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					  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
SHELL                   SPE    121272             CO2
SHELL                   SPE    121272             CO2
Distinguished Author    SPE     93951             CO2
SHELL                   SPE    113917           EOR/IOR
SHELL                   SPE    113358           EOR/IOR


CHEVRON                 SPE    112375           EOR/IOR
BP                      SPE    102239           EOR/IOR
SHELL                   SPE    120428           Heavy Oil
SHELL                   SPE    107201           Heavy Oil

CHEVRON                 SPE    122922           Heavy Oil
BP                      SPE    122793   Low Permeability Reservoirs
SHELL                   SPE    100574   Low Permeability Reservoirs
SHELL                   SPE    115034   Low Permeability Reservoirs
SCHLUMBERGER            SPE    123296   Low Permeability Reservoirs
SCHLUMBERGER            SPE    103250   Low Permeability Reservoirs
SCHLUMBERGER            SPE     90630   Low Permeability Reservoirs
SHELL                   SPE    110379     Reservoir Management
SCHLUMBERGER            SPE    122339     Reservoir Management
SCHLUMBERGER            SPE    122421     Reservoir Management


CHEVRON                 IPTC    11219     Reservoir Management
SHELL                    SPE   109826     Reservoir Management


CHEVRON                 SPE    100656     Reservoir Management


CHEVRON                 SPE    102988     Reservoir Management


CHEVRON                 SPE     89755     Reservoir Management
SHELL                   SPE    121891     Reservoir Management
SHELL                   SPE    119156     Reservoir Management
                Section                                Subject
           Modelling - Injection                     Geochemical
           Modelling - Injection                     Geochemical
                 Storage                                 Aquifer
   High Pressure Air Injection - Modelling        Impact of Combustion
        Modelling - Foam Injection                   Heterogeneity


     Modelling - Near Wellbore Effects            Gravity Segregation
         Modelling - Waterflood                  Controlled composition
     Modelling - Fractured Carbonate               Integrated Study
       Modelling - History Matching                 Steam Injection

            Modelling - Streamline                Technique Evaluation
     Modelling - Fracture Performance          Fractured Well Performance
     Modelling - Fracture Performance            Multilayered Reservoirs
Modelling - Probablistic Production Analysis          Inflow Profiling
    Modelling - Reservoir Performance            Production Forecasting
   Modelling - Single well Performance           Optimised Completions
            Modelling - Streamline                   Fluvial Reservoir
  Modelling - Coupled Fracture/Reservoir        Fractured Water Injection
Modelling - Coupled Surface/Reservoir Model      Production Optimisation
Modelling - Coupled Surface/Reservoir Model            SMART wells


      Modelling - Experimental Design           Development Optimisation
      Modelling - Experimental Design               Steam Injection


      Modelling - Experimental Design                  Tahiti Field


      Modelling - Experimental Design                  Tahiti Field


     Modelling - Experimental Design                   Thin Oil Rim
     Shell's Adjoint Simulation Method                  Simulation
     Shell's Adjoint Simulation Method         Well Placement Optimisation
                                              Title
Injection of Supercritical CO2 into Deep Saline Carbonate Formations, Predictions from Geochemical Modeling
Injection of Supercritical CO2 into Deep Saline Carbonate Formations, Predictions from Geochemical Modeling
Modeling Long-Term CO2 Storage in Aquifer With a Black-Oil Reservoir Simulator
The Modeling Challenge of High Pressure Air Injection
Foam Modeling in Heterogeneous Reservoirs Using Stochastic Bubble Population Approach


Well Stimulation and Gravity Segregation in Gas Improved Oil Recovery
Modeling Low-Salinity Waterflooding
From Data Acquisition to Simulator: Fracture Modeling a Carbonate Heavy-Oil Reservoir (Lower Shuaiba, Sultanate of Oman)
Realistic History Matching of Cyclic Steam Stimulation Performance of Several Groups of Multilateral Wells in the Peace River

