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									Advances In Unconventional Gas
  Solutions to meet growing gas demand worldwide.




                 A publication of Hart Energy Publishing
                                                                                                                                                                     Overview
        A publication of Hart Energy Publishing




         1616 S. Voss, Suite 1000
        Houston, Texas 77057-2627
              713-993-9320
           Fax: 713-840-8585
           www.hartenergy.com
                                                           Tight Sand, Shale, Coal
                                                           As contribution grows, low-permeability reservoirs face common challenges.
                   Editor in Chief
                     BILL PIKE                             By John Kennedy, Contributing Editor



                                                           D
                                                                 emand for natural gas will continue to grow at a faster pace than that for oil because
         Director of Custom Publishing                           it is a cleaner fuel. Though global conventional gas reserves are significant, the cost
              MONIQUE A. BARBEE                                  of moving gas from large sources to large markets still makes it, to some extent, a
                                                           regional fuel.
                Contributing Editor
                                                             The United States and Canada are two regions facing a growing gap between natural gas
                 JOHN KENNEDY
                                                           demand and conventional supply. Development of unconventional gas resources is most
                                                           advanced in North America, where it has the potential to help fill that gap.
                    Art Director                             Fully exploiting the potential of unconventional gas resources will depend heavily
                  ALEXA SANDERS                            on the application of advancing technology and new strategies.
                                                             A 2003 U.S. National Petroleum Council (NPC) study concluded that of the total gas
                 Graphic Designer                          resource in North America of 1,969 Tcf about 20% is contained in shale, low-permeability
                  JAMES GRANT                              sands and coal seams. The study estimated recoverable reserves from tight gas sands at 175
                                                           Tcf, coal seams at 148 Tcf and gas shales at 51 Tcf.
               Production Manager                            According to the U.S. Energy Information Administration’s (EIA) Annual Energy
                 JO LYNNE POOL
                                                           Outlook 2006, the contiguous U.S. states’ non-associated onshore conventional gas pro-
                                                           duction will fall from 4.8 Tcf in 2004 to 4.2 Tcf in 2030; associated dissolved natural gas
      For additional copies of this publication,
                                                           reserves will slip during the period from 2.4 Tcf in 2004 to 2.3 Tcf.
   contact Customer Service at (713) 260-6442.
                                                           TABLE OF CONTENTS
      Group Publisher, Newsletter Division
                 DAVID GIVENS                              Coalbed Methane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
                                                           Water and fine-tuning technology to each zone are challenges for coalbed methane.
             Regional Sales Manager
                   Mitch Duffy
                                                           Effective Multizone Stimulation and Controlling Fines . . . . 9
        Corporate Director of Marketing                    Keys to successful coalbed-methane production.
                 JEFF MILLER



                  Group Publisher
                                                           Low-permeability Gas Sands . . . . . . . . . . . . . . . . . . . . . . . . . . 12
                   RUSSELL LAAS                            Precisely placed wellbores and tailored stimulation are keys to success.

Hart Energy Publishing,                               LP
                                                           Technologies Optimize Tight Gas Sands . . . . . . . . . . . . . . . . 17
              Sr. Vice President and                       Fracture face damage control, accurate fracture placement and reliable tools help get the most from tight gas sands.
              Chief Financial Officer
                 KEVIN F. HIGGINS

             Executive Vice President
                                                           Gas Shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
              FREDERICK L. POTTER                          Better 3-D interpretation, tighter spacing and more efficient drilling are needed.

                  President and
              Chief Executive Officer                      Developing Gas Shale Reserves . . . . . . . . . . . . . . . . . . . . . . . . 26
               RICHARD A. EICHLER
                                                           Lifecycle-based approach works best for gas shale reserve development.
     About the cover: Halliburton fracture
 stimulated Devon Energy's Haygood No. 11H
  near Carthage, Texas. (Photo courtesy of Halliburton)    Advances In Unconventional Gas • www.hartenergy.com                                                               1
Overview




Devon’s Bridgeport natural gas processing plant is one of the largest in the country, serving hundreds of gas wells in the rapidly expanding Barnett Shale field in north Texas.
(Photo courtesy of Devon Energy)


   However, the EIA expects production                         more critical to economic success.                               • reservoir characterization and
of the Lower 48’s onshore unconven-                               The defining characteristic of                                   imaging;
tional resources to increase from 7.5 Tcf                      unconventional gas reservoirs – low                              • stimulation;
in 2004 to 9.5 Tcf in 2030, when it will                       permeability – makes effective stimula-                          • resource assessment;
represent about half of that total for the                     tion and a large number of precisely                             • data mining;
same area’s production. The largest                            placed wellbores keys to commercial                              • producibility models;
share of that unconventional production                        production and recovery.                                         • produced water handling;
will come from low-permeability sands.                            Though there are technologies                                 • extending well life;
                                                               more critical to one unconventional                              • drilling cost reduction;
Common Technology Needs                                        resource than others, the common                                 • horizontal well completion; and
Gas from shale, low-permeability sands                         characteristic of low permeability                               • expert systems.
and coal seams each offers a large,                            means many technology needs are                                  If one of these is most important, it
onshore resource target to multiple                            common to all.                                                 is reservoir characterization, Perry
players. These tempting targets also                              In a presentation at the Hart                               said. Determining how much gas is
pose special challenges.                                       Unconventional Gas Conference in                               available and at what depth as well as
  Unconventional gas reservoirs are                            March, Kent Perry, director of explo-                          accurately defining the reservoir
found in heterogeneous, complex and                            ration and production research with                            parameters are the foundation of a
often poorly understood geologic sys-                          the Gas Technology Institute, listed                           sound development strategy.
tems. Understanding those systems is                           10 areas where improvement is needed                             There is still much that is not known
more difficult than understanding many                         to fully develop the potential of                              geologically, said Perry. “There are still a
conventional reservoirs and arguably                           unconventional gas:                                            lot of unanswered questions about the

2                                                                                                                                                  www.hartenergy.com • January 2007
                                                                                                                                   Overview




size of these resources.
   “Reservoir characterization is proba-
bly most critical in the case of gas shale.                      “Unconventional gas
Coal seams might be considered the
next most important in this regard.                         development is a game of cost.
More is known about tight gas sands
because they are the largest unconven-                    You have to figure out what spacing
tional gas resource and have been studied
for some time.
                                                              to drill on and then how to
   Some significant trends are under
way, Perry said, including a shift “from
                                                                 cut your cost to drill.”
horsepower to precision” in stimulation,                                                                  Keith Hutton, XTO President
significant reductions in drilling costs
and the implementation of new devel-
opment strategies.
   The NPC report notes that as more             Texas, the Piceance Basin and else-             opers is long. Some have a narrow
unconventional gas resources are devel-          where; in the Barnett Shale in the Fort         regional focus, others are pursuing a
oped, the average permeability of the            Worth Basin; and in Powder River                variety of low-permeability reservoirs.
producing reservoirs will continue to            Basin coalbed methane development.
decrease, requiring the industry to                 XTO’s two big tight gas plays are            Think In New Ways
apply new technologies and best prac-            the Freestone Trend in Texas and the            “Unconventional gas development is a
tices that enable wells to produce at            Piceance Basin in Colorado.                     game of cost,” Hutton said. “You have to
economic rates.                                     “Freestone is one of the major driv-         figure out what spacing to drill on and
   The industry will be challenged to            ers of our growth,” said XTO                    then how to cut your cost to drill.”
find methods to locate “sweet spots”             President Keith Hutton.                            Developers often face special envi-
in tight basin-centered gas fields,                 The company entered the Barnett in           ronmental and regulatory challenges
shale gas and coalbed methane reser-             2004, and with an acquisition and               because of the need to drill many wells
voirs to reduce the number of margin-            expansion, became the second largest            or dispose of large volumes of water.
ally commercial wells being complet-             producer in the play.The company also has          It will take new ideas across a range of
ed, according to the report.                     a significant position in other shale basins.   technologies to develop the remaining
   In the United States, some help in               Its coalbed methane focus is on the          potential of gas shales, low-permeability
pursuing the research and develop-               Rocky Mountain region where per-                sands and coal seams.
ment needed to boost unconventional              well rates and reserves are “much bet-             The Fruitland coalbeds and the
gas production will come from the                ter” than in other coalbed methane              Barnett Shale were not new places
Energy Policy Act of 2005. It pro-               plays, Hutton said. The company                 when they finally were targeted for
vides research funds of $50 million              entered San Juan in 1997, Raton in              development. They had been drilled
annually for 10 years, and specifies             2002, and the Powder River and                  through many times as operators
that unconventional gas research will            Uintah basins in 2004.                          looked for less complicated sandstone
get $16.2 million.                                  Devon Energy Corp. is an aggressive          reservoirs above and below.
   Industry’s traditional technology             developer of coalbed methane and                   But, said Brad Foster, Devon’s vice
providers will perform most of the               shale gas. Its San Juan Basin success           president and general manager for the
development.                                     led Devon to other coalbed reservoirs.          central division, during the conference,
                                                 The company also helped the Barnett             “as University of Tulsa Petroleum
Two Diversified Developers                       shale become such a successful play             Geology professor Parke A. Dickey said
Some operators are focused on one                that it fueled interest by other operators      in 1958, ‘sometimes, all it takes to rein-
resource – gas shale, tight sand or              and spurred exploration and develop-            vigorate an old place is a new idea.’”
coalbed methane. Other companies                 ment of other shale formations across              Four things make unconventional
have developed large acreage posi-               North America.                                  gas plays work, he said:
tions and are aggressively developing               Since 2002, when Devon boosted its              • knowledge and expertise;
more than one of these plays, some-              position there by acquiring Mitchell               • technology and technology transfer;
times all three.                                 Energy Corp., the company’s Barnett                • time to think and develop a strategy;
   XTO Energy Inc., for example, is              Shale production has doubled.                        and
active in tight sand reservoirs in East             The list of unconventional gas devel-           • a healthy natural gas price.

Advances In Unconventional Gas • www.hartenergy.com                                                                                       3
Introduction - Coalbed Methane




Coalbed Methane
Water and fine-tuning technology to each zone are challenges for coalbed methane.
By John Kennedy, Contributing Editor



C
      oal is the world’s most abundant
      hydrocarbon energy source.
      Volumes of methane-rich gas were
generated and trapped when it was
formed from plant material.
   Until recent decades, this gas was
known only as a hazard for underground
coal miners. Now seen as a significant
energy source in many parts of the
world, development is most advanced in
North America.
   However, even there, serious exploita-
tion of gas in coal seams is barely 20
years old and much of the resource
remains undeveloped. Significant coal
reserves extend from the northern
reaches of Canada’s Great Plains Coal
Region in northern Alberta to the
southern extent of the Gulf Coast Coal       Devon drills in the Big George coal formation in the Powder River Basin.   (Photo courtesy Devon Energy Corp.)
Region at the tip of Texas. More coal
deposits are strung back northeast           large and small companies. Outside the                         addition, Alaska may have recoverable
through the Black Warrior Basin to the       United States, those involved in CBM                           reserves of 57 Tcf from its total in-place
upper end of the Appalachian Basin in        projects tend to be major international                        resource of 1,045 Tcf.
western Pennsylvania.                        companies with the resources needed to                            Coalbed methane continues to be a
   Exploration costs are low, and            get development moving.                                        significant source of gas in the United
improved dewatering techniques, hori-           Section 29 tax credit incentives played                     States, though production has reached
zontal wells with multi-seam comple-         a key role in the major companies’ shift                       somewhat of a plateau, said Vello
tions and better control of fines have       to natural gas in the 1990s and in estab-                      Kuuskraa, president of Advanced
fueled coalbed methane’s (CBM)               lishing significant CBM production in                          Resources International (ARI).
growth development.                          the United States. Between 1990 and                                “It is good to see that CBM produc-
   Despite the technical, economic and       1999, the companies using the credit                           tion in the San Juan Basin continues to
environmental challenges that remain,        increased their U.S. natural gas produc-                       defy its expected demise,” Kuuskraa
CBM reserves offer:                          tion by 26%, while other majors reduced                        said. “The real hope is to make deeper,
   • low drilling costs, shallow depths;     their production by 14%.                                       lower permeability coals productive and
   • long life reserves, low decline rates      During that period, growth in CBM                           economic, such as those in the Green
     and good production rates;              production accounted for 57% of the                            River Basin and in the Piceance Basin.
   • large areas to explore, including       overall growth in U.S. natural gas pro-                        And advanced multi-seam completion
     bypassed opportunities; and             duction, according to the U.S. Energy                          technology for the thin multilayer mid-
   • advancing technology that can           Information Administration (EIA).                              continent coals and the extensive
     bring success in plays that failed         The Gas Technology Institute (GTI)                          Powder River coals is needed.
     earlier.                                estimates total CBM resource in the                               “If those technology barriers could
                                             continental U.S. to be 703 Tcf.                                be overcome there could be a second
Still Much Potential                         Recoverable reserves are estimated at 63                       round of growth, but these are signif-
The growing club of coalbed methane          Tcf from known resources, plus 110 Tcf                         icant barriers.”
producers in the United States includes      from as-yet undiscovered resources. In                            Coalbed methane reserves in the

4                                                                                                                                   www.hartenergy.com • January 2007
                                                                                                              Introduction - Coalbed Methane




