job was to ensure that the
tonation conditions of the perforator. The model takes

  overbalance conditions in the wellbore in a system configuration whic
 to high skin and rapid production decline. The challenge in this f
  resulted in reducing the water cut (WC) form 20% to 0% maintaining t
he operator chose to maximize the integration of the services by bund
6 1/2-in. drift diameter allows using common-sized screens and p
 ted gas electrical submersible pumps (ESPs) have been used in Hawtah to enhan
eperforated new screens run and a second frac pack pumped. When laying down
 solidation) methods. A proprietary HDR squeeze pack technique (mechanical method)

ry reduces water influx fines migration and increases recovery factors
il the reservoir completion philosophy drilling and c

case studies the wells were gravel packed using shale stabilizer
 r-based fluid. The packing mechanisms and efficienci
  the washpipe and casing-workstring annulus. In the open-hole section flow th
h oil-based (OB) fluids which have yielded well productivi
 leted with brine as the carrier fluid (water packs). The proposed
eted with brine as the carrier fluid (water packs). The proposed t
e of production experience with this technique on the
with similar characteristics occurred in Stag field. Water i
 d as well as the key technologies involved from perforating to p

esigns without knowing the cause of the sand and understanding the risks had been pro
 that in most instances will be unavailable or the acquisition of which will incur
ould have been sand-prone formation. Facing these appa
 degree of residual water saturation. The effect is most significant for sandstones

hich predict the extent of a yielded zone using various con
nd upper bound mud weights with depth were developed for typi
evels reached nearly 10 mol%. They were also utili
ong in the leakoff direction. The long c
fracture stimulations. Chemical and mechanica
uring ends up stimulating the highest reservoir qu
uring ends up stimulating the highest reservoir q
 oelastic diverting acid system with a significant increase i
with a perforation density of about 5 shots per foot (spf) over relati
 ontacts water and that degrades when mixed with oil in the
 ent paper describes a comparison of procedures and produc

n situ has shown that significant skin reductions can be obtained provided
g a suitable organic acid for a specific acidizing


x permeability after performing a static leakoff test
chniques and they are often not applicable or not effective in we
 ulation treatment. Hydraulic fracturing t
ury injection as well as resistivity measurements chemical testing etc.� Eac
 response to original fracture jobs (IP) could play an equally important r
  based CO2-compatible high foam quality (>60%) fluid was propo
s recently selected for the fracturing treatments on three wells. Initial prod
 subsequently provides the support for engineering decisio

 ersion systems placed with coiled tubing (CT) prov
ement log interpretations matched the communication test results. One well which c
 t is more accurate than the currently available methods. Calcula
 int pressure estimation as well as quantification o
 story as an extended drawdown and in combination with direct
 he permeability and skin of each layer. This information was
well. This paper proposes a method for identifying on the
high as 0.1 psi. One of the constant background noises
ple and how they work together to achieve continuous reservoir and
regarding the successful and practical application of each method. In addi

processing of Image Log data. Simulation of n
 t controlled local production and interference as well as to enable the cap
  data to estimate reservoir parameters (k s and p*). We also compute non-Darc
ct of imperfect separation. 20 tests were performed considering 15
 portance of the hydrate detection and mitigation processes is essential in

ould be greater than the gain expected from a stimulation or restor
experience from the operations of various multiphase flowmeters in the area. Mos
e accuracy and no additional measurements. The wet gas and low-liquid-volume-frac
eparators for fair evaluation and interpretation of well’s behaviour. T
 ell based on the advantages and benefits of the� industry recognized Vx* Technology.�
 ssure data. •�� Use common data models like fluid (PVT) and
oduction data using the β-integral
 urate and representative dp/dt curve by incorporating knowledge of both
  we believe these are the first streaming potential transients to be measur

				
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