Evaluation of Streamline Simulation Application to Heavy Oil Waterflood
Advancing Reservoir Simulation Capabilities for Tight Gas Reservoirs
Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered “Tight Gas Reservoirs: A Case History in t
Improved Production Profiling Using Thermal Balance and Statistical Modeling in the Pinedale Anticline of the US Rocky Mount
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
Waterflooding Under Dynamic Induced Fractures: Reservoir Management and Optimization of Fractured Waterfloods
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
The Jurassic-Age Marrat Reservoir at Humma Field, Partitioned Neutral Zone (PNZ), Saudi Arabia
and Kuwait—Utilization of a Probabilistic, Two Stage Design of Experiments Workflow for
Reservoir Characterization and Management
Peace River Carmon Creek Project—Optimization of Cyclic Steam Stimulation Through Experimental Design

Tahiti: Development Strategy Assessment Using Design of Experiments and Response Surface
Methods


Tahiti Field: Assessment of Uncertainty in a Deepwater Reservoir Using Design of Experiments


Production Strategy for Thin-Oil Columns in Saturated Reservoirs
Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and Improved Well Clean-up Tim
Automatic Well Placement Optimization in a Channelized Turbidite Reservoir Using Adjoint Based Sensitivities
                                 Author                                      Abstract
                                                                             Abstract Modeling of supercritical Berkeley Nation
C. Taberner, G. Zhang, and L. Cartwright, Shell International Exploration and Production; and T. Xu, LawrenceCO2 injection int
                                                                             Abstract Modeling of supercritical Berkeley Nation
C. Taberner, G. Zhang, and L. Cartwright, Shell International Exploration and Production; and T. Xu, LawrenceCO2 injection int
S. Mo, SPE, and I. Akervoll, SINTEF Petroleum Research                       Abstract This paper presents results of modeling
                                                                             Abstract High Pressure International Exploration
A.H. de Zwart, D.W. van Batenburg, C.P.A. Blom, A. Tsolakidis, C.A. Glandt, and P. Boerrigter, ShellAir Injection (HPAI) is a po
                                                                             Abstract Foam is an attractive option in EOR for in
F. Farshbaf Zinati, R. Farajzadeh, and P.L.J. Zitha, Department of Geotechnology, Delft University of Technology, The Netherla
M. Jamshidnezhad, Delft University of Technology; C. Chen, Chevron
Energy Technology Company; and P.�Kool and W.R. Rossen, Delft
University of Technology                                                     Abstract Models for gravity segregation in gas imp
                                                                              SPE, BP
Gary R. Jerauld, SPE, C.Y. Lin, Kevin J. Webb, SPE, and Jim C. Seccombe,Summary Low-salinity waterflooding is an emergin
                                                                             Abstract A dedicated appraisal campaign and mod
Georg M.D. Warrlich, SPE, Pascal D. Richard, SPE, Timothy E. Johnson, Petroleum Development Oman, L. Bart M. Wassing,
Paul Frantisek Koci and Junaid Ghulam Mohiddin, Shell Intl. E&P Inc.         Abstract With 8 billion barrels of bitumen in place a

I. Osako, M. Kumar, V. Hoang, and G. Balasubramanian, Chevron ETC            Abstract Lack of analogs and the nature of high m
                                                                             Abstract is critical to BP Canada Energy spaci
Yafes Abacioglu, SPE, and Herbert M. Sebastian, SPE, BP America Inc., and Jubril B.ItOluwa, SPE,identify optimum wellCompa
                                                                             Abstract Low permeability or “tight Shell E&P
S.K. Schubarth, SPE, Schubarth Inc.; J.P. Spivey, SPE, Phoenix Reservoir Software LLC; and P.T. Huckabee, SPE, gas reser
                                                                             Abstract The Pinedale anticline is located in the Gr
G. Donovan, P.E., SPE, D. Dria, SPE, G. Ugueto, SPE, Shell E&P Co., A. Gysen, Interpretative Software Products
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 It is well B.V., J.D. Jansen, Delft Univers
P.J. van den Hoek, R. Al-Masfry, and D. Zwarts, Shell International Exploration and Productionestablished within the Industry th
                                                                             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
W. Scott Meddaugh, SPE, Chevron Energy Technology Company; David
Barge, SPE, Saudi Arabian Chevron; and W.W.�(Bill) Todd, SPE, and
Stewart Griest, Chevron Energy Technology Company                            Abstract The Jurassic-age Humma Marrat carbona
                                                                             Abstract Peace River Carmon Creek is a 100% Sh
Paul Frantisek Koci, SPE, and Junaid Ghulam Mohiddin, SPE, Shell International E&P
P.E. Carreras, SPE, Chevron Energy Technology Co., and S.E. Turner,
SPE, and G.T. Wilkinson, SPE, Chevron North America Exploration and
Production Co                                                                Abstract Tahiti field in deepwater Gulf of Mexico i
P.E. Carreras, SPE, and S.G. Johnson, SPE, Chevron Energy Technology
Co.; and S.E. Turner, SPE, Chevron North America E&P Co., Chevron
Corp.                                                                        Abstract Tahiti prospect in deepwater Gulf of Mex