United States grew five-fold during 15             “As the impact of CBM development          San Juan Players
years, from 3.6 Tcf in 1989 to 18.3 Tcf in       on the province’s water resources is eval-   “The San Juan Basin dwarfs every-
2004, according to the EIA, accounting           uated, we may see the Ardley begin to        thing” in CBM development, said
for almost 10% of U.S. dry natural gas           be developed,” said Michael Gatens,          Keith Hutton, president of XTO
reserves. Production in the United States        chairman of the board for Quicksilver        Energy Inc. “It has the best wells and
has grown steadily, too, from 91 Bcf in          Resources Canada Inc. “That success          the best economics.”
1989 to 1,720 Bcf in 2004, providing             will grow over the next 2 to 5 years.”          Active primarily in the Rocky
about 9% of U.S. dry gas production.               Other targets in Alberta also have         Mountain region because per-well rates
  Together, Colorado and New Mexico,             potential, said Gatens, including those      and reserves are “much better,” XTO’s
home of the San Juan Basin, account for          down south along the Crows Nest Pass         CBM production was about 160
about 60% of proved U.S. CBM                     area; in the traditional coal-mining         MMcf/d in September, a rate it expects
reserves and production.                         areas in the north; in northeast British     to double in the next 2 to 3 years. XTO
  Fruitland coals alone, the San Juan            Columbia; even in Nova Scotia.               first entered the San Juan Basin in 1997
Basin’s most prolific reservoir, could                                                        and CBM production in the San Juan,
contain between 50 Tcf and 100 Tcf               China and Russia                             Uinta and Power River basins now
of coal gas in place, said Barbara               China is the largest consumer and pro-       accounts for about 12% of the compa-
Wickman, Southern Ute Indian Tribe,              ducer of coal in the world, according to     ny’s production.
Red Willow Production Co. at the                 the EIA. BP, Chevron and others are             Economics can be good for CBM
Hart Unconventional Gas Conference               developing CBM production in cooper-         even with the 2-year dewatering period,
last March.                                      ation with China United Coalbed              Hutton said. The wells XTO is drilling
                                                 Methane Corp. (CUCM), which will             in San Juan toward the outer edge of
Just Beginning                                   participate in a number of ventures in       the basin average 1 Bcf of reserves and
According to the Canadian Society of             northern, northwestern and northeast         cost between $400,000 and 500,000 to
Unconventional Gas (CSUG), more                  areas of China, according to a report by     drill. That compares with Raton Basin
than 3,000 CBM wells were drilled in             news agency Xinhua.                          wells at $500,000 to 700,000 to drill,
2005 and 3,500 more were planned for               According to the report, a spokesman       also with 1 Bcf of reserves. In Uintah,
last year. Production was forecast to            for the corporation indicated it has 26      wells cost between $700,000 and $1
reach 700 MMcf/d by this year. The               contracts for CBM exploitation with          million to drill and typically have
EIA recently cited predictions that              foreign companies. The spokesman said        reserves of 1.5 Bcf.
Canadian CBM production could aver-              CUCM produced 20 million cu m in                Powder River Basin is the cheapest at
age more than 1,400 MMcf/d by 2010.              2005, and output was expected to hit         $150,000 per well and reserves of 500
   Most of Canada’s CBM potential –              150 million cu m last year. In 2005,         MMcf per well, Hutton said.
and current activity – is in Alberta,            there were 330 CBM wells completed,             Marathon Oil Corp. holds 390,000
where estimates put in-place reserves at         more than the total of the previous          net acres in the Wyoming portion of
700 Tcf. An additional 80 Tcf is expect-         decade, he said.                             the basin. In mid-2005, it operated
ed to be in place in British Columbia.             Russia, too, has large coal reserves. A    3,100 coalbed natural gas wells.
Recoverable reserves, again mostly in            report by L.A. Puchcov, S.V. Slastunov       Average net daily production was 69
Alberta, could be 75 Tcf.                        and G.G. Karkashadze of the Moscow           MMcf/d during 2004.
   In Alberta, where multiple coals              State Mining University estimates the           The Williams Cos. Inc. also is active
underlie half of the province, according         methane resource of Russian coal basins      in the San Juan Basin, operating more
to CSUG, early activity is centered on:          at 49 trillion cu m, including Kuzbass,      than 3,300 wells producing about 225
   • Horseshoe Canyon coals, the most            13.085; Pechora, 1.942; Eastern Donbass,     MMcf/d.
     mature development, with a 66-Tcf           0.097; South Yakutia, 0.920; Ziryansk,          According to ConocoPhillips, as of
     resource and current production of          0.099; Tunguska, 20.0; Lensk, 6.0; and       March 31, the bulk of its CBM produc-
     about 450 MMcf/d;                           Taymir, 5.5.                                 tion was from the Fruitland Coal where
   • Mannville coals, possibly a 300-Tcf           According to the report, the               net gas production averaged 470
     resource, where the first commer-           Vorkutinskaya, Severnaya, Komsomolskaya      MMcf/d in 2005. The company has an
     cial projects are under way and hor-        and Zapaliarnaya mines in the                ongoing program to drill new wells,
     izontal wells are encouraging; and          Pechora coal basin have the highest          work over existing wells, add compres-
   • Ardley coals, with an estimated             methane content, with 380 million cu m,      sion and install artificial lift.
     53 Tcf in place, where there is             362 million cu m, 292 million cu m              Anadarko Petroleum Corp. operates
     little current production but               and 298 million cu m per square km,          multiple full-scale CBM properties as well
     active evaluation.                          respectively.                                as active pilot programs and continues to

Advances In Unconventional Gas • www.hartenergy.com                                                                                       5
Introduction - Coalbed Methane




                                                                                                                              In Appalachia, Range Resources
                                                                                                                           Corp.’s CBM now covers about 400,000
                                                                                                                           acres and production has reached 20
                                                                                                                           MMcfe/d. At the end of 2005, about
                                                                                                                           1,000 CBM wells had been drilled, with
                                                                                                                           3,000 remaining in inventory. Success
                                                                                                                           with an infill-drilling pilot in the Nora
                                                                                                                           field in Virginia could significantly
                                                                                                                           boost the number of undrilled locations,
                                                                                                                           according to the company.

                                                                                                                           Coast to Coast in Canada
                                                                                                                           Quicksilver Resources Canada established
                                                                                                                           the Horseshoe Canyon play, the first com-
                                                                                                                           mercial Canadian CBM production, in
                                                                                                                           2001. Half way through last year, “We’re
                                                                                                                           on schedule with our Horseshoe Canyon
                                                                                                                           development drilling and in maintaining
                                                                                                                           production,” Gatens said.
                                                                                                                              By third quarter, the production
Fenced off wellhead is tied in for production. (Photo from Canadian Society for Unconventional Gas courtesy MGV Energy.)   decline had been offset with new pro-
                                                                                                                           duction, and an increase of 15% was
evaluate new CBM exploration oppor-                                  Bcfe of proved reserves, according to                 expected by year-end. Quicksilver-
tunities across the Rocky Mountain                                   the company.                                          operated properties now produce
region, according to the company. In                                   Nance Petroleum Corp. has an active                 about 90 MMcf/d to 100 MMcf/d,
mid-2006, it was focused on the Big                                  coalbed gas development program                       most coming from Horseshoe Canyon
George coal at the company’s County                                  under way in the Hanging Woman                        coal seams and associated sands; the
Line property and the Atlantic Rim                                   Basin, a sub-basin in the northern                    company’s net is about 50 MMcf/d to
field in Wyoming, and the Helper and                                 Power River Basin on the Wyoming-                     55 MMcf/d.
Drunkard’s Wash fields in Utah.                                      Montana state line.                                      Most of Quicksilver’s budget for last
   In the second quarter, Anadarko’s                                                                                       year is for Horseshoe Canyon, but it is
gross production reached 145 MMcf/d,                                 Beyond San Juan                                       during this time that major new facili-
compared with 131 MMcf/d in the first                                Black Warrior Basin extends from                      ties construction will be needed, Gatens
quarter, primarily because of dewatering                             Alabama into northeastern Mississippi                 said. Now, the focus will be primarily on
of the Big George coals in the County                                and contains Lower Pennsylvanian                      development drilling and well tie-in.
Line field. Its Atlantic Rim develop-                                coals. Oil and Gas Investor’s “Alabama                   Quicksilver is in the process of evalu-
ment had sales of 5.9 MMcf/d during                                  Hat Trick,” which appeared in last                    ating the few horizontal wells it has
the quarter.                                                         March’s issue, reported that “since                   drilled in Manville and is continuing to
   The company also has completed the                                1994, Black Warrior CBM wells have                    evaluate older vertical pilot wells.
Powder River Basin Water Pipeline to                                 consistently produced in the vicinity of                 In late 2005, Trident Exploration
transport produced water from CBM                                    310 MMcf/d and 325 MMcf/d of gas,                     Corp. announced plans for commer-
wells to the Madison aquifer at Salt                                 combined. Operators have been able to                 cial development of the Corbett
Creek. The line will reduce water-han-                               pull off this decline-busting feat                    Mannville CBM joint venture, expect-
dling expenses and establishes a pre-                                through steady drilling, adding hun-                  ing to reach a production of 150
dictable cost structure for future water                             dreds of wells a year at average costs of             MMcf/d by 2011. Trident is a joint
handling, according to Anadarko. The                                 around $350,000 each and recoveries                   venture between Nexen Inc. and Red
48-mile (77-km) 24-in. line will handle                              of up to 400 MMcf of gas each.”                       Willow Exploration Co.
between 400,000 b/d and 450,000 b/d                                    Dominion Exploration & Production                      On the other side of the continent,
of water.                                                            Inc. entered the Black Warrior in 1993                Stealth Ventures Ltd.’s CBM project in
   Bill Barrett Corp. is also targeting                              and early last year was producing a gross             the Stellarton sub-basin in Pictou
the Big George. At the end of 2005,                                  60 MMcf/d, according to Oil and Gas                   County, Nova Scotia, contains an esti-
it had 53,040 net undeveloped acres,                                 Investor. By then it had drilled 1,000                mated 500 Bcf of natural gas in place in
20 MMcfe/d net production and 26                                     wells in the play.                                    coal seams at depths between 1,313ft

6                                                                                                                                         www.hartenergy.com • January 2007
                                                                                                               Introduction - Coalbed Methane




and 3,937ft (400m and 1,200m).                   decreases and gas desorbs from the coal.      More Deliverability, Less Cost
Individual seam thicknesses range from           Once desorbed, the gas moves into and         The first CBM projects were devel-
3ft to 10ft (1m to 3m) and total net coal        through fracture networks to wells.           oped with fracture-stimulated verti-
thickness is as much as 394ft (120m.)               Gas content generally increases by         cal wells. Then expansions began to
The coals have gas contents in the test-         coal type as well as with coal bed depth      be drilled with horizontal wells and
ed coals between 100 scf per ton to 330          and reservoir pressure; the deeper the        from multi-well pads, and completed
scf per ton, according to Stealth.               coal bed, the less water is present.          as single leg multi-seam or multilat-
  In June, Stealth began testing its                With the easiest production devel-         eral horizontal wells. In the process,
Cumberland property, installing down-            oped, CBM producers face thinner coal         the four surface locations typically
hole pumping equipment and flow                  seams, said Kent Perry, director of E&P       needed for a site evolved to a single
testing the 1,411-ft (430-m) open hole           research with the Gas Technology              surface location that could develop
at Coal Mine Brook No. 3, the first              Institute. In the past, some seams were       four sites.
completion test. The Cumberland sub-             tens of feet thick; now there are many           Equipment evolved, too. Today, for
basin is estimated to contain more than          that are between 1ft and 2ft (0.3m and        example, Quicksilver drills its wells with
1 Tcf of gas in place in coal seams at           0.6m) thick.                                  fit-for-purpose shallow gas single rigs or
depths between 2,000ft and 8,000ft                  “Fracturing is almost everything in        coiled tubing rigs.
(610m and 2,440m).                               many coal plays,” Hutton said.                   “Both are working well, and we are
                                                    Some water fracs are used, especially in   approaching an average of 1 day or less
China Projects                                   the Powder River Basin. In other areas,       per well for drilling,” Gatens said.
Chevron was the first multinational              large sand fracs are required along with         In the Horseshoe Canyon play, efforts
oil company to sign a contract with              some type of coal fines stabilization.        to reduce the surface impact of opera-
China’s CBM development firm,                       It’s also important to draw down the       tions have resulted in a well footprint
according to Chevron. The company                pressure as low as possible and dewater       that can be as small as 10ft by 10ft (3m
has interests in four onshore produc-            effectively. “Because dewatering may          by 3m), according to CSUG. In “mini-
tion-sharing contracts in the Ordos              take as much as 2 to 3 years, it does take    mal disturbance drilling,” no soil is
basin with CBM and conventional                  some staying power to play the coalbed-       stripped, and no location or built-up
natural gas potential.                           methane game,” he said.                       access road is constructed. Pipelines are
   Far East Energy Corp. is exploring               To tailor technology to the devel-         plowed in.
and developing CBM projects through              opment plan, it’s best to “let the rocks         Nitrogen fracs are typical in the
its agreements with ConocoPhillips and           talk to you,” then use both practical         Horseshoe Canyon formation where
CUCM. Far East’s China projects could            observations and science, such as             multiple seams must be stimulated and
contain between 18.3 Tcf and 24.9 Tcf            micro-seismic data and reservoir              gas flows commingled to achieve eco-
of gas in place with recovery as high as         modeling, to help establish the best          nomic production rates. Coiled tubing
50%. Shanxi has an estimated 6.55 Tcf            way to drill, complete and stimulate          units allow multiple seams to be treated
to 9.8 Tcf of recoverable CBM                    wells, Kuuskraa said.                         in a short time; individual coal seams are
resources, Enhong 1.10 Tcf and                      “Adaptation of technology to each          perforated and selectively fractured
Laochang 1.55 Tcf. Enhong and                    setting is a fundamental objective,” he       using gaseous nitrogen.
Laochang coals range between 55ft and            said. “And the more information you
62ft (17m and 19m) thick and tests               have on the reservoir, the better the         Regulators and Communities
show gas content between 200 cu ft and           adaptation.”                                  The more wells that must be drilled, the
500 cu ft of gas per ton.                           Another top priority is to continue        greater the environmental issues and
   In April, Far East began drilling its         improving horizontal well and stimula-        more important the need for a good
third horizontal well in the Shanxi              tion technologies in ways that do not         relationship among operators, landown-
Province project.                                create well damage. In many uncon-            ers and communities.
                                                 ventional gas settings, for the first 6          In the San Juan Basin, regulatory
Adapt Technology to Each Setting                 months, the well is still cleaning up         requirements are especially complex
The high porosity of coal seams allows           and may never reach its productive            because of the many agencies and gov-
them to hold a lot of gas, but low perme-        potential.                                    ernments involved, including the U.S.
ability makes getting it out a challenge.           “Past use of heavy cements, high-          Environmental Protection Agency,
Coal’s natural fractures – cleats – are filled   weight drilling fluids plus gels and poly-    Bureau of Indian Affairs and Bureau
with water that exerts pressure on the coal      mers in lower temperature settings are        of Land Management (BLM) at the
and holds gas in place. When the water is        some of the reasons that wells never          federal level, as well as state and
produced, the pressure within the fractures      cleaned up,” Kuuskraa said.                   native-American tribal governments.

