BAKER HUGHES INCORPORATED
`Exhibit 1020
`
`Page 1 of 11
`
`

`
`2
`
`M.S. VAN DOMELEN
`
`SPE 49523
`
`Case Study 1: Germany's Soehlingen Wells
`
`The Reservoir. The Rotliegendes formation includes several
`sands that are productive in Gennany. The Netherlands and
`the soutlrenr North Sea. Rotliegendes sands are nrassivc (up to
`1000 it gross) with moderate porosity (I0-12%) and typically
`low permeability (rarely above 10 md and often as low as 001
`Ind). The presence ofdiagerretic illite in the pore spzrce is the
`cause for low penrreability. Reservoir depth tends to increase
`from ca. 9.000 feet in the southern North Sea to 16.000 feet as
`
`the trend moves cast into Gennany. Permeability also tends to
`decrease in the eastward direction. Commercial production of
`natural gas from these low penneability, deep members of the
`Rotliegendes fonnations requires completion with propped
`hydraulic
`fractures.
`Examples
`of
`successful
`fracture
`stimulations in the North Sea Rotliegendes can be found in
`references 2 to 5. Fracture stimulation of the Rotliegendes
`formation in Germany is complicated by the higher reservoir
`temperature (290°F) and increased stress levels due to depth
`(15,700 ft TVD) and reservoir pressure (8,700 psi).
`
`The History. Germany's first massive hydraulic fiacturing
`(MHF)
`treatments were
`conducted in
`1977
`in BEB’s
`Goldenstedt Z7 well.6 A total of 420,000 lbs of Ottawa sand
`was placed in two separate hydraulic fracturing treatments
`utilizing a total of 225,000 gal of polymer emulsion frac fluid.
`During pumping the average proppant concentration was less
`than 2 ppg. Post treatment production rates from the 0.1-0.5
`md formations were approximately 7 MM scf/D.
`_A record-setting MHF t:reatment was conducted on the
`Hauptsandstein of the Rotliegendes formation in Mobil Oil
`AG’s Soehlingen Z4 well in December of 1982.7 A total of 1.2
`MM lbs. of high strength sintered bauxite was placed with
`690,000 gallons of titanate crosslinked fluid. As with the
`Goldenstedt Z7 well, the average proppant concentration was
`less than 2 ppg. At
`the time the Soehlingen Z4 fracturing
`treatment was the largest ever conducted in Europe and the
`world’s largest in terms of bauxite placed. Fracture stimulation
`allowed the production rate from the 0.008 md formation to be
`increased from 1.2 MM scf/D at 260 psi to 6.7 MM scf7D at
`2,870 psi.
`It is interesting to note that the effective permeability of
`the Soehlingen Z4 well was 10 to 50-fold less than that of the
`Goldenstedt Z7 well yet
`similar production rates were
`achieved. The fracturing treatment on the tighter Soehlingen
`Z4 well used roughly three times as much proppant. The
`resulting production increases were the result of the larger job
`size as well as the use of stronger proppant (sintered bauxite
`instead of sand). It was the advances in fracturing technology
`which allowed the tighter Soehlingen Z4 well to be produced
`at a rate comparable to the Goldenstedt Z7 well and the
`treatment added an estimated 20 bcf of reserves to the field.
`Three vertical wells were drilled and fractured in the
`
`Soehlingen Field in the 1980’s. Large fluid volumes were used
`on the three wells averaging 500,000 gallons of crosslinked
`fluid with 35% by volume pad with average proppant
`
`concentrations below 3 ppg. The results ofthe treatments were
`not frilly satisfactory. The average sustained production rates
`of4_5 MM scf/D proved uneconomical.
`
`and
`drilling
`in
`developments
`The Challenge. Recent
`completion lCCllI10l0g_\' allowed for a totally new approach to
`the development of the Soehlingen Z10 well. The project's
`objective was
`to attain production rates
`frorrr
`a multiple
`fractured horizontal well that are three to five times the rates
`
`attainable from a vertical. corrveritionally fractured wellfll This
`translates to a sustained rate of about 13 MM scf/D.