C.S. Kabir, SPE, Chevron Energy Technology Company; M. Agamini, SPE,
Chevron Nigeria Limited; and R.A. Holguin, SPE, Chevron North America Summary Maximizing oil recovery in thin and ultra
                                                                           Abstract The most common
O. Vazquez, SPE, E. Mackay, SPE, K. Sorbie, SPE, Heriot-Watt University and M. Jordan, SPE, Nalco method for preventing
                                                                           Abstract Economic constraints impose
David Casti�eira, Faruk O. Alpak, and Detlef Hohl, SPE, Shell International Exploration and Production Inc. usdc stringent lim
supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite with minor anhydrite) was performed
supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite with minor anhydrite) was performed
 presents results of modeling long-term CO2 storage in a shallow saline aquifer with a commercial black-oil reservoir simulator. Realistic CO
ure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep high-pressure light oil reservoirs after waterflooding.
 attractive option in EOR for increasing oil recovery in mature water-flooded reservoirs. In this paper we use stochastic bubble population mo


 ravity segregation in gas improved oil recovery (IOR) indicate that the distance injected gas and water travel together before complete segre
 y waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is controlled to improve oil
 appraisal campaign and modeling study was carried on a heavy-oil fractured Shuaiba field in the north of the Sultanate of Oman to assess t
n barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects Peace River offers an excellent growth o

  logs and the nature of high mobility ratio waterflood conditions pose many difficulties for reliable performance forecasts for heavy oil waterflo
  o identify optimum well spacing to develop cost-effective full field development plans for tight gas reservoirs. Accurate prediction of well perfo
  ability or “tight gas reservoirs are being developed at an ever increasing rate in the U.S.�The amazing increase in activity in the Roc
 e anticline is located in the Green River Basin of Southwestern Wyoming USA. The field is the largest tight gas discovery for the onshore reg
 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
 ablished within the Industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs
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


c-age Humma Marrat carbonate reservoir is mainly located in the southwest corner of the Partitioned Neutral Zone (PNZ) between Saudi Ara
 Carmon Creek is a 100% Shell owned ultra-heavy oil lease located in north-western Alberta Canada approximately 700 km northwest of E


 n deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt with primary hydrocarbon-bearing turbidite sands ranging


 ect in deepwater Gulf of Mexico is a three-way anticlinal structure trapped against salt with primary pay sands ranging from 24 000 to 27 00


 g oil recovery in thin and ultrathin (< 30 ft) oil columns is a challenge because of coning or cresting of unwanted fluids regardless of well orie
 mmon method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process a scale inhibitor solution is i
 onstraints impose stringent limits on the number of wells that can be drilled in deepwater developments. Thus optimal placement and opera
with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction model implementation for handling high
with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction model implementation for handling high
k-oil reservoir simulator. Realistic CO2/water phase behavior (pVT properties) covering all pressure temperature and compositional conditi
 ght oil reservoirs after waterflooding.� The advantage of air over other injectants like hydrocarbon gas carbon dioxide nitrogen or flue g
use stochastic bubble population model and complex power law rheological model to integrate foam physics into a flow simulator. Foam dis


 avel together before complete segregation scales with the injection rate Q. Therefore in cases where injection pressure is limiting reducing
 ed water is controlled to improve oil recovery vs. conventional higher-salinity waterflooding. Corefloods and single-well chemical-tracer tests
of the Sultanate of Oman to assess the feasibility of steamassisted gas-oil gravity drainage (SAGOGD) EOR. In this field key to a successfu
ace River offers an excellent growth opportunity for Shell’s ultra-heavy oil portfolio. In support of this initiative integrated geological and r