Advances In Unconventional Gas • www.hartenergy.com                                                                                        7
Introduction - Coalbed Methane




   Regulatory issues include produced                                                                   Reserves, Bcf                                                      Production, Bcf
water disposal, compressor noise and air                                                                1999                              2004                              1999                             2004
quality as well as the protection of cultural   United States                                   13,229                             18,390                               1,252                            1,720
sites and ranching/farming/wildlife sur-        Alabama                                          1,060                              1,900                                 108                              121
face use. Spacing, for example, is an issue     Colorado                                         4,826                              5,787                                 432                              520
with tribes, the BLM and states.                New Mexico                                       4,080                              5,166                                 582                              528
   Water production in San Juan can             Utah                                                                                  934                                                                   82
range from 0 b/d to 1,000 b/d of water;         Wyoming                                                                             2,085                                                                  320
between 5 b/d and 200 b/d of water is           Eastern states                                                                      1,620                                                                   72
common. Some agencies oppose pits,              (Pennsylvania,
and the volumes are too large to evapo-
                                                Virginia,
rate or flow downstream, so most oper-
                                                West Virginia)
ators lay water pipe with gathering lines
                                                Western states                                                                            898                                                                  77
and inject into their own wells,
                                                (Kansas,
Wickman said.
                                                Montana,
   The regulatory environment in
                                                Oklahoma)
Canada is on a par with that in
Michigan, California or New York, said
                                                Other*                                             3,263                                                                    130
                                                Source: US Energy Information Administration. *Prior to 2000, Other States includes Kansas, Montana, Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.
Gatens, and some requirements are
quite stringent.                                U.S. Coalbed Methane Reserves and Production
   Another complication is that a typical
resident landowner does not own the             Two Looks at Technology Needs                                                           In addition, well placement in thinner
mineral rights. The Alberta govern-             In preparing its Technological Roadmap                                                  coal seams is difficult.
ment has tried to develop practices             for Unconventional Gas Resources,                                                          Another report resulted from a
that allow development of the resource          GTI’s survey of operators turned up a                                                   series of three workshops sponsored
for all taxpayers, while facilitating the       number of top priorities. Many were                                                     by the U.S. Department of Energy’s
relationship between industry and               common to all unconventional gas                                                        National Energy Technology Laboratory.
landowners, Gatens said.                        sources, but some are unique develop-                                                   Issued in November, Technology Needs for
                                                ment challenges.                                                                        U.S. Unconventional Gas Development
Carbon Dioxide Injection:                          For example, participants cited 3-D                                                  cited these major areas in which CBM
Two Benefits                                    characterization of the lateral conti-                                                  technology needs improvement:
Another feature of coal seams is their          nuity of reservoir beds, and other                                                        • multizone well completion—Improved
high affinity for carbon dioxide                reservoir properties as especially                                                          construction of fishbone well pat-
(CO 2). When coal seams with                    important for CBM operators.                                                                terns and directional control within
adsorbed methane are exposed to the             Because coal seams must be dewa-                                                            thin coal formations;
CO 2, the molecules replace the                 tered, water is a special issue with                                                      • smaller well footprint—Ability to
adsorbed methane molecules.                     CBM development. CBM producers                                                              drill and produce from small surface
   This feature is the focus of growing         would welcome downhole water sepa-                                                          locations and with greater well
attention because coal seam gas pro-            ration and injection, ways to produce                                                       spacing;
duction could be enhanced with CO2              less water and improved surface water                                                     • rapid technology transfer—Rapid
while the reservoir also serves the goal        treatment.                                                                                  dissemination of best field prac-
of CO2 sequestration.                              “It’s rare in any area to not have water                                                 tices;
   With the increasing attention to CO2,        issues, either produced water handling                                                    • produced water technology—The
there is also new interest in the use of        or a supply of fresh water for drilling                                                     ability to change produced water
CO2–based frac fluids. When used to             and completion,” Perry said. “Water                                                         from waste to resource;
stimulate a coal bed, the CO2 releases more     issues need more work and continued                                                       • improved gas recovery per well—
methane, but stays locked in the coal seam.     research.”                                                                                  More effective well stimulation
   However, the diffusion of methane-              Projects in new areas also face special                                                  techniques and new technologies;
CO2 mixtures of variable concentrations         challenges, according to the GTI report.                                                    and
in the cleat and pore systems is not fully      Coal seam permeability, which governs                                                     • technology integration/development
understood, according to GTI, and               the dewatering and degassing processes,                                                     planning—A systematic approach
more research and development on this           cannot be determined prior to drilling                                                      to field development that integrates
process are needed.                             with any degree of reliability, for example.                                                all technology.

8                                                                                                                                                                     www.hartenergy.com • January 2007
                                                                                                                                                       Coalbed Methane




Effective Multizone
Stimulation and Controlling Fines
Keys to successful coalbed-methane production.



N
      ew fracturing fluids and additives         improvement was seen in wells that                              which has been used to reverse pro-
      have been developed specifically           were in the third phase of the CBM                              duction declines in more than 1,000
      for coalbed methane (CBM) and              well lifecycle. The five phases of CBM                          CBM wells in the western United
unconventional gas reservoirs:                   wells are:                                                      States. In some cases, entire fields have
  • For cross-linked gel fracturing,               • regional resources reconnaissance;                          been treated with treatment payout
    Delta Frac® CBM has been opti-                 • local asset evaluation;                                     being as short as 9 days.
    mized for lower temperatures to                • early development;                                             The service helps remove wellbore dam-
    provide further reduction in perme-            • mature development; and                                     age and coal fines blockage with a power-
    ability damage based on regained               • declining production.                                       ful back flush and can restrict the mobility
    permeability testing.                          The wells in the study were treated                           of formation fines (coal, shales, clays).
  • HpH FoamerTM surfactant, a new               with CoalStim post-fracture service,                            The service degrades polymer left from
    foaming agent designed to reverse
    its foam character upon flowback                                                  Case            CBM Refrac 1             CBM Refrac 2             CBM Refrac 3
    has been incorporated into a new              Gas produced 9 months after                           463,747                   88,406                   72,452
    CBM foam fracturing system. This              initial stimulation (Mcf )
    system reduces the damage conven-
    tional foamers can have on produc-            Delta gas 9 months after                              179,071                  408,818                  268,294
    tion in CBM wells.                            refrac (Mcf )
  • For water fracturing, a new CBM
    system, Water FracTM CBM, has                 at $2.50 per Mcf                                   $447,677.50            $1,022,045.00              $670,735.00
    been developed incorporating a low-
    damage friction reducer. Additives            Rate of Interest of refrac                             3.37:1                   9.22:1                    5.71:1
    including GasPerm 1000TM agent                after 9 months (approximate)
    and SandWedge® enhancer pro-
                                                  Time to pay out of stimulation                        3 weeks                  3 weeks               1.33 months
    vide high-value solutions to help
                                                  treatment
    achieve ultimate well performance
    in CBM reservoirs.
  • CoalStimSM service has recently
    achieved success in primary stimu-
                                                      Monthly Gas Production, MMscf




    lation of horizontal laterals and
    use as a pre-pad and primary frac-
    turing fluid.

CoalStim Service
An operating company exploring for
and producing coalbed methane from
vertical wells in the eastern United
States has increased its anticipated 5-
year cumulative CBM production by
40%, and its estimated ultimate recovery                                                             Time on Production, Month
(EUR) by 57% in three wells selected
for a pilot study. The production                Figure 1. Production results from three San Juan Basin coalbed methane wells that were refractured using SandWedge service.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                        9
Coalbed Methane




                                                                                        stringer (Figures 2 and 3). These example
                                                                                        jobs highlight its capabilities.
                                                                                           Colorado—In southeastern Colorado,
                                                                                        CBM trapped in multiple seams has
          SandWedge service combines                                                    plagued operators for decades. Typical
                                                                                        well depth is 3,500ft (1,068m) with up
      advanced proppant coating capability                                              to 20 seams trapping gas. Until recently,
                                                                                        the most popular technique, a “velocity
      with a treatment design and proppant                                              over accuracy” approach, did not bring
                                                                                        the best results. Now, the Cobra Frac
      selection specific for each application.                                          service team is fracturing multiple
                                                                                        seams in a single day, bringing more
                                                                                        methane to market quicker and with
                                                                                        less environmental impact.
                                                                                           England—In the United Kingdom, the
                                                                                        objective was to complete an exploration
fracturing operations and helps dissolve     service resulted in an average incre-      program in multiple coal seams (10 to 14
precipitates or carbonate scales.            mental production of 66 MMcf of gas        per well) in a cost-effective and timely
   CoalStim agents initially act as “clot    with an average treatment payout of 32     manner in a highly populated area. Using
busters,” helping break apart the inter-     days, even at the low gas prices at the    the Cobra Frac technology, five wells
nal bridges and agglomerates. Then, the      time. Two-thirds of the wells treated      were completed with 53 individual frac-
agents act as “clot formers,” making coal    showed increases in production of at       ture treatments, placing 3 million lb of
particle surfaces tacky. The tacky parti-    least 7%.
cles form clots that adhere to formation
features and proppant grains away from       SandWedge Service Helps Achieve
the fluid flow paths.                        More Production Longer
   The result is a highly conductive flow    Halliburton’s SandWedge agent can
path from the coal matrix to fractures,      be a useful tool in CBM stimulation.
then to the wellbore.                        It combines advanced proppant coat-
   The thin CoalStim carrier fluid is        ing capability with a treatment design
pumped under high pressure into the          and proppant selection specific for
damaged fractures, then the well is          each application. The following case
shut-in to allow the chemical process to     history illustrates its effectiveness in
alter the surface of the fines. Finally,     rejuvenating CBM wells. Three CBM
pump pressure is released to allow fluid     wells in the San Juan Basin (Four
in the well to rush out, flushing solids     Corners area) were refractured using
out of the wellbore area.                    SandWedge service. The wells were
   Material that had previously blocked      studied in terms of the effect of
the wellbore is held immobile at the         SandWedge agent on advancing
extremes of the fracture so gas can now      dewatering and overall production.
more easily enter the wellbore.              All three wells responded significantly
   When an operator producing from a         and provided fast payouts of the
mature CBM basin implemented the             refracs. The production chart in
CoalStim process to help extend the life     Figure 1 is for well two. Notice there
of a field, a typical treatment response     is no production decline.
was a 17 1/2 % increase in gas production
rate. During the long life of a typical      Cobra Frac Service Provides
CBM well, such an increase can add up        Excellent CBM Results
to a significant increase in cash flow and   Halliburton’s Cobra Frac service is
production.                                  especially effective in CBM develop-
   Average payout for these treatments       ment. It enables efficiently stimulat-
was 9 days.                                  ing multiple zones in a single trip by     Figure 2. Cobra Frac service enables stimulating multiple
   A 30-well program using the CoalStim      straddling each individual productive      thin zones in a single trip.

10                                                                                                           www.hartenergy.com • January 2007
                                                                                                                                                       Coalbed Methane




sand accurately in all targeted seams.                                        Conventional treatment                                      Cobra Frac
   Alabama—The goal was to stimulate
                                                              Three to nine stages per well                              Four to 18 stages per well
production from three individual zones
in a 1,950-ft (595-m) CBM well. Total                         Treated down casing                                        Treated down 2 3/8-in. coiled tubing
thickness of the three formations – the                       Zones isolated with bridge plug                            Zones isolated with straddle
Mary Lee, Blue Creek and Pratt Coal                                                                                      bottomhole assembly
groups – is only 30ft (9m) and is distrib-                    Sequence: Perf/frac/set bridge plug                        Sequence: Perf every zone/frac each
uted over 800ft (244m) of wellbore.                           (two trips per zone)                                       pay with one trip in well
Production after treatment was expect-                        Average effective stimulation of                           Average effective stimulation of
ed to be 200,000 scf/d. The zones were                        net pay: 60%                                               net pay: 76%
perforated with the goal of treating
between 2-ft and 10-ft (0.6-m and 3-m)                        Higher completion cost                                      Completion cost reduced by 2%
intervals. Using 2 7/8-in. coiled tubing,                     Lower production because of less                           Increased production, though
the Cobra Frac process was used to                            effective stimulation                                      conventionally treated wells had
place 80,000 lb of proppant into the                                                                                     twice the net pay
Mary Lee and Blue Creek coal groups.                        Figure 3. Cobra Frac service compared with conventional fracturing process.
The process also broke down each set of
perforations in the Pratt Group.                            Composite Bridge Plug                                       lower zone during squeeze cementing
   Cobra Frac service could not be                          Success in CBM development depends on                       operations on land-based or offshore
applied to the Pratt Group since each                       efficient hydraulic fracturing of multiple                  rigs, in vertical or deviated wells.
perforated interval communicated with                       coal seams. The seams may be commin-                           Fas Drill bridge plugs can be set on
open perforations above and could not                       gled and fractured together or isolated to                  tubing, drillpipe or with electric wire line.
be isolated. After the Pratt Group was                      perform staged fracturing treatments.                       It can be drilled out with conventional
stimulated by placing 70,000 lb of                             Halliburton’s Fas Drill is a composite                   three-cone, PDC or junk-mill bits.
proppant down the 5 1/2-in. casing, it                      epoxy-glass fracture plug designed for                         To re-frac an old well in northwest
came in at 500,000 scf/d against 125psi                     completing multiple coal seams with                         Virginia to boost production from the
backpressure.                                               staged zonal treatments (Figure 4). It                      upper coals without damaging the P-3
                                                            provides flow back capabilities after                       coal, a Fas Drill bridge plug was set to



                                                                      Success in CBM development
                                                                 depends on efficient hydraulic fracturing
                                                                 of multiple coal seams. The seams may be
                                                                    commingled and fractured together
                                                                       or isolated to perform staged
                                                                           fracturing treatments.