`
`Similar to the previous Soehlingen wells. the target for this
`well was to treat
`the Hauptsandstein of the Rotliegendes
`formation. The Z 10 well was drilled to a total vertical depth of
`15,688 ft, where it was deviated horizontally for 2,066 ft into
`the reservoir parallel to the least principal stress. The drilling
`ofthe well is discussed in detail in by Pust and Schamp.9 The
`well was completed with Sliding Side Doors (SSD) in 7 inch
`casing to allow for
`selective
`stimulation with multiple
`hydraulic fractures. The completion of the well is discussed in
`detail by Chambers, et.ar.“’ 1n the fall of 1994, 2.3 MM lbs of
`intermediate strength proppant were placed in the Z10 well in
`four separate fracturing treatments, applying approximately
`500,000 gallons of a delayed borate crosslinked fluid. This
`corresponds to an average pumping proppant concentration of
`5 ppg. "
`Two world records were set by this treatment: one for the
`deepest horizontal well drilled and the other for the deepest
`multiple fi“actures.”'” Initial post-fracture production was 23
`Min scf/D at a flowing tubing head pressure of 4,350 psi.
`After 2 years, a sustained production rate of 18 MM scf/D at
`4,350 psi was achieved from all four fi'actures.8 This rate
`exceeded the original target rate and demonstrated that it
`is
`technically possible to drill, complete and have multiple
`stirmrlations in long horizontal sections in a very deep, tight
`reservoir under
`extreme high pressure/high temperature
`operating conditions.
`
`Past and Present. Below, fracturing techniques used in the
`past and new technological advances that were crucial to the
`success of Soehlingen Z-10 will be compared and discussed.
`Results of fracture simulations for the Z4 and Z10 wells are
`
`presented in Table 1. Key design and treatment data are given
`in Table 2. Treatment results are summarized in Table 3.
`
`Examination of these three tables provides a good illustration
`of the technological advances made since 1982.
`Fracture Optimizution. The first step in the optimization
`process for fractured horizontal wells is to determine the
`required length of the horizontal section,
`the number of
`fractures required and the length of the individual fractures.
`For the Z10 well,
`it had been decided to use transverse
`fractures. See Figure
`1
`for an illustration of transverse
`fractures in a horizontal wellbore. Production predictions for
`the Z10 well were provided by Hunt for various combinations
`of multiple transverse fractures, fracture half-lengths and total
`drainage areas.” The prediction technique that was used is
`
`600
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`Page 2 of 11
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`

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`SPE 49523
`
`ENHANCED PROFITABILITY WITH NON-CONVENTIONAL IOR TECHNOLOGY
`
`3 g
`
`discussed by Soliman, et.al.”’ Norris, et.al. provides a good
`overview of current
`technology for prediction of fractured
`horizontal perfonnance.l7 Once the well was drilled and the
`reservoir
`permeability more
`accurately
`known.
`frnal
`optirnization indicated an optimum lrorizontal length of 2.000
`feet with four perpendicular fractures eqtrally spaced along the
`hor'i'/.orrtal section. The most effective fractur‘e length was
`beliered to be 300 feet. assurnirrg inlinite condrtctivily. Table
`1 contains the results of fracture (r‘e-)sirrrulations performed
`with data
`from the Z4
`and ZIO well
`liles. using a
`commercially available fracture simulator (FracPro). It is very
`interesting to note that
`the designed fracture length (total
`length, not halflength) for the Z4 well is about the same as the
`optimized length of the horizontal wellbore in the ZIO. It is of
`further
`interest
`to note that
`the calculated total propped
`fracture areas for the two wells are nearly identical. Yet the
`Z10 well
`significantly out—perfonned the Z4 well. This
`demonstrates that a fractured horizontal well can effectively
`drain a larger area than a fracture vertical well.