                                                     OnePetro
mance forecasts for heavy oil waterflood.� In many cases although numerical simulation is the method of choice for forecasting it also fac
  oirs. Accurate prediction of well performance is a major challenge that arises during the development of such reservoirs. Understanding wel
mazing increase in activity in the Rocky Mountain region over the past decade is a testament to this.�Currently there are several “tigh
 ght gas discovery for the onshore region of the United States in the last twenty years (Robinson and Shanley 2004). Gas production is from v
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
Particularly in low-mobility reservoirs large fractures may be induced during the field life. This paper presents a new modeling strategy that 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


 utral Zone (PNZ) between Saudi Arabia and Kuwait. The reservoir was discovered in 1998. The reservoir depth is about 9000 ft subsea. The
 pproximately 700 km northwest of Edmonton (Fig. 1). It holds nearly eight billion barrels of 7�API oil in place spread over 370 km2. The C


 arbon-bearing turbidite sands ranging from 24 000 to 27 000 ft TVD. The discovery well was drilled in 2002 and two appraisal wells were dr


                                                                                 OnePetro
 sands ranging from 24 000 to 27 000 ft TVD. The field contains several hydrocarbon-bearing turbidite sands. The discovery well was drilled


 wanted fluids regardless of well orientation. Significant oil is left behind above the well completion even for horizontal wells when bottom- or
 process a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly scale treatments comprise th
  Thus optimal placement and operation of wells have a major impact on the project rewards. Well-placement in deepwater developments is
odel implementation for handling high salinity problems (Zhang et al. 2006). The formation brine salinity is ~225 000 ppm (NaCl dominant) te
odel implementation for handling high salinity problems (Zhang et al. 2006). The formation brine salinity is ~225 000 ppm (NaCl dominant) te
mperature and compositional conditions accounted for during the simulations have been used. The pressure and temperature in the aquife
as carbon dioxide nitrogen or flue gas is its availability at any location.� HPAI has been successfully applied in the Williston Basin for mo
 ysics into a flow simulator. Foam displacement is examined in layered reservoirs with and without isolating shale barrier between the layers a


 jection pressure is limiting reducing skin resulting from damage at the wellbore face directly increases volumetric sweep of gas in IOR. Even
 and single-well chemical-tracer tests have shown that low-salinity waterflooding can improve basic waterflood performance by 5 to 38%. Thi
 EOR. In this field key to a successful SAGOGD is a well-connected fracture network which was investigated by a dedicated appraisal camp
 initiative integrated geological and reservoir modeling of two project areas was conducted. The key objectives were to improve predictive m


  such reservoirs. Understanding well performance is needed for both well design and depletion planning.� Almost all wells in tight gas field
½Currently there are several “tight gas plays in the U.S. that involve the commingling of multiple intervals in order to gain economic viab
 anley 2004). Gas production is from very tight stacked clastic reservoirs that are Upper Cretaceous in age with productive intervals in exces
 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
 sents a new modeling strategy that combines fluid-flow and fracture-growth (fully coupled) within the framework of an existing ‘standardâ€
 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


 ir depth is about 9000 ft subsea. The gross reservoir interval is approximately 730 ft thick (110 ft net). The lowermost Marrat E zone contribu
 n place spread over 370 km2. The Carmon Creek Project targets possibly about half of that oil for development by cyclic steam stimulation


 002 and two appraisal wells were drilled soon afterwards. Due to significant uncertainties remaining after appraisal probabilistic methods w




  for horizontal wells when bottom- or edge-water invasion occurs. Two depletion strategies may be enacted to improve recovery of the rema
mmonly scale treatments comprise the following stages: preflush main scale inhibitor pill overflush tubing displacement and shut-in followed
 ement in deepwater developments is a challenging optimization problem. Manual approaches to its solution can be cumbersome even with g
 s ~225 000 ppm (NaCl dominant) temperature at 102oC and pressure at 225 bars. CO2 injection rate was considered constant for a period
 s ~225 000 ppm (NaCl dominant) temperature at 102oC and pressure at 225 bars. CO2 injection rate was considered constant for a period
ssure and temperature in the aquifer is above the CO2 supercritical conditions giving rise to the existence of a two-phase fluid system of CO
y applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.
 ng shale barrier between the layers and in stochastically distributed permeability fields. It is demonstrated that in isolated layers foam propag