                                                            treatment and reduces drill out time.                       protect the lower coal. Cobra Frac serv-
                                                               The Fas Drill bridge plug is used                        ice was used to treat the upper coals
                                                            much like a conventional permanent                          using coiled tubing. Then the Fas Drill
                                                            bridge plug and is available in standard                    plug was drilled out. After a successful
                                                            and high-pressure/high-temperature                          treatment, the well showed a sustained
Figure 4. The Fas Drill composite plug helps reduce drill   models. In addition to multizone stimu-                     production increase expected to last for
out time in multizone treatments.                           lation in coalbeds, the tool can isolate a                  several years.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                11
Introduction - Tight Gas




Low-permeability Gas Sands
Precisely placed wellbores and tailored stimulation are keys to success.
By John Kennedy, Contributing Editor



E
      xploitation of low-permeability        to nearly 0.8 Bcf/d last year, he said.       Mississippian reservoir is Ohio’s and
      sands is most advanced in the          New transportation infrastructure has         West Virginia’s Berea sandstone. More
      United States where “tight” sands      helped bring this new gas to market,          than 12,400 wells have been drilled into
are the largest unconventional gas           supporting a four-fold increase in well       the Berea in Ohio, where the sands are
resource. According to the 2003              completions during the period.                found at depths to 6,000ft (1,830m). A
National Petroleum Council study,                                                          typical well can recover up to 400
recoverable gas reserves in low-perme-       U.S. Sources                                  MMcf of gas, according to the report.
ability sands in the United States is        Half of U.S. tight sand gas production          In an area that covers parts of south-
175 Tcf.                                     comes from Texas and 30% from the             ern New York, northwest Pennsylvania
   Production from tight gas sands           Rocky Mountain region. Most of the            and eastern Ohio and Kentucky, the
averages 3.2 Tcf/year, representing          rest is produced in the Permian and           U.S. Geological Survey has estimated
about 15% of U.S. gas production,            Anadarko basins; less than 2% now             that several tens of trillions of cubic feet
according to the Gas Technology              comes from the Appalachian Basin.             of recoverable gas still remain in the
Institute (GTI). The U.S. Energy                According to last March’s special          Clinton and Medina reservoirs.
Information Administration forecasts         report, “Tight Gas,” published by Oil           In the western United States, more
tight gas production will reach 6.8          and Gas Investor, since 2000, East            than half of the tight gas resource is on
Tcf by 2025.                                 Texas gas production from unconven-           federal lands, where U.S. Bureau of
   “U.S. gas shale development has been      tional reservoirs has grown by 12.5%,         Land Management and the U.S. Forest
growing at a healthy pace, but tight gas     more than double the growth rate of           Service place significant restrictions on
is still the ‘600-pound gorilla’ of uncon-   conventional production. By the end of        development.
ventional gas resources,” said Vello         2005, tight gas plays had cumulative            The impact of those restrictions on
Kuuskraa, president of Advanced              production of 8.7 Tcf of gas, according       supply was indicated by a study ARI
Resources International. And its contri-     to the report.                                completed for the U.S. Department of
bution continues to grow.                       In East Texas and North Louisiana,         Energy (DOE). The study concluded
   “We estimate tight gas production,        tight gas sand pays include Travis Peak,      that a 10% improvement in permitting,
not including gas shale or CBM, at           Cotton Valley, “regular” Bossier (at          wildlife mapping, drilling exceptions
nearly 15 billion cu ft per day (Bcf/d)      12,000ft to 15,000ft or 3,660m and            and length of drilling season could
last year,” he said.                         4,575m) and Deep Bossier (deeper              increase the available natural gas
   The accepted definition of a tight gas    than 15,000ft).                               resource in the region by about 14 Tcf.
reservoir is one with a matrix porosity         “The really exciting new tight gas
of 10% or less and less than 0.1             play in East Texas is the Deep                Some Key Players
milliDarcy permeability.                     Bossier, which is just starting,”             About 65% of XTO Energy Inc.’s gas
   Production has come from a variety of     Kuuskraa said. “The recently drilled          production is from tight sands in the
sources, including East Texas, North         wells in this deep tight play appear to       East Texas Basin, San Juan Basin and
Louisiana, the San Juan Basin and along      have recoveries that range from 5 Bcf         Rocky Mountains, said company
the Gulf Coast. Big plays in the Rockies     to 25 Bcf per well.”                          president Keith Hutton. XTO’s two
include Green River, Wind River and             Setting aside the Deep Bossier, the        big tight gas plays are the Freestone
Piceance basins.                             average East Texas tight sand well pro-       Trend in Texas and the Piceance
   The Piceance Basin in Colorado has        duces 1 1/2 Bcf to 2 Bcf during its pro-      Basin in Colorado.
seen especially rapid growth, although       ductive life, and the top 10% of the            In the third quarter of last year, the
from a modest base, Kuuskraa said.           wells will average 5 Bcf to 6 Bcf, he said.   company was running 23 rigs in the
Extensive infill drilling and use of            Tight gas reservoirs are a significant     Freestone play and production was
multiple stimulations have contributed       share of the Appalachian Basin’s              about 570 MMcf/d. “We can increase
significantly to the increase in tight gas   remaining resource base, according to         that by 10% to 20% a year for the next 3
production from 0.2 Bcf/d 5 years ago        the Oil and Gas Investor report. A major      years,” Hutton said.

12                                                                                                        www.hartenergy.com • January 2007
                                                                                                                                  Introduction - Tight Gas




Compressor header for gas-gathering in the Freestone Trend. (Photo courtesy of XTO Energy Inc.)

   XTO’s cumulative production in the                            to drill, and recover between 3 Bcf and     added areas including West Texas,
play is about 600 Bcf and it has booked                          4 Bcf per well with initial producing       Wyoming and the Wild River field in
about 2.5 Tcf of reserves.                                       rates between 3 MMcf/d and 4                Canada. Anadarko’s net gas production
   “That puts us about half way done.                            MMcf/d. Exxon’s offset wells in the         from tight gas formations averaged
There is still probably 3 Tcf to be                              Piceance Creek unit have reportedly         521 MMcf/d in 2005, according to
added,” he said.                                                 been producing at initial rates between     the company.
   The Piceance Basin, where XTO will                            3 MMcf/d and 6 MMcf/d. Exxon and               The East Texas Bossier play, where
earn 50% of a 70,000-acre farm out                               others in the Piceance are developing on    Anadarko has been operating since the
from ExxonMobil by drilling four wells,                          20-acre spacing.                            mid-1990s, is one of its more mature
is XTO’s next big tight gas push,                                   In Southwestern Energy Co.’s Overton     tight gas plays, with more than 750
Hutton said. In early September, the                             field in East Texas, tight gas production   wells. It expects to ultimately recover
first well was being completed in the                            was only 2 MMcf/d in March 2001, but        2.4 Tcf from its 200,000 net acres and
4,000-ft (1,220-m) gas column and the                            by late 2005, the production rate was       has a 5-year drilling inventory. Net pro-
second well was under way. All four are                          about 107 MMcf/d, according to the Oil      duction in the middle of last year was
expected to be at total depth between                            and Gas Investor report.                    about 190 MMcf/d.
14,000ft and 15,000ft (4,270m and                                   Anadarko has been working to pro-           Anadarko’s Wild River/Cecilia drilling
4,575m) by the first quarter this year.                          duce natural gas from tight sands           program continues in the company’s
   “In the first well, we had good shows                         since the early 1980s. It began in the      most active development area in
and good sand,” Hutton said. “If half of                         Golden Trend of Oklahoma and                Canada. With between five and seven
XTO’s acreage is successful, net reserves                        transferred those techniques first to       zones at depths between 9,500ft and
would be about 2 Tcf.”                                           the Bossier field in East Texas then        11,000ft (2,898m and 3,355m), the
   Development wells are expected to                             to deeper zones in the Vernon field of      company had a 243-well inventory in
cost between $3 million and $4 million                           North Louisiana. Recently, it has           the middle of last year.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                   13
Introduction - Tight Gas




  With a 1.9 million-net acre leasehold       log and thus be bypassed.                         “Stimulation has evolved from horse-
position in Appalachia, Range Resources          “We just don’t have enough data on          power to precision,” said Kent Perry,
Corp. is targeting substantial reserves in    clay mineralogy, including its cation          director of exploration and production
shallow tight gas sands, as well as CBM       exchange capacity, for the important           research with GTI. In the 1960s, an
and shale gas. During first quarter last      tight gas basins,” Kuuskraa said.              experiment with nuclear stimulation
year, its Appalachian division drilled                                                       showed that technique “was not practi-
149 (106 net) wells in its tight sand-        More Skill, Less Brute Force                   cal for a lot of reasons,” he said.
stone and CBM properties. Last year,          Stimulation is the key to making tight            Hydraulic fracturing then became the
the company planned to drill or partici-      gas sand development economically              tool for developing low-permeability
pate in about 800 wells compared with         viable. The evolution of stimulation           reservoirs. In the Denver-Julesburg
600 wells in 2005.                            techniques has been driven by new tech-        Basin in Colorado, for example, the
  At the end of 2005, Range Resources’        nology and an expanding range of               strategy was to drill one well on 640-
proved reserves in Appalachia were 838        options that can be tailored to individual     acre spacing and perform a massive
Bcfe; daily net production for the year       reservoirs. More cost-effective multiple       hydraulic frac in an attempt to drain a
was about 94 MMcfe.                           stimulations in horizontal wells is an         significant portion of that rock.
                                              important objective; existing technology          Stimulating tight sand reservoirs with
Identify and Define                           works, but it is still relatively expensive.   cross-linked polymer fluids and large
The best unconventional gas strategy             “The key to tight gas plays is to figure    sand volumes often was too expensive.
depends on the type of resource and           out how to frac them,” Hutton said.            In the 1990s, the less-costly slick-water
the basin.                                    “Usually, you know the sands are there.        fracturing technique that used large
   “Each basin and resource has its           The challenge is to maximize the flow          volumes of water and low concentra-
unique set of technical challenges,”          rate for the lowest cost.”                     tions of proppant made more prospects
Kuuskraa said. “Reservoir characterization
techniques that can show ‘this part of
the basin is high in quality, while this
part is low in quality’ is the No. 1                        “Stimulation has evolved from
technology need.”
   A key part of that analysis is detecting
                                                              horsepower to precision.”
natural fractures that can connect per-                                                      Kent Perry, Director of Exploration
meability with horizontal wells.                                                                 and Production Research, GTI
   “That doesn’t always work in all
basins,” Kuuskraa said. “In some basins,
natural fractures have served as fluid
flow paths and brought minerals into             In East Texas, XTO has been using           economical. Then the development of
the matrix, reducing permeability.            water fracs since 1998. It took a while        multi-stage fracturing made it possible
   “It’s not a panacea, but it is generally   before service companies routinely rec-        to more efficiently treat several zones.
desirable to find naturally fractured         ommended this technology, but it is               As more was learned about frac-
settings.”                                    widely used now in many different basins.      tures, it became clear that the ability
   Identification of gas-bearing zones by        Water fracs make it possible to treat       to reach all the rock with 640-acre
surface seismic imaging and seismic           more stages for the same cost as treating      spacing was limited.
attribute analyses has had reasonable         one interval with a gel frac, Hutton said.        “Fractures were short and taller, and
success in conventional reservoirs but        At a cost of $100,000 for water frac and       more complex,” Perry said.
has seen limited success in tight sands.      $300,000 for a gel frac, three stages can         The key to success is to get a well-
The same holds true for identification        be treated with the water frac for the         bore into the vicinity of the rock that
of pay zones and estimation of gas satu-      cost of one gel frac.                          is to be produced. With the limited
ration by well logging and petrophysical         “Also, a large gel frac can screen out a    ability to reach out with a frac treat-
analysis techniques.                          well,” Hutton said. “It can hurt the well,     ment, the sands have to be reached
   Finding and identifying gas-filled         but a water frac will not.”                    with a wellbore instead.
porosity in formations containing                In East Texas, where the gas column            An example is the Jonah field in
large amounts of clay is still less than      is about 4,500ft (1,373m), XTO can do          Wyoming, Perry said. Spacing as low as
perfect. Depending on the nature of           as many as nine stages and still keep          10 acres per well is being considered to
the clay and its volume, those forma-         well cost about $2.5 million for wells         adequately drain the gas from that reser-
tions can look “wet” on a traditional         that average 3 Bcf of reserves.                voir. With horizontal drilling and

14                                                                                                         www.hartenergy.com • January 2007
                                                                                                                                                            Introduction - Tight Gas




Halliburton performs fracturing service on Quicksilver Resource’s well in the Barnett Shale formation. (Photo courtesy of Halliburton)

microhole wellbores, it is practical to                           reservoirs where no liquid hydrocarbon                             only a few of the open fractures, lim-
access reservoirs with small well spacing.                        saturation has been present.                                       iting flow rates.
  “We hit it with a hammer in the                                    Retention of this increased water
1960s,” he said. “Now, we are using a                             saturation in the pore system can                                  Challenges of the Deep
much lighter touch.”                                              restrict the flow of methane. Use of                               The Deep Bossier play in East Texas
  Still, hydraulic fracturing of low-per-                         water in reservoirs with low satura-                               poses special challenges, Kuuskraa
meability zones is complex. Tight gas                             tion may also reduce permeability and                              said, because it involves deep, expen-
sands have a wide geographic spread                               associated gas flow by permanently                                 sive wells drilled to depths of
and vary in depositional environments,                            increasing water saturation.                                       20,000ft (6,100m).
subsurface stress regimes and reservoir                              Another significant issue in tight                                 The “regular” Bossier and the Deep
properties. Predicting and characteriz-                           sands reservoirs is permeability reduc-                            Bossier are similar to the offshore Gulf
ing natural fractures in low-permeabili-                          tion resulting from physical and chemi-                            of Mexico “shelf ” and the “slope,” he
ty sandstones is difficult; a fracture                            cal reactions between the reservoir rock                           said. The Deep Bossier – the slope –
design that is successful in one field may                        and the drilling and fracturing fluids.                            deepens rapidly and is a “much more
not be in another.                                                   Better fracturing technology has                                complicated geological animal.”
  Introducing a water-based fractur-                              made possible increased production                                    The cost of drilling Deep Bossier
ing fluid into a low-permeability                                 from tight sands during the past two                               wells makes stimulation technology
reservoir can lower the effective frac                            decades, but several challenges                                    critical, and because of the high pressure
half-length because of phase trapping                             remain to be met, according to a GTI                               and temperature, it is necessary to use
associated with the retention of the                              report on unconventional gas technology                            fluids that will not dehydrate and prop-
water-based fluid in the formation.                               needs. For example, because hydraulic                              pants that will not be crushed, for example.
The problem is magnified by the                                   fractures normally grow parallel to the                            The treatment must be placed against
water-wet nature of most tight gas                                open natural fractures, they intersect                             an over-pressured formation.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                             15
Introduction - Tight Gas