`Perfomtion Considerations. Much research has been
`done on the optimization of perforations for horizontal well
`fracturing.m° Table 2 contains perforation details for the Z4
`and Z10 wells. along with other relevant design and treatment
`data. A short perforated interval was used in the Z10 well to
`avoid the creation of multiple fractures. High shot density and
`large holes ensured that perforation skin effects would be
`minimized. Extreme overbalance perforatingz" was also used
`in the Z10 well to minimize fracture initiation pressures. The
`fracture-specific perforation design was. combined with the
`placement of SSDs in the horizontal completion to allow the
`four fiacturing treatments to be selectively placed and allow
`selective isolation and re-errtry. These advances in perforating
`and completion technology contributed significantly to the
`ability to effectively fracture-stirnulate the high-pressure
`intervals in the Z10 well. Specific details of the perforation
`techniques used in the Z10 well are given in reference 10. A
`simplified completion diagram is show in Figure 2.
`.
`fluid
`Fluid (.'0n.s'i1leratimrs. Advances
`in
`fracturing
`technologies
`allowed
`significantly
`higher
`proppant
`concentrations to be placed in the Z10 well. (See Table 2)
`This contributed to a reduction in fluid volumes and allowed
`
`more efficient packing of the fractures. Tip Screen Out (TSO)
`designs“ were used to provide additional conductivity in the
`near wellbore area, the portion .of fracture where the highest
`flow rates occur. High conductivity was required due to the
`relatively small perforated intervals and anticipated non-Darcy
`effects. A tail-in of resin coated proppant was used to prevent
`proppant back production. Break times were significantly
`reduced to ensure that the proppant was trapped in the fracture
`with rrrinirnum settling. To take advantage of the known
`improvements in borate fracturing fluid technologies”, an
`extensive
`fluid optimization program was
`conducted.”
`Viscosity behavior as a function of time, interaction between
`the fracture fluid and resin coated proppant and compatibility
`studies with the formation and completion fluids were
`investigated. Specific details of the fluid optimization are
`
`601
`
`iven in reference H. The fluid formulation used in the Z10
`well represented one of the tnost aggressive tests of borate
`chemistry to date. This is due to the high Bl lT (290°F) and
`high conecrrtrations ofcurable resin coated proppant (up to l2
`ppg). Both of these factors are known to adversely elfcct the
`stability of borate llrrids as well as the per‘lbr‘rrr:rrrce of high
`ternperature br'eakers. Balancing the lluid stability during '
`pumping and the rapid break time was a teclrnical challenge in
`the '/.l() well and would not have been possible with the
`technology that was a\'ailable when the
`'/.4 well was
`completed.
`Pmp/nmt I)emil\'. The fracturing treatrnent on the Z4 used
`high-strength sintered battxite. Evert
`though high quality
`intennediate strength ceramic (lSC) proppants had just been
`introduced to the industry, they had not yet gained acceptance
`and were therefore not used for this treatment. The use of lSC
`in the ZlO well resulted in significant cost reduction, while
`still maintaining the desire for high conductivity. The high
`concentrations of proppant that were placed allowed the ISC
`to be strong enough, even at stress levels as high as 10,000 psi.
`The use of resin coated (RC) proppant for tail—in,
`limited
`proppant back-production. The desire to use RC proppant with
`a borate fluid necessitated additional testing as high pH fluids
`can adversely affect
`the ultimate
`compressive
`strength
`obtained with curable RC propparrts. Commercially available
`RC proppants were evaluated which consolidate in the
`fracture, but not in the wellbore in case of premature screen-
`out.” The use of such proppants, particularly in a high-
`temperature borate
`fluid,
`is
`another
`illustration of
`the
`technological advances that were made in the time between
`the fracturing ofthe Z4 and Z10 wells.
`important
`the most
`Treatment Execution.