volumetric sweep of gas in IOR. Even in the absence of damage at the wellbore face most of the injection pressure is dissipated near the we
rflood performance by 5 to 38%. This paper describes a model of low-salinity flooding that can be used to evaluate projects; shows the impli
gated by a dedicated appraisal campaign which included drilling one vertical and 3 near-horizontal wells. BHI sonic and resistivity logs were
ectives were to improve predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS mu


g.� Almost all wells in tight gas fields are hydraulically fractured. We have investigated methods of simulating hydraulic fractures using coa
ervals in order to gain economic viability.�The Pinedale Anticline of southwestern Wyoming is one of these areas. The Pinedale Anticline
 ge with productive intervals in excess of 6000 feet. The large productive intervals require multiple hydraulic fracture stages to complete. Tim
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
mework of an existing ‘standard’ reservoir simulator. We demonstrate the coupled simulator by applications to five-spot pattern flood m
 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


 he lowermost Marrat E zone contributes 80-90% of the production based on PLT data. The productivity of the Marrat E is dominated by a for
 lopment by cyclic steam stimulation (CSS). There are growth plans for a significant increase in oil production over the next five years. The p


 ter appraisal probabilistic methods were used to assess development alternatives. In this study the classical experimental design method




cted to improve recovery of the remaining oil. In the first option a conventional horizontal is completed below the gas/oil contact (GOC). Onc
ng displacement and shut-in followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in th
 ion can be cumbersome even with good use of engineering judgment: (a) There often exist many combinations of well locations subject to in
was considered constant for a period of 1 year through a horizontal well in a 3D model domain. The carbonate formation was assumed to ha
was considered constant for a period of 1 year through a horizontal well in a 3D model domain. The carbonate formation was assumed to ha
nce of a two-phase fluid system of CO2 as a supercritical fluid (“gas) and CO2 dissolved in the aqueous phase. The objective was to mo
erators for application in their assets.� Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir
ed that in isolated layers foam propagates faster in the high permeability layer and sweeps the low permeability layer only modestly. In comm


 on pressure is dissipated near the well but most of the segregation occurs much further from the well. Therefore if injection pressure is limit
 to evaluate projects; shows the implications of that model and demonstrates its use to represent corefloods single-well tests and field-scale
  BHI sonic and resistivity logs were run to understand static fracture characteristics; dynamic behavior was assessed with DSTs and PLTs.
 tory matching two groups of CSS multilateral wells and develop a history matched physical representation that not only validates empirical


mulating hydraulic fractures using coarse grids since explicitly gridding these fractures can easily lead to an impractical number of grid blocks
  these areas. The Pinedale Anticline completions pose a particularly complex problem when attempting to evaluate the “best method of
 ulic fracture stages to complete. Time-lapsed production analyses are performed to optimize well spacing and to characterize the gas beari
 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
pplications to five-spot pattern flood models addressing various aspects that often play an important role in waterfloods: shortcut of injector a
 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


 of the Marrat E is dominated by a forty-foot thick largely dolomitized interval with 15-20% porosity and 20-100 mD permeability. The upper z
 ction over the next five years. The purpose of this study was to optimize CSS well configuration and steaming strategy for each distinct rese


 assical experimental design method was applied and reasonable P10 P50 and P90 reservoir simulation models were designed. Next we lo




 elow the gas/oil contact (GOC). Once the well waters out the well is recompleted in the gas zone. Completion occurs either at the crest for a
 pplied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking thus avoiding slow
 inations of well locations subject to investigation; (b) There is need to optimize operational constraints for every well-placement scenario; (c)
 onate formation was assumed to have homogeneous porosity and permeability and to be overlaid by an impermeable seal. The effect of a h
 onate formation was assumed to have homogeneous porosity and permeability and to be overlaid by an impermeable seal. The effect of a h
eous phase. The objective was to model scenarios of CO2 storage in aquifer with emphasis on the sensitivity of CO2 distribution in the depo
 oratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristic
eability layer only modestly. In communicating layers sweep efficiency is improved significantly due to cross flow. In stochastic random perm


 herefore if injection pressure is limited increasing mobility near the injection well has a large impact on Q with a direct benefit in delaying g
ods single-well tests and field-scale simulations; and gives insight into the reservoir engineering of low-salinity floods. The model represent
was assessed with DSTs and PLTs. Fracture models were built with forward modeling algorithms using Shell’s fracture modeling softwa
tion that not only validates empirical models but can be deployed to optimize CSS designs for full field development. Detailed geological mo


an impractical number of grid blocks for large full field models with many and complex wells. We have developed practical solutions for acc
 to evaluate the “best method of stimulation because as many as twenty-two separate stimulation treatments are placed in up to 70 disc
 ng and to characterize the gas bearing reservoirs. �Production logs are also run to determine the effectiveness of the hydraulic fracturing
 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
e in waterfloods: shortcut of injector and producer fracture containment reservoir sweep. We also demonstrate that induced fracture dimens
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