   There have been very big wells and                                                                              Freestone                                 Barnett                               CBM
very big disappointments to date,              Depth, 1,000ft                                                     13 to 15                                  5 to 9                               2 to 4
Kuuskraa said. “Deep Bossier is an
                                               Cost, $ million                                                       2 to 3                             1.6 to 2.2                           0.4 to 0.8
emerging play that is still being defined.
It is pushing the limits of unconven-          Rate, MMcf/d or b/d of oil                                            1 to 7                                 2 to 7                           0.4 to 1.1
tional gas development,” he said.              Reserves, Bcf or million boe                                          2 to 4                                 2 to 6                           0.5 to 2.5
                                               Rate of return, %                                                 80 to 100                              50 to 100                            50 to 100
Rigs and Tools
                                               Based on Nymex prices of $8/Mcf and $50/bbl. Source: XTO Energy Inc. presentation to Hart Unconventional Gas Conference, March 2006 XTO’s unconventional gas economics
To put a wellbore near more gas accu-
mulations means more wellbores, which         XTO’s unconventional gas economics.
means cost and surface footprint rise to
the top of the list of challenges.            Niobrara in Kansas and Colorado.                                                        formation damage; and understanding
   The good news is that since each           Operators also would like to be able to                                                 the rock-fluid interaction.
accumulation is relatively small, a           use that rig to drill between 1,000ft and                                                  Important needs related to stimula-
large wellbore is not needed. So, one         1,500ft (305m and 458m) horizontally,                                                   tion and completion, though not
way to cut cost is with a fit-for-pur-        but it is difficult to get the weight on                                                described as a top priority, are:
pose coiled tubing drilling rig               the bit needed to effectively drill.                                                       • improved understanding of the nat-
designed to drill smaller holes faster          “The ability to drill horizontally with                                                    ural stress field;
with little surface disturbance.              coiled tubing is an area that needs                                                        • development of appropriate fracture
   An example of that technology,             development,” Perry said.                                                                    models;
Perry said, is a very mobile rig that                                                                                                    • improved diagnostics;
routinely drilled 3,000-ft (915-m)            Technology Priorities                                                                      • candidate selection and evaluation
wells in a single day in the Niobrara         Many of these challenges that stem                                                           of re-stimulation; and
in Colorado and Kansas.                       from the need to drill an increased                                                        • effective horizontal well stimulation.
   For this rig’s operation, no location is   number of wells are closely related:                                                       During production, the real-time
built, and usually no built-up road is           • understanding the resource, ability                                                continuous monitoring of flow rate,
needed. Only one small pit is required if           to drain the rock, designing the                                                  pressure and other parameters is
cuttings are to be buried on site, or they          best drainage patterns and spacing;                                               deemed a top priority. Also important
can be hauled away. Since most wells are         • efficient drilling; and                                                            are extending well life by re-stimulation,
drilled with fresh water, little cuttings        • minimizing the environmental                                                       more efficient water handling and a
treatment is needed.                                impact that could result from                                                     more accurate estimate pressure depletion
   A fit-for-purpose rig for unconven-              increased number of wells.                                                        and drainage volume.
tional gas development should be able            Minimizing wellbore damage is also                                                      A top priority in reservoir charac-
to handle 1 in. through 2 5/8 in. coiled      critical to the economic performance of                                                 terization for tight sands is improved
tubing, have a 5,000-ft (1,525-m) depth       unconventional gas wells. Advancing                                                     reservoir imaging for thin and deep
capability and a zero discharge mud sys-      drilling and completion technology in                                                   pays as well as natural fracture assess-
tem, according to GTI. It should also be      ways that reduce wellbore damage is one                                                 ment and prediction. Improved mod-
rated to handle 7 5/8 in. casing.             of the biggest challenges.                                                              els for calculating original gas-in-
   “As boreholes become smaller, and             Technologies exist for breaking up                                                   place and producible gas, and 3-D
the reach of the wellbore needs to be         wellbore damage, helping restore and                                                    characterization of lateral continuity
extended, a new portfolio of tools is         enhance the permeability of the per-                                                    of bed and other reservoir properties
required,” Perry said.                        forations and surrounding area,                                                         are also needed, according to the
   The DOE has its microhole drilling         including the creation of pulsating                                                     operators surveyed.
work aimed at those needs, but more needs     pressure waves within the wellbore                                                         Other top priorities include improved
to be done in developing those tools, espe-   and formation fluids.                                                                   direct imaging of thin reservoirs and depo-
cially those for formation evaluation.           According to GTI’s Technological                                                     sitional models on a play and basin scale.
   “As we continue to move away from          Roadmap for Unconventional Gas                                                          Needed in the logging/petrophysics area,
brute force toward more precision             Resources, participants in the survey of                                                according to participants in the survey, are
approaches to development, we need to         technology needs cited two high-prior-                                                  better resolution, characterization and
develop smaller tools for logging while       ity needs related to stimulation and                                                    accurate flow predictions of thin bedded
drilling, steering and data transmission.”    completion of all types of unconven-                                                    pay, natural fracture/cleat characterization
   The coiled tubing rig, for example,        tional gas reservoirs: developing best                                                  and behind pipe logging to identify
can drill vertical wells efficiently in the   practices and quantifying/preventing                                                    bypassed pays.

16                                                                                                                                                                  www.hartenergy.com • January 2007
                                                                                                                                                                Tight Gas




Technologies Optimize
Tight Gas Sands
Fracture face damage control, accurate fracture placement and reliable tools help get the most from tight gas sands.

                                                                                                                CobraMax® V Service

U
       ltra-low-permeability formations
       are especially prone to fracture                                                                         The CobraMax V service process is
       face damage because of imbibition                                                                        used for unperforated, cemented casing
of fracturing fluids. When the fractur-                                                                         completions in vertical wells (Figure 2).
ing fluid initiates and extends the frac-                                                                       The process is performed with a coiled-
ture and then carries proppant into it,                                                                         tubing-deployed Hydra-Jet™ bottom-
water is drawn into the formation,                                                                              hole assembly (BHA). There are no
sometimes several feet into the rock                                                                            packers or mechanical devices to set.
porosity. This movement of water into                                                                           Depth correlation is accomplished by
the formation is because of the capillary                                                                       setting a wireline bridge plug below the
effect and can be a significant cause of          Figure 1. Photomicrograph shows the effects of phase          deepest interval to be stimulated. The
low hydrocarbon production.                       trapping that can occur during a fracturing treatment. This   bridge plug is tagged with the coiled
   New GasPerm 1000SM service provides            process is especially pronounced with water fracs in ultra-   tubing, and the referenced depth is input
important benefits to help get production         tight gas formations. The discontinuous phase reduces the     into the depth encoders on the coil unit.
from unconventional gas reservoirs on-            gas permeability. GasPerm 1000 service has helped             The BHA is moved to the first target
line faster and at higher rates:                  enable the trapped phase such as imbibed water flow           and perforating is accomplished by
   • helps reduce damage because of               freely from the rock matrix and fracture system resulting     hydrajetting via the coil. The annulus is
      phase trapping;                             in significantly improved permeability to gas.                closed in to break down the perforations,
   • enhances mobilization of liquid                                                                            and the fracture treatment is pumped
      hydrocarbons including conden-              OptiKleen-WFTM viscosity-reducing agent
      sate;                                       In fracturing unconventional gas
   • helps increase regained permeabili-          reservoirs, friction reducers have been
      ty to gas following treatment;              shown to cause fracture face damage
   • improves load recovery;                      and have demonstrated damaging
   • GasPerm 1000™ additive can                   effects to fracture conductivity.
      replace methanol for water block            Proprietary OptiKleen-WF viscosity-
      applications; and                           reducing agent has been developed to
   • it improves environmental and                enhance fluid load recovery and
      safety performance over existing            reduce damage that can be created by
      alternatives.                               long chain polymers. It helps return
   Operators are already receiving positive       the viscosity of solutions containing
results from applying GasPerm 1000 serv-          treating agents, such as friction
ice. For example, a Cotton Valley tight gas       reducer, to that of water. It can help
sand well was fracture stimulated using           maximize the effectiveness of water-
Halliburton’s suite of products designed to       fracturing treatments by:
help improve water frac results. The                • improving load recovery and pro-
GasPerm 1000 service included a version                ductivity;
of SandWedge® enhancer especially for-              • minimizing friction-reducer polymer
mulated for water fracs and OptiKleen-                 damage;
WF™ agent. Results show more than 14                • preventing polymer adsorption to
times the wellhead pressure and almost                 the fracture face; and                                   Figure 2. CobraMax V service extends the benefits of
twice the initial production (Figure 1).            • reduces fluid viscosity.                                  coiled tubing fracturing to larger, higher rate treatments.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                      17
Tight Gas




through the annulus. The coiled tubing
is moved above the treatment interval
and then acts as a deadstring for fracture
diagnostics. A final proppant stage of
un-crosslinked, high concentration
proppant is pumped to induce a near-
wellbore proppant pack that further
improves near-wellbore conductivity
and acts as a diversion for treatments
further uphole. When all intervals have
been treated, the well is cleaned out
with the coil unit, and the well can be
jetted or flowed to recover treatment
fluid. Up to 22 individual intervals have
been fracture-stimulated in a single
completion.
   CobraMax V service was successfully
deployed in Chevron’s Lost Hills asset
with significant reduction in overall
cost/barrel of oil equivalent based on
180-day cumulative production over
conventional ‘perf-and-plug’ limited-              Figure 3. CobraMax H service successfully addresses the flow convergence issues in fractured horizontals.
entry fracturing method (37.6% higher
cumulative production reported). Since             be combined with the CobraMax H                              CobraJet Frac® Service
the initial test of the method, the                service process to deliver the highest                       The CobraJet Frac* process also uses a
process has been used on more than 40              possible sustained production from each                      coiled tubing deployed BHA (Figure 4).
of Chevron’s well completions averaging            completion.                                                  This process is similar to CobraMax
17 fracs per well with 2.2 million lb of                                                                        service in that the Hydra-Jet perforating
proppant per well in the Lost Hills                                                                             is accomplished by pumping through
alone.                                                                                                          the coiled tubing and the fracture treat-
                                                                                                                ment is pumped though the annulus. In
CobraMax® H Service                                                                                             this process, however, diversion from
The same CobraMax process used to                                                                               previously stimulated intervals down
treat vertical wells is especially benefi-                                                                      hole is accomplished using a compres-
cial for horizontal wells where flow con-                                                                       sion set packer. CobraJet Frac service
vergence from the fracture into the                                                                             offers the same dead-string advantages
wellbore can cause significant loss in                                                                          as CobraMax service. One advantage of
production (Figure 3). The proppant                                                                             Cobrajet Frac service is the time savings
pack as a final stage of each fracture                                                                          between treatments. The packer isola-
treatment helps ensure maximum con-                                                                             tion method is often quicker than the
ductivity in the near-wellbore region                                                                           process of setting proppant plugs in the
where flow convergence issues are the                                                                           wellbore and often does not require a
most extreme.                                                                                                   cleanout at the end of the completion.
   Horizontal well fractures are especial-
ly vulnerable to conductivity loss in the                                                                       RapidFrac-MZSM Service
near-wellbore area because of fines                                                                             RapidFrac-MZ* service is a multiple-
migration, proppant flowback and the                                                                            zone stimulation process that uses
limited flow area exposed by the small                                                                          select-fire perforating guns that remain
perforated interval connecting to the                                                                           in the casing while fracturing is accom-
fractures. A small amount of fines plug-                                                                        plished down the casing. A series of
ging near the perforations will create a                                                                        select-fire guns is run into the well, and
significant choke point to production.             Figure 4. CobraJet Frac service diversion is accom-          the lowermost interval is perforated
Conductivity endurance products can                plished by using a compression set packer.                   (Figure 5). The guns are then positioned

18     *Technology licensed from ExxonMobil Upstream Research Co.                                                                   www.hartenergy.com • January 2007
                                                                                                                                                   Tight Gas