`Perhaps
`advances in fracturing technology have been in the area of
`treatment execution. Proper fonnation breakdown techniques,
`along with variable-rate injection tests and erosion sand
`slugsm“ helped to limit surface treating pressures which were
`slightly higher in the Z10 well than in the Z4 well. (See Table
`2). In addition, proper minifrac analysis as well as real-tirne
`monitoring of the bottom hole treating pressure allowed
`greater confidence in executing the TSO designs. Automated
`control of the
`fracturing equipment provided execution
`consistency not available at
`the time the Z4 well was
`fractured. Specific details of the treatment execution are given
`in references 8 and 1 1.
`
`Treatment Results. Table 3 compares the treatment results
`for the Soehlingen Z4 and Z10 wells. The use of multiple
`fractures in the horizontal Z10 well provided a four times
`higher well productivity than the Z4 well. The best summary
`of this project is obtained by quoting directly from the Mobil
`engineers “The pioneering project provided evidence that the
`integration of horizontal well and stimulation techniques will
`mobilize new reserves
`firom very low penneability gas
`reservoirs. Above all, this represents a breakthrough for the
`future development of tight gas reservoirs.”8
`
`Page 3 of 11
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`

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`4
`
`MS. VAN DOMELEN
`
`’SPE 49523
`
`Case Study 2: Phillips UK’s Joanne Field
`
`The Reservoir. The Judy/Joanne Fields are located in the UK
`sector of the central North Sea, commonly known as the J
`Block. The original field development plan consisted of a 24-
`slot platform for Jud)‘ and a
`l2-slot subsea template for
`Jozrnne. Wells in the Joanne produce primarily front Danizin
`sediments with the interxals of interest
`the likofsk and Tor
`
`clralks. These forinations tend to be soft. Reservoir pressure is
`27.000 psi and ternperature is 240°F. Depth ranges from 9.000
`to l L000 ft. Experience with other North Sea clralks showed
`that extensive acid stimulation programs are required in order
`to achieve commercial production rates.25'27 Each chalk well
`would
`contain multiple
`producing
`intervals.
`Selective
`placement of the acid stimulations was therefore critical to the
`success of the project.
`
`The History. Phillips’ original plan was to drill up to 12
`deviated. wells, however, because drilling horizontal wells
`would allow a reduction in the number of well slots,
`the
`decision was made to complete horizontally,” The new wells
`were designed to intersect the most productive reservoir layers
`twice, to further maximize production. A review of similar
`completions carried out by other North Sea operators indicated
`that an excessive amount of rig time would be required to
`perform the selective stirnulations, typically 3-4 days per zone.
`From the initial review. it was apparent that the project could
`not support the increased rig costs, and thus, an altemative
`completion and stimulation method was needed.
`
`The Challenge. Completion systems for selective stimulation
`of horizontal wells had been used in the Danish sector of the
`
`North Sea for several years.Z°‘3° These systems, however,
`require an additional
`trip with the drill string with each
`interval to be selectively perforated, stimulated and isolated.
`Hence, there is a significant increase in rig time and time on
`location for the stimulation vessel. The goal was to develop a
`new completion so that each zone could be treated directly
`after the previous zone. Simplicity, rig savings and stimulation
`cost reduction were the primary driving factors during the
`design stage.
`
`The Solution. An imrovative completion design that allows
`rapid, multiple
`stimulations
`(fracture or matrix)
`to be
`perfonned in horizontal wells was developed. Specific system
`details are given by Thomson and Nazaroo." This field-
`proven system allows acid stimulation of up to 10 different
`zones in a single trip without
`through-tubing intervention.
`Figure 3 shows a typical Joanne completion. The key element
`of the completion system is a Multi-Stage Acid Frac (MSAF)
`tool that is similar to a sliding sleeve circulating device and is
`run in the closed position. Up to 9 MSAF tools have been run
`in the Joanne completions. Zonal
`isolation is achieved by
`hydraulic-set retrievable packers positioned on each side of the
`MSAF tools. Each sleeve contains a threaded ball seat with the
`
`smallest ball seat