 0-100 mD permeability. The upper zones contribute 10-20% of the production from thin intervals with 12-15% porosity and 2-5 mD permeab
eaming strategy for each distinct reservoir area by deploying previously improved and history matched simulation models1. A full field static m


n models were designed. Next we looked upon the development plan by performing a second round of design of experiment runs with unco




pletion occurs either at the crest for a small gas-cap reservoir or at the GOC inducing reverse cone for reservoirs with thick-gas columns. A
 or water blocking thus avoiding slow well clean-up and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. This
or every well-placement scenario; (c) The optimization process has to be repeated for a variety of geologic realizations; (d) Presence of comp
n impermeable seal. The effect of a higher permeability fault with orientation perpendicular to the horizontal well and bounded by the imperm
n impermeable seal. The effect of a higher permeability fault with orientation perpendicular to the horizontal well and bounded by the imperm
sitivity of CO2 distribution in the deposit with respect to critical CO2 saturations during the injection period and to residual CO2 saturation for
 and to assess the burn characteristics of the crude/reservoir rock system.� The ensuing estimation of the potential incremental recovery f
 oss flow. In stochastic random permeability field foam injection increases the liquid recovery by a factor of two in comparison to gas injectio


 Q with a direct benefit in delaying gravity segregation. There is also a relatively small increase in gravity segregation in the near-well region
 salinity floods. The model represents low-salinity flooding using salinity-dependent oil/water relative permeability functions resulting from we
Shell’s fracture modeling software (SVS Fracture-Solution). They are based on fracture characterization that integrates the well data with
evelopment. Detailed geological models were created over two pad areas providing a geological framework large enough to have realistic b


 developed practical solutions for accurately representing both flowing and shut-in performance of hydraulically fractured vertical wells and m
reatments are placed in up to 70 discrete sand intervals over a gross interval up to 6 000 feet thick. Evaluations are further complicated by v
ectiveness of the hydraulic fracturing and to identify water entry points that may lead to premature completion failures. Typical wells produce
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
onstrate that induced fracture dimensions can be very sensitive to typical reservoir engineering parameters such as fluid mobility mobility ra
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


2-15% porosity and 2-5 mD permeability. A two stage design of experiments (DoE) based workflow was used to evaluate and optimize prima
 mulation models1. A full field static model was built comprising over 400 wells. More detailed static sector models were also built for each d


 design of experiment runs with uncontrollable uncertainties and decisions as factors. The goal was to validate that the previously selected m




 reservoirs with thick-gas columns. Alternatively one can skip the initial oil completion where gas disposition is a nonissue. Gravity-stable flo
 hibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on w
 ic realizations; (d) Presence of complex sub-seismic geologic architecture may render workflows that solely rely on seismic data obsolete. W
tal well and bounded by the impermeable overburden was evaluated. The impact on mineralogical and rock property changes in the saline
tal well and bounded by the impermeable overburden was evaluated. The impact on mineralogical and rock property changes in the saline
od and to residual CO2 saturation for water reentering CO2 filled volumes (hysteresis in fluid saturations). The re-distribution of water occur
f the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical mode
 of two in comparison to gas injection. Introduction Foam is an excellent mobility control agent for Enhanced Oil Recovery (EOR) processe


y segregation in the near-well region. An analytical model for gravity segregation in homogeneous reservoirs can be extended to a case whe
meability functions resulting from wettability change. This is similar to other EOR modeling and conventional fractional-flow theory can be ad
ation that integrates the well data with 3D seismic field kinematic structural evolution and the regional understanding established by Petroleu
work large enough to have realistic boundary conditions including impact of surrounding wells. The geological models were imported into CM