                                                         Delta StimTM Sleeves                                    Reliable Well Construction
                                                         For multi-zone fracturing applications                  In many wells, unsuccessful installation
                                                         in horizontal and vertical wells, the                   of liners and failure of liner tops result
                                                         Delta Stim sleeves can be used not only                 from a variety of causes, including;
                                                         to provide an effective means of replac-                   • a lack of integrity in the liner top
                                                         ing conventional perforating and isolat-                     cement;
                                                         ing individual frac treatments, but also                   • pre-setting of the liner hanger and
                                                         can to selectively close off fractures that                  packer;
                                                         may have communicated with water                           • failure to get the liner to depth; and
                                                         producing intervals. The sleeves are typ-                  • failure of tools such as darts, plugs
                                                         ically cemented in the wellbore as part                      and running/setting tools.
                                                         of the casing string with acid soluble                     Current technology for running and
                                                         cement. Acid can be used to facilitate                  setting mechanical equipment poses
                                                         formation breakdown.                                    several risks, including multiple slips,
                                                            Delta Stim sleeves offer a distinct                  tortuous flow paths, exposed hydraulic
                                                         advantage to convention processes for                   ports, many potential leak paths and
                                                         acid fracturing treatments as well as                   reduced radial clearance.
                                                         treating reservoirs with potential for                     These risks, however, can be mini-
                                                         producing hydrogen sulfide that would                   mized – in many cases eliminated – by
                                                         complicate hydrajetting practices.                      applying new technology.
Figure 5. RapidFrac-MZ service provides speed of oper-                                                              The VersaFlex® liner hanger system,
ation and is well suited for water fracs.                Magnum Stimulation ValveTM Assembly                     for example, combines expandable
                                                         Magnum Stimulation Valve assemblies                     solid liner hanger technology as well
at the next interval uphole while the                    are run as part of the completion casing                as Halliburton’s complete range of
fracturing treatment is pumped on the                    and cemented in place between frac tar-                 cementing products and services
first interval down the casing. As a                     gets. They are full open and present no                 (Figure 7). The system expands the
final fracturing stage, ball sealers are                 restrictions inside the casing string.                  capability and enhances the reliability
injected to seal-off the first interval.                 These are flapper valves actuated                       of conventional liner installations.
When the pressure rises, indicating                      mechanically using slickline, wireline or                  The system’s heart, the VersaFlex
the first interval is sealed, the second                 coiled tubing to shift a sleeve that allows             integral liner hanger/packer, is made up
zone is perforated without shutting                      the flapper to be released to provide isola-            of an integral tieback receptacle above
down the pumps, and the second frac-                     tion of fluid flow from above (Figure 6).               or below (depending on system size) an
ture treatment is initiated while the                                                                            expandable solid hanger body. Elastomeric
guns are moved uphole to the third                                                                               elements bonded to the hanger body are
interval. Usually, only six select-fire                                                                          compressed in the annulus as the hanger
guns are run in a single run into the                                                                            body is expanded. This virtually elimi-
wellbore; therefore, the spent guns are                                                                          nates the liner hanger/casing annulus
retrieved after the sixth interval is                                                                            and provides liner top pressure integrity
stimulated.                                                                                                      as well as high tensile and compressive
   If more than six treatments are                                                                               load capacity.
required, a composite bridge plug and                                                                               The VersaFlex liner system provides:
new select-fire guns are run into the                                                                               • Simplicity—no moving parts, slips, or
well. The bridge plug is set above the                                                                                cages to suspend the liner in the sup-
sixth zone via wireline, and the seventh                                                                              port casing, eliminating the risk of
interval is perforated. The process is                                                                                pre-setting the liner hanger/packer;
repeated as before for zones seven                                                                                  • Reliability—multiple redundant
through 12, if desired.                                                                                               elastomeric elements maintain
   The process promises speed because                                                                                 pressure integrity while virtually
of the idea that there is essentially no                                                                              eliminating gas migration paths
downtime between fracture treatments.                                                                                 in the liner top;
However, premature screenouts can                                                                                   • Integrity—the reduced outer diame-
cause complications, so the process is                   Figure 6. Magnum Stimulation Valve assemblies present        ter (OD) of the hanger body allows
best suited for water fracs.                             no restrictions inside the casing string.                    for higher circulation rates during

Advances In Unconventional Gas • www.hartenergy.com                                                                                                      19
Tight Gas




                                                                                               incorrectly assembled.
                                                                                                  To avoid presetting the hanger or
                                                                                               packer by catching the slips or packer
                                                                                               elements and by the surge effect when
                                                                                               running in the hole, the system can only
                                                                                               be set by following the proper setting
                                                                                               sequence. There are no exposed
                                                                                               hydraulic ports.
                                                                                                  Anadarko Petroleum Corp. recently
                                                                                               chose the system for a 13,549-ft (4,132-
                                                                                               m) well being drilled in Madison
                                                                                               County, Texas. The liner was run in the
                                                                                               hole without any problems until it got
                                                                                               stuck at 13,386ft (4,083m). Freeing it
                                                                                               required a total pull of 465,000 lb
                                                                                               (260,000 lb over pick-up weight).
                                                                                               During pumping, the hole packed off
                                                                                               several times, creating a maximum pres-
                                                                                               sure of 4,500psi on the drillpipe.
                                                                                                  Only when the pump rate was
                                                                                               increased to 10.5 bbl/min and the liner
                                                                                               was rotated at 80 rpm with torque
                                                                                               between 8,500 ft-lb and 14,500 ft-lb
                                                                                               did the liner begin to move. It took 25
                                                                                               hours of washing and reaming to
                                                                                               achieve total depth.
                                                                                                  After setting the hanger, a 300,000-lb
                                                                                               pull test and 4,200-psi positive pressure
                                                                                               test with no pressure loss confirmed the
                                                                                               hanger was set.
                                                                                                  Anadarko representatives on location
                                                                                               were quoted as saying, “No one else’s
                                                                                               equipment could have stood up to that
                                                                                               kind of abuse and still set or tested.”
                                                                                                  Anadarko has since utilized the
                                                                                               VersaFlex liner system in several of their
                                                                                               wells.

Figure 7. VersaFlex liner hanger system running.                                               A Versatile Retrievable Packer
                                                                                               The Halliburton Versa-Set® wireline or
    cementing to improve cement                    pack off and increase equivalent circu-     tubing-set packer is a single-bore
    integrity and minimize cement                  lating density, the slick OD of the         retrievable packer ideal for medium-to
    pack-off potential;                            VersaFlex system significantly reduces      high-pressure environments (Figure 8).
  • Versatility—VersaFlex systems will             the risk of lost circulation.               It is used for testing, injection and zone
    soon be available in virtually all com-           The system also avoids a stuck setting   stimulation, and can serve as a produc-
    mon liner/casing configurations; and           tool, the most common causes of which       tion packer, temporary bridge plug or
  • Adaptability—the liner hanger/pack-            are debris entering the setting             tubing anchor in a pumping application.
    er can be combined with existing               tool/extension sleeve gap, and incorrect       The packer is a useful tool in any well
    Halliburton completion products to             tool assembly. In the VersaFlex system,     that requires it to be lubricated into the
    provide a superior liner top comple-           the liner top is completely sealed to       well under pressure with a plug in place,
    tion solution.                                 keep out fines, cuttings and other well     minimizing damage to sensitive forma-
  While hangers with slips and cones               debris. In addition, the hanger and set-    tions. It can be released, moved and re-
provide a trap for cuttings and debris to          ting tool assembly will not make up if      set mechanically on tubing. Rated at

20                                                                                                            www.hartenergy.com • January 2007
                                                                                                                                         Tight Gas




                                                 10,000psi with full-bore inner diameter
                                                 for most tubing/casing combinations, it
                                                 easily converts to wireline set or
                                                 mechanical set in the field.
                                                   An opposing slip design holds in
                                                 both directions and is operated with a
                                                 simple quarter-turn J-slot. A tempo-
                                                 rary plug may be installed at the top
                                                 of packer. Mechanically re-settable, it
                                                 has an internal bypass and emergency
                                                 shear release.

                                                 Restoring Permeability
                                                 Halliburton’s Pulsonix® service uses
                                                 alternating bursts of fluid to create pul-
                                                 sating pressure waves within the well-
                                                 bore and formation fluids. These pres-
                                                 sure waves can break up many types of
                                                 near-wellbore damage, helping restore
                                                 and enhance the permeability of the
                                                 perforations and the surrounding area.
                                                    Fluidic oscillation helps remove dam-
                                                 age instead of breaking through it,
                                                 cleaning the entire interval, not just the
                                                 open sections.
                                                    Pulsonix TF service, the next-gen-
                                                 eration process for treating near-well-
                                                 bore and perforation damage, uses
                                                 tuned frequency (TF) technology to
                                                 customize amplitudes and frequencies
                                                 for each application. The service
                                                 incorporates Halliburton’s coiled tubing
                                                 expertise with its proven fluidic oscil-      Figure 9. New Pulsonix TF tool is equipped with
                                                 lator technology (Figure 9).                  side and bottom parts for more direct impingement
                                                    Pulsonix TF service is applicable for a    on perforations.
                                                 variety of vertical and horizontal wells,
                                                 both openhole and cased hole. It per-           Side and bottom ports enable more
                                                 forms well in removing deposits – scale,      direct impingement on perforations
                                                 formation fines, paraffin, asphaltene,        than the original service and the process
                                                 emulsions and more – from the near-           can function at lower flow rates. The
                                                 wellbore area, perforations and screens.      service can be used:
                                                    It minimizes location time because it        • to enhance placement and effec-
                                                 can clean out fill and stimulate the well          tiveness of treatment fluids;
                                                 in one trip. It is not limited by stand off     • for primary stimulation of high-
                                                 requirements like jetting nozzles and              permeability formations;
                                                 can be run with other tools.                    • for preparation prior to stimulation
                                                    The technology provides signifi-                treatments, gravel packing or frac
                                                 cant advantages over the original                  packing;
                                                 service. A wider range of rates can             • to clean out fill from openhole or
                                                 better match the bottomhole assembly               casing;
                                                 and gain the benefits of flow capacity,         • to change injection profiles; and
                                                 and the amplitude is stronger for more          • for correct placement of treating
Figure 8. Versa-Set Packer                       effective action.                                  chemicals.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                21
Introduction - Gas Shale




Gas Shale
Better 3-D interpretation, tighter spacing and more efficient drilling are needed.



G
      as-in-place in shale formations in a        •   Abraxas;                                    • well depth is between 6,000ft and
      dozen U.S. basins could total               •   EnCana Corp.;                                 9,000ft (1,830m and 2,745m); and
      between 500 Tcf and 600 Tcf. Early          •   EOG Resources Inc.;                         • reserves are greater than 1 Bcf per
last year, more than 35,000 wells were            •   Devon Energy Corp.;                           well (vertical).
producing an estimated 600 Bcf per year,          •   Quicksilver Resources Inc. and others.      Midway in the third quarter of last
according to the 2006 edition of “Shale                                                        year, Devon had 26 rigs running in the
Gas,” a special Oil and Gas Investor report.    The Big One…And Why                            play, up from 18 early in the year. It was
   Production comes from shale reser-           Development of the Barnett shale,              scheduled to drill about 325 wells last
voirs in the Michigan, Illinois,                contained mainly in Wise and                   year as planned, most of which are hor-
Appalachian, San Juan and Fort                  Denton counties in North Texas,                izontal. In 2005, Devon drilled 217
Worth basins.                                   began with experimental drilling and           wells, 244 of which were horizontal.
   “Currently, the hottest play going in        completion techniques during the               Devon’s cumulative production reached
unconventional gas is pursuit of shale          1980s and early 1990s.                         1 Tcf in 2005 and by the middle of last
gas reservoirs,” said Vello Kuuskraa,              By early last year, the Newark East         year, was 1.1 Tcf.
president of Advanced Resources                 Barnett shale field had about 4,200               A 20-acre infill well pilot program in
International (ARI).                            wells and 135 active rigs, according to        Devon’s core acreage has boosted
   The hottest shale gas play is the            a presentation by Brad Foster, vice            expected recovery from 1.8 Bcfe per
Barnett in the Forth Worth Basin,               president and general manager, central         well to 2 Bcfe per well. Ultimately, the
where horizontal drilling and multiple-         division for Devon Energy Corp. dur-           company expects to drill infill wells on
zone stimulation techniques have fueled         ing the Hart Unconventional Gas                its core and non-core acreage.
the growth from about 0.2 Bcf/d 5 years         Conference last March. Cumulative                 Devon’s recent purchase of Chief
ago to more than 1.3 Bcf/d in 2005.             production stood at 1.7 Tcf, and the           Holdings LLC added significant
   “We believe this gas play could reach        play had the potential to expand to a          reserves and acreage. Plans for the Chief
3 Bcf/d down the road,” Kuuskraa said.          10-county area, he said.                       acreage include drilling about 800 wells
   These technologies and their success in         There are two key reasons the Barnett       during the next 5 years and ultimately
the Barnett have also spurred other shale       became the biggest shale play, Foster          recovering more than 2 Tcfe of gas.
plays, he said, including the Fayetteville in   said. Compared with other productive              “Four things made Chief work for
Arkansas, the Barnett and Woodford in           U.S. gas shales – the Ohio, Antrim, New        us,” Foster said. “We have extensive
West Texas and the Caney and Woodford           Albany and Lewis – the Barnett is over         knowledge and expertise in the Barnett
in the Arkoma Basin of Oklahoma.                pressured with a gradient of about 0.52        and a lot of proprietary seismic inter-
Interest has also been renewed in the           psi/ft, and it contains much more gas in       pretation technologies. We also have a
Devonian shale of the Appalachian Basin         place, an estimated 142 Bcf/sq mile.           unique experience with our 20-acre
where gas shale drilling is up by 50% dur-         Recovery from near-term develop-            infill wells. And finally, we have an
ing the past year.                              ment is expected to be between 10% and         advanced production optimization
   In Oil and Gas Investor’s January 2007       12%; improved recovery techniques              capability.”
“Shale Gas” report, John White, U.S.            might recover an additional 5% to 10%             Average recovery of gas-in-place
exploration and production analyst for          of gas-in-place.                               from Devon’s acreage in the core area is
Natexis Bleichroeder Inc., said 64 pub-            The core producing area of the Barnett      now 16%, up from 9% to 10% in 2002.
lic companies were involved in eight            has the following characteristics:             Every four percentage-point increase in
shale-gas plays in the United States.             • fractures are closed and calcite           recovery adds 1 Tcf of recoverable
Among the most active are:                           filled;                                   reserves for Devon, Foster said.
   • Chesapeake Energy Corp.;                     • porosity is 3% to 5% primary;                 XTO Energy Inc. entered the Barnett
   • Southwestern Energy Co.;                     • permeability is less than 0.001            in 2004 with an acquisition, and by
   • Range Resources;                                milliDarcies;                             September 2006, was producing about
   • Carrizo Oil and Gas;                         • Reservoir thickness is 400ft to            270 MMcf/d and had 21 rigs running, 7
   • Brigham Exploration;                            600ft (122m and 183m);                    in its non-core acreage. It has about

22                                                                                                           www.hartenergy.com • January 2007
                                                                                                                                            Introduction - Gas Shale




                                                                                                                       year; the company expected it to reach
                                                                                                                       200 MMcfe by year-end and 250
                                                                                                                       MMcfe by end 2007. Most of its acreage
                                                                                                                       is in Johnson and Tarrant counties.
                                                                                                                          Chesapeake had 2,100 net potential
                                                                                                                       locations and was operating 12 rigs in
                                                                                                                       the middle of last year, expecting to
                                                                                                                       have 24 rigs at work by year-end
                                                                                                                       capable of drilling 350 to 400 gross
                                                                                                                       wells per year. From the 2,100-net
                                                                                                                       potential locations, Chesapeake esti-
                                                                                                                       mates it has 3.4 Tcfe of unproved
                                                                                                                       reserve potential in addition to 0.6
                                                                                                                       Bcfe of proved reserves.
                                                                                                                          Range Resources Inc.’s shale plays are
                                                                                                                       producing about 24 MMcfe/d from
                                                                                                                       more than 350,000 acres. In the
                                                                                                                       Barnett, the company plans to complete
                                                                                                                       40 wells in the second half of the year
                                                                                                                       and have six rigs running by year-end,
                                                                                                                       according to company information.
Horizontal wells can avoid water even when the shale is not protected by the frac barrier. Horizontal wells also are      In the West Texas Barnett play,
exposed to more pay zone and are able to produce more gas than vertical wells. (Graphic courtesy of Devon Energy)      Range has a 3-D seismic shoot under
                                                                                                                       way and an initial well planned for early
200,000 net acres, about 90,000 in the                         development, during the Unconven-                       this year.
core area. XTO is targeting a recovery of                      tional Gas Conference. At that time,                       Early last year, Reichmann Petroleum
more than 20% in the core area of the                          the company had 10 rigs running in                      Corp. extended drilling contracts on
Barnett where its spacing is 50 acres.                         Johnson County and three in western                     three rigs in the Fort Worth Basin
   “Back in the day of $2 gas and verti-                       counties; it planned to have 22 rigs                    Barnett for 1 year with an option to
cal wells, the Barnett shale was                               running by the end of the year. The                     extend the contracts for an additional
mediocre,” said Keith Hutton, XTO                              company’s average production from the                   year. Reichmann planned to drill more
president. “That started to change when                        Barnett in 2005 was about 50                            than 30 wells in the play last year.
gas prices went up and operators began                         MMcf/d, but reached 100 MMcf/d by
to drill horizontal wells.”                                    the end of the year.                                    Emerging Fayetteville
   Vertical wells in the Barnett produced                         Delozier called EOG’s northeast                      The Fayetteville shale in the Arkansas
between 500,000 cu ft/d and 700,000 cu                         Johnson county area “monster” well terri-               side of the Arkoma Basin is Miss-
ft/d and had typical reserves of 1 Bcf;                        tory and its western Johnson county area,               issippian-age shale, the geological
many horizontal wells had initial flow                         where wells provide a 100% rate of return,              equivalent of the Caney Shale in
rates of 3 MMcf/d to 5 MMcf/d and                              “routine.” Early last year, with four                   Oklahoma and the Barnett Shale in
reserves of 3 Bcf.                                             Johnson county pilots under way, EOG                    north Texas, according to Southwestern
   Hutton estimates the company has 1.2                        was implementing 500-ft (153-m) spac-                   Energy Co., the major participant in
Tcf of reserves in the Barnett, a number                       ing throughout the county and was ready                 the play.
expected to grow by the end of last year.                      to begin a 500-ft Erath county pilot.                      The extensive shale ranges in thick-
   “That will probably grow by 15% to                             Early last year, EOG’s Barnett Shale                 ness from 50ft to 325ft (15m to 99m),
20% over the next 2 years,” he said.                           economic model was based on a direct                    and is found at depths from 1,500ft to
   Most of XTO’s non-core acreage is in                        well cost of $1.8 million and 1.9 Bcf of                6,500ft (458m to 1,983m). South-
areas where the Barnett is 200ft (61m)                         net reserves for western Johnson                        western has drilled productive wells
or thicker. “We believe you can frac the                       County, and a well cost of $2.9 million                 as far apart as 120 miles (193 km) in
wells into water if the layers are any                         and net reserves/well of 2.9 Bcf for                    an east/west direction and 20 miles
thinner than that,” he said.                                   northeast Johnson County.                               (32 km) apart in the north/south
   The Barnett Shale is one of EOG                                Chesapeake Energy Corp.’s Barnett                    direction, said Richard Lane,
Resources Inc.’s key developments, said                        Shale average daily net production was                  Southwestern Energy Co. president.
Phil Delozier, vice president of business                      about 140 MMcfe in the middle of last                   In the middle of last year, Southwestern

Advances In Unconventional Gas • www.hartenergy.com                                                                                                             23
Introduction - Gas Shale




had 10 drilling rigs running in its            others. If drilled on 100-acre spacing,     and a well cost between $3 million and
Fayetteville area.                             XTO reserves could be between 1 Tcf         $4 million.
   Basin average Fayetteville porosity is      and 2 Tcf.                                     The 2006 Oil and Gas Investor report
between 2% and 8%, according to                                                            said the Palo-Duro Bend Shale in the
Southwestern, compared with 6% to 8%           Other Basins                                south Texas Panhandle, 500ft to 1,000ft
in the Newark East field in the Barnett        Oil and Gas Investor’s 2006 “Shale Gas”     (153m to 305m) thick at depths of
play. Permeability is similar for both         report also highlights participants in      7,000ft to 10,500ft (2,135m to 3,203m),
shales at 100 nanoDarcies to 400               other plays around the United States.       is similar in ways to the Barnett Shale
nanoDarcies.                                   Talisman Energy Inc. has a significant      and could “be as big as the Barnett.”
   The key difference between the two is       position in the Appalachian Basin’s            Production from the Antrim Shale in
that the Fayetteville is not overpressured.    Devonian/Ohio play. Edge Petroleum          Michigan has declined for several years.
   In the third quarter, Southwestern          Corp., Noble Energy Corp. and               The wells are between 400ft and 2,000ft
was on track with its 2006 plan to drill       Murphy Oil Co. are active in the Black      (122m and 610m) deep, cost about
between 175 and 200 wells in the               Warrior Basin in Alabama and                $170,000 to drill, and complete and
Fayetteville, almost all of them horizontal.   Mississippi. Newfield Exploration Co.       produce between 400 MMcf and 800
The company has a two-fold drilling            and Petrohawk Energy Corp. are active       MMcf during their life.
strategy, Lane said. In areas where pro-       in the Caney/Woodford in the Arkoma            In Western Canada, Stealth Ventures
duction is building and infrastructure is      Basin, according to the report.             Ltd. announced in October 2005 that it
in place, infill wells are being drilled to       Penn Virginia Corp. has a position in    acquired rights in three Saskatchewan
further boost production. The other            the New Albany Shale play in the Illinois   Exploration Permits, covering slightly
prong of the strategy is to step out with      Basin. Questar Corp. is in the Baxter       more than 1 million acres of primarily
new pilots.                                    play in the Vermillion Basin of northern    shallow gas prospective lands, including
   “By the end of 2006, this strategy will     Colorado and Southern Wyoming.              shale gas. In mid-2006, the company
give us a good spatial sampling of the            In the Devonian Shale play in            began its shallow shale gas-drilling pro-
play on our acreage,” Lane said. “We’ve        Pennsylvania, Range Resources has           gram in Alberta and Saskatchewan. In
seen a good production response as we          drilled 13 wells, with several yet to be    Alberta, Stealth completed drilling a
drill and complete more wells and              completed. Three of the vertical wells      second well that was cored through two
improve the process.”                          have been on production for an average      target intervals identified by the first
   Gross production from the play              of 5 months, and reserves appear to be      well in the same area.
topped 50 MMcf/d by late summer,               in the range of 600,000 cu ft to 1             At Foam Lake, Saskatchewan, six test
compared with 20 MMcf/d in May.                MMcf per well, according to the com-        wells have been drilled and cased in the
   Southwestern expects its horizontal         pany. It plans to have 10 vertical wells    ongoing drilling program. Stealth has a
wells to have an ultimate recovery             frac’d and on production early in the       50% interest in the program, which was
between 1.3 Bcf and 1.5 Bcf per well.          fourth quarter 2006.                        expected to have 16 wells by the fourth
The newer slick-water completions are             Chesapeake is evaluating horizontal      quarter. The company intends to evalu-
coming in above that curve, Lane said,         vs. vertical wells on its acreage in the    ate several producing zones, including
but more production history is needed          West Texas counties of Reeves, Pecos,       the Upper and Lower Colorado Group,
to fully evaluate those completions.           Brewster and Culberson, where shales        for shallow and shale gas.
Recovery is expected to be in the low          are up to four times thicker than the
20%-range.                                     Barnett, have two to four times as much     Stimulation Trends
   Chesapeake believes at least 300,000        gas-in-place and have similar porosity,     Fit-for-purpose fracs have significantly
of its 1.1 million net acres in the            permeability and organic content,           improved shale gas economics, driving
Fayetteville will be commercial. If so, it     according to the company. West Texas        the acceleration of activity in the
would have up to 4,600 net potential           shales, however, are twice as deep as the   Barnett, for example.
drilling locations with an estimated           Barnett, and recovery factors are not yet     “The light sand frac really kicked the
recovery between 1.2 Bcfe and 1.5 Bcfe         known. At mid-2006, Chesapeake had          Barnett off,” Foster said. “It was the first
per well. In the middle of last year, it       three commercial wells on production        technology breakthrough.”
had three rigs running and could have          on its West Texas acreage – four being        Gas is produced from shale through
between 10 and 15 by year-end.                 completed and two being drilled.            desorption from organic components in
   XTO is also in the Fayetteville with           XTO has about 30,000 acres in the        the shale and the release of free gas
about 200,000 acres. The company will          Woodford shale in Oklahoma where it         residing in pore spaces in interbedded
begin drilling this year, and it owns          will drill one or two wells in 2006. It     sand and siltstone layers.
interest in wells now being drilled by         expects between 2 Bcf and 3 Bcf/well          Understanding the reservoir is the

24                                                                                                        www.hartenergy.com • January 2007
                                                                                                                                                        Introduction - Gas Shale




first step in creating a development                                                     Barnett                        Ohio*      Antrim*       New Albany*        Lewis*
strategy. During the past 2 years, 3-D            Depth, ft       7,200                                            2,000            600              500        3,000
seismic has been acquired over much of                           to 9,000                                         to 5,000        to 2,200        to 2,000    to 6,000
the Barnett and most operators have               Thickness, ft 400 to 500                                      300 to 1,000        160              180    500 to 1,900
proprietary interpretation technology.            Scf/ton       100 to 150                                       60 to 100       40 to 100        40 to 80     1 to 45
   “We’re doing things with 3-D data to           Reservoir       3,000                                         500 to 2,000        400          300 to 600     1,000
try to understand the shale play better,”         pressure, psi  to 4,000                                                                                     to 1,500
Lane said. “It goes past the normal               Gas in place,   142.5                                              5 to 10      6 to 15          7 to 10     8 to 50
mapping of reflection data and deeper             Bcf/sq mile
into the attributes.”                                 *Source: Hill & Nelson, 2000, from a presentation by Devon Energy Corp.

   In addition to its shift to horizontal        U.S. Productive Gas Shales
wells, Southwestern has been experi-
menting with completion techniques.              Conference, Steve Drake of Netherland-                                         these challenges facing expansion:
More than 30 recent wells have been              Sewell and Associates Inc. said the 3,000                                         • in the oil prone Barnett, the lower
treated with slick water, or hybrid slick        vertical wells in the Barnett core area                                             frac barrier is water-bearing;
water that use cross-linked fluids, instead      typically will produce 800,000 cu ft/d                                            • there are limestone facies in the
of nitrogen-foam-based treatments.               initially, and 0.6 Bcf to 1.5 Bcf during a                                          Lower Barnett;
   “On a rate time plot, these completions       35-year life. In contrast, the typical initial                                    • increased drilling depths are
are better performers than previous wells,”      potential of 750 horizontal wells was 1.3                                           required;
Lane said. “We are hoping for higher             MMcf/d to 3 MMcf/d, and they are                                                  • urban encroachment is a growing
recoveries from this type of stimulation.”       expected to produce 1.3 Bcf to 2.7 Bcf                                              issue;
   Credit for the improvement likely             during a 30-year life.                                                            • production decline is steep; and
goes to the ability of the water-based              In Devon’s 29-well 20-acre infill pilot                                        • fault zones transport water into
treatment to contact more rock, he said.         program in the Barnett, vertical wells                                              Barnett.
   Southwestern is also testing multi-           left a portion of the reservoir untouched.                                        In areas outside the core area, Upper
stage completion technologies that               In the program, a horizontal well drilled                                      and Lower frac barriers are absent, the
would make it possible to complete hor-          between vertical wells develops four 20-                                       effect of faulting is unknown and pres-
izontal wells quicker and more efficient-        acre areas at a time with one horizontal                                       sures are normal, and the Barnett section
ly. The company has experimented with            well. Offsetting the existing wells                                            thins. There also is a lack of infrastructure.
different perforating schemes as well as         boosted recovery in the core area to                                              Technology advancement needs are
acid soluble cement.                             about 2 Bcf per well.                                                          across the board. It is important to
   Southwestern also continues to ana-              In Johnson County, Devon has                                                find more ways to reduce the footprint
lyze microseismic data to determine the          reduced the average number of days to                                          of operations, use resources such as
type of fracture geometries being creat-         drill a Barnett Shale well from 33 in                                          fresh water and lower the impact on
ed. Interpretation of microseismic               2005 to 18.                                                                    local communities. More efficient
information has led to better under-                Southwestern’s strategy is to pur-                                          multilateral completion techniques
standing of fracture geometry and sub-           chase and operate its own drilling rigs.                                       would be welcome, as would more
sequent job design modifications.                In late summer, it had six company-                                            cost-effective frac techniques.
   There is another key to success in the        owned and operated rigs running in                                                There is potential for a quantum leap
Barnett, Hutton said, where XTO has              the Fayetteville play.                                                         in completion efficiency by condensing
3-D over all its acreage.                           “We’re seeing improved efficiencies                                         the drilling and completion cycle time.
   “You also need 3-D seismic to identify        from that decision. Not only do we have                                           Priority technology needs for gas
karsts and salts that can serve as conduits      better equipment, but it is custom built                                       shale development are the ability to
for water when drilled into,” he said.           for the play,” Lane said.                                                      quantify and prevent formation damage
                                                    The rigs are a “super single” design                                        and understand rock-fluid interaction,
Drilling and Completion Trends                   that uses 45-ft (14-m) joints. The auto-                                       according to operators surveyed for the
Compared with vertical completions,              mated pipe-handling system does not                                            Gas Technology Institute’s Technology
horizontal wells produce more gas                rack pipe in the derrick during trips;                                         Roadmap for Unconventional Gas
sooner and have higher ultimate recov-           instead, a joint is picked up from the                                         Resources. A better understanding of
ery. Horizontal wells began to be a fac-         pipe rack and added to the string.                                             production mechanisms is needed,
tor in the Barnett in 2002 and are now                                                                                          according to the report. Also at the top
general practice.                                Technical Issues, Resource Constraints                                         of the list was public domain gas des-
  At the Hart Unconventional Gas                 In the case of the Barnett, Devon cites                                        orption and thermal maturity data.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                          25
Gas Shale




Developing Gas Shale Reserves
Lifecycle-based approach works best for gas shale reserve development.