ulically fractured vertical wells and multiply fractured horizontal wells in full-field models. We have validated these approximations in trials with
 luations are further complicated by variation in permeability exceeding two orders of magnitude and pore pressures increasing from 0.44 ps
etion failures. Typical wells produce relatively small amounts of water usually less than 5 percent by volume. It is nearly impossible to detec
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
ers such as fluid mobility mobility ratio 3D saturation distribution (in particular shockfront position) positions of wells (producers injectors)
 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


 used to evaluate and optimize primary reservoir development. Reservoir uncertainties affecting volume and connectivity were assessed in th
ctor models were also built for each distinct geological area and translated into elements of symmetry thermal simulation models. The choice


validate that the previously selected models reasonably represented P10 P50 and P90 oil recoveries and net present value after including




sition is a nonissue. Gravity-stable flooding is required to maximize reserves. Extensive flow simulations in multiple history-matched models
hibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the impa
olely rely on seismic data obsolete. We developed an adjoint-based optimization algorithm that rapidly identifies alternative optimal well-place
d rock property changes in the saline aquifer during injection has been assessed. The simulations found that: (1) the higher permeability fault
d rock property changes in the saline aquifer during injection has been assessed. The simulations found that: (1) the higher permeability fault
 s). The re-distribution of water occurs after stop of CO2 injection due to gravity segregation of dense CO2 saturated water and CO2-free wa
quires fit-for-purpose numerical modeling.� Typically the flue gas generated in-situ by combustion leads to in an immiscible gas drive whe
anced Oil Recovery (EOR) processes such as gas (nitrogen carbon dioxide etc.) or steam injection [1-8]. Due to its unique microstructure


voirs can be extended to a case where permeability is stimulated within a cylindrical region inside a larger cylindrical reservoir. The effect of t
tional fractional-flow theory can be adapted to describe the process in 1D for secondary and tertiary low-salinity waterflooding. This simple an
nderstanding established by Petroleum Development Oman’s (PDO) long-term activities in the area. This integration makes the fracture
logical models were imported into CMG’s STARS thermal reservoir simulator and a relatively fine grid was extended over each project a


 ed these approximations in trials with actual field examples. We found it necessary to enable wellbore cross-flow in the simulator for coarse
 re pressures increasing from 0.44 psi/ft to 0.83 psi/ft. The analysis of “tight gas reservoirs has been the topic of many SPE papers ove
 ume. It is nearly impossible to detect such small watercuts with conventional methods of production analysis. However a probabilistic produ
 . 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
 itions of wells (producers injectors) and geological details (e.g. flow baffles). The results presented in this paper are expected to also apply
 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


 and connectivity were assessed in the first stage of the workflow. The second stage of the workflow focused on dynamic uncertainties. The
ermal simulation models. The choice of design parameters and handling of uncertainties were addressed in a phased manner. First the sm


nd net present value after including decisions in the design. The validation worked out properly reinforcing the confidence in the model sele




 in multiple history-matched models have shown that the proposed strategy improves recovery significantly. Two field examples are present
d a recent model to simulate the impact of a surfactant on improved inhibitor retention which used data derived from laboratory experiments.
entifies alternative optimal well-placement scenarios for a given geologic realization. Adjoint-based gradients approximate the sensitivities of
that: (1) the higher permeability fault acts as a CO2 conduit; (2) a dryout zone is d
that: (1) the higher permeability fault acts as a CO2 conduit; (2) a dryout zone is d
O2 saturated water and CO2-free water. The impact of various
ds to in an immiscible gas drive where the stripping of
8]. Due to its unique microstructure foam dramatically re


er cylindrical reservoir. The effect of this stimul
 salinity waterflooding. This simple analysis shows that
. This integration makes the fracture models more realistic than purely stochasti
 rid was extended over each project area. All available historical pr


cross-flow in the simulator for coarse grid field
n the topic of many SPE papers over the past twenty years.�Sever
alysis. However a probabilistic production analysis method si
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
his paper are expected to also apply to (part
s using dynamic simulation with a coupled surface
em (Electrical Submersible Pump ESP) through a network simul


used on dynamic uncertainties. The results of the workflow defined the P10 P50 a
ed in a phased manner. First the smallest possible element of symmetr


ing the confidence in the model selection. Finally the polynomial




 ntly. Two field examples are presented to demonstrate t
derived from laboratory experiments. The focus of this p
ients approximate the sensitivities of a suitable objective function with r

				
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