S
     hale is a fine-grained sedimentary
     rock characterized by thin layers
     that break with an irregular curv-
ing fracture parallel to the bedding
planes. Shale is typically deposited in
slow-moving water and is often found
in lake and lagoon deposits, river
deltas, offshore beach sands and on
floodplains.
   Shale usually contains free as well as      New Shale Frac-RF frac fluid is proving highly effective in stimulating shale formations. SEM pictures of the shale frac-
adsorbed gas. If the predominant pro-          ture face before (left) and after exposure to reactive fluids show a remarkable amount of surface disruption. This can
duction mechanism is by desorption,            result in improved production following a fracturing treatment.
then a stimulation treatment should be
designed to maximize total fracture sur-            of fracture design and production                           • ShaleCleanSM service—Primary stimu-
face area. If most of the gas is free gas           prediction.                                                    lation and remedial chemistry
stored in the micro-porosity and natural         • Phase 3—Early Development (Mass                                 designed to restore or enhance
fractures, a high-conductivity prop frac            Production). Rapid development                                 productivity.
would likely be more effective.                     with optimized design. Database                              Production decline from fractured shale
                                                    development and benchmarking.                             appears to have three distinct flow peri-
ShaleStimSM Process Provides                     • Phase 4—Mature Development                                 ods, each governed by multiple reservoir
Effective, Holistic Approach                        (Reserve Harvesting). Cash flow                           and completion factors. In the early peri-
The low permeability of shale has driven            cycle. Reservoir production history                       od, frac spacing in the stimulated area and
stimulation design toward large-volume              matching. Adjusting reservoir model.                      frac permeability are key criteria. During a
water fracs, the most economical and                Database imaging.                                         middle flow period, fracture areal extent is
practical way to stimulate gas shales.           • Phase 5—Declining Phase (Main-                             important, along with frac permeability.
Volumes in excess of 100,000 bbl have               tenance and Remediation). Iden-                           In the later period, un-fractured area
been pumped on a single zone.                       tification of remedial candidates.                        (drainage area), matrix permeability and
   Pumping this amount of water into a              Re-stimulation. Decline curve                             frac spacing in the non-stimulated area all
gas-bearing formation, however, is not              shifting.                                                 have an impact.
without risk. Halliburton’s ShaleStim            ShaleStim service consists of a family                          Though proppant transport in thin
process helps address some of the neg-         of products and services to help opera-                        fluids is not well understood, prop
ative consequences associated with             tors enhance asset value throughout the                        nodes, bed fluidization and the ability to
large-volume water fracs. The service is       shale reservoir lifecycle.                                     move high-density prop deposits
tailored to the specific shale production        • ShaleEvalSM service—Shale evalua-                          through narrow slots and right angle
mechanism and composition. The                      tion including total organic carbon                       turns have been demonstrated in lab
process follows the lifecycle of the                (TOC) content, shale maturity                             experiments.
reservoir, which includes these phases:             (vitrinite reflectance Ro), gas con-                         ShaleFrac service is useful because
   • Phase 1—Regional Resource Reco-                tent (scf/ton), free and adsorbed gas                     shale is not characterized by single bi-
     nnaissance (Reservoir Assessment).             content, fracture flow tests, x-ray,                      wing fractures but contains many paral-
     Initial look at reservoir potential and        SEM and acid solubility analysis.                         lel and orthogonal fracture wings.
     extent. Evaluate the shale. Quantify        • ShaleLogSM service—Log identifica-                         Empirical models have been generated
     reservoir quality.                             tion of sweet spots (TOC, scf/ton,                        for the Barnett Shale using microseis-
   • Phase 2—Local Asset Evaluation                 brittleness, GIP, IP and EUR).                            mic image data.
     (Start-up Exploration). Experimental        • ShaleFracSM service—Shale-specific                            Each ShaleClean service treatment
     development of drilling and comple-            hydraulic fracture stimulation                            has several elements. Surface reactive
     tion techniques. Trial investigation           technologies.                                             fluid enhances the overall surface area

26                                                                                                                                 www.hartenergy.com • January 2007
                                                                                                                                                                          Gas Shale




conductivity; surface modification                                                                                          less productive than fractured vertical
agents help reduce fines migration,                                                                                         wells. Low-permeability zones often
enhance fracture conductivity and help                                                                                      contain multiple layers of varying
remove treatment water. A microemul-                                                                                        porosity and permeability. Unexpected
sion also helps treatment water removal.                                                                                    vertical permeability barriers often exist
Conductivity enhancement/endurance                                                                                          that are too thin to be detected by con-
prop additives improve and maintain                                                                                         ventional well logs.
fracture network conductivity during                                                                                           Uncontrolled generation of hydrauli-
the production cycle.                                                                                                       cally induced fractures can result in a
   ShaleClean agent is a primary water frac                                                                                 poor distribution of the fractures along
clean up and remedial treatment chemical                     Diagenesis can greatly reduce fracture conductivity.           an openhole lateral. For best results, a
used to mitigate the impact of foreign                       Coating the proppant with SandWedge enhancer can help          fracture treatment should produce a
chemicals and solids injected during a                       control this process.                                          limited number of discrete fractures
large-volume water frac. These foreign                                                                                      widely separated and well distributed
materials can cause reactions between the                     Reported initial production has been                          along the horizontal.
fluids injected, the rock face and the reser-                 double that of treatments without reac-                          Fractures also should be created only
voir fluids. Scale, sludge and emulsions can                  tive fluids.                                                  where they are needed. Multiple frac-
form. Other problems can occur, including                                                                                   tures close to each other will improve
formation degradation, prop pack loss of                      SandWedge® enhancer                                           the initial stimulation response but
conductivity and fines migration. Fresh                       SandWedge enhancer, part of Halli-                            usually provide little additional cumu-
water also can introduce bacteria capable                     burton’s Conductivity Endurance tech-                         lative production after a year or two
of thriving at downhole conditions.                           nology, is now available in a special for-                    following treatment.
                                                              mulation designed for water fracs. This                          Now, there is a stimulation process
ShaleFrac-RF service                                          on-the-fly proppant coating technology                        that is consistently effective in low- to
The use of reactive fluids is a relatively                    provides several benefits for water frac                      medium-permeability horizontal com-
new concept in shale stimulation. The                         treatments:                                                   pletions. Field performance of Halli-
concept evolved from the use of acid                             • increases conductivity.                                  burton’s SurgiFrac service has shown it
slugs to increase injection rates. The                           • increases load recovery;                                 can provide precise control of fracture
unexpected pressure drop that occurs                             • controls the effects of diagenesis;                      initiation and propagation in gas
when acid hits the shale formation                                 and                                                      shale. The SurgiFrac service provides
raised a question about shale acid solu-                         • helps increase production.                               important benefits:
bility. Most shales in the Mid-                                                                                                • helps increase production by re-
Continent area have a solubility of 8%                        SurgiFrac® service                                                 entering openhole horizontal well-
to 20%. Multiple treatments have been                         provides fracture control                                          bores with coiled tubing or jointed
done using between 20,000 gal and                             Horizontal completions are the choice                              pipe and accurately placing fractures
200,000 gal of reactive fluid dispersed                       for many shale wells; however, in some                             in bypassed and underperforming
through the water frac volume.                                situations, horizontal completions are                             zones quickly and cost effectively;




SurgiFrac service combines proven hydrajetting technology and fracturing techniques to enable placing multiple fractures with surgical precision in horizontal wellbores with no down-
hole sealing devices. Operators are achieving significant increases using this method.

Advances In Unconventional Gas • www.hartenergy.com                                                                                                                                27
Gas Shale




                                                                                   rate of three wells into         tubing in a 4 3/4-in., 1,600-ft (488-m)
                                                                                   the best performer. To           openhole horizontal section and
                                                                                   stimulate production             eight fractures were placed in 5
                                                                                   from the three hori-             hours;
                                                                                   zontal completions in a      •   in the first treatment of an open-
                                                                                   low-permeability car-            hole multilateral completion, a
                                                                                   bonate reservoir, con-           workover rig and a bent sub were
                                                                                   ventional treatments             used with the SurgiFrac assembly
                                                                                   and the SurgiFrac                to place six small-to-moderate
                                                                                   process were used.               size fractures in each of two 800-ft
                                                                                   Well depths ranged               (244-m) laterals using 28% HCl
                                                                                   from 11,000ft to                 as a stimulation fluid and avoiding
                                                                                   12,500ft (3,355m to              a nearby water zone. An initial
Example of the effect of refracturing a shale well on production rate.             3,813m) and laterals             five-fold increase stabilized at a
                                                                                   varied in length from            four-fold increase several weeks
   • optimizes reservoir drainage by 2,200ft to 4,600ft (671m to 1,403m).                                           after the treatment;
     precise location of fractures with a Reservoir pressure was between 3,219psi                               •   in South Texas, a gas well with
     customized treatment;                                     and 4,650psi.                                        an 1,800-ft (549-m) horizontal
   • adds new production more quickly                             Wells 1 and 2 had the best potential.             perforated liner was treated with
     than with conventional fracturing They were treated using coiled tubing                                        40,000 gal at 18 bbl/min down
     by creating multiple fractures in the and a tool with a jetting sub to place                                   casing, boosting production by
     wellbore with no sealing (packers, acid treatments. Production increases,                                      75% compared with a conven-
     etc.) required between zones; and                         however, were disappointing.                         tional acid frac;
   • reduces fracturing treatment                                 Well 3 had the lowest pre-stimulation         •   in Southeast New Mexico, an old
     costs by lowering tortuosity, production rate and the least potential,                                         well in a mature waterflood with a
     resulting in less equipment and even though it had the longest open-                                           1,600-ft (488-m), 4 3/4-in. open-
     lower viscosity fluids.                                   hole lateral. After Well 2 experienced               hole lateral in low-permeability
   As with single wellbore horizontal such a short-lived production increase,                                       carbonate was producing 3 b/d of
completions, a growing number of it appeared the only way to make Well                                              oil before being fracture-acidized
marginally economic Level 1 and 3 economical was to create deep frac-                                               with SurgiFrac service, creating
Level 2 multilateral completions are tures that could connect with natural                                          eight distinct fractures. Initial pro-
not living up to their potential. fracture networks that were not near                                              duction after treatment was 50 b/d
Conventional methods that are effec- the borehole.                                                                  of oil and production a month later
tive usually pose too high a risk of                              SurgiFrac service used 1 3/4 in. coiled           was 30 b/d of oil;
well problems or are too costly for tubing to pump three stages averaging                                       •   offshore Brazil, SurgiFrac boosted
low-return reservoir conditions.                               5,000 gal of gelled 28% hydrochloric                 production from an offshore,
   In openhole multilateral Level 1 acid (HCl) down the tubing through                                              openhole horizontal well with a
wells in Texas and Louisiana, however, the special service tool. Carbon dioxide                                     pre-perforated liner by five-fold
SurgiFrac service was used to create six pumped through the annulus formed a                                        after three proppant fractures were
to 14 independent fractures in each of foam down hole that enhanced acid                                            placed using bauxite and resin
several dual and triple lateral wells, retardation and helped limit fluid loss.                                     coated bauxite (16 to 20 mesh) in
some of which were sand fractured and                             The result was longer fractures.                  concentrations reaching 14 lb/gal.
others were acid fractured. Consistently                          Although only three fractures were
high production rates proved that if                           placed along the lateral, production           Refracturing shale wells
permeability is low, the SurgiFrac increased from 0.83 MMscf/d to 5.9                                         It has been established that only 10% of
process can stimulate wells that could MMscf/d. The well exhibited a slower                                   GIP is recovered with the initial com-
not be stimulated with conventional decline than Well 2, indicating the                                       pletion. Refracturing the shale can
techniques.                                                    treatment was successful in reaching the       increase the recovery rate by an addi-
                                                               distant fracture network.                      tional 8% to 10%. Simple reperforation
Case histories                                                    Other field results highlight SurgiFrac’s   of the original interval and pumping a
In Canada, SurgiFrac service provided a                        versatility and effectiveness:                 job volume at least 25% larger than the
six-fold production increase, turning a well                       • production increased 800% after the      previous frac has produced positive
with the lowest pre-treatment production                               service was deployed with coiled       results in vertical shale wells.

28                                                                                                                            www.hartenergy.com • January 2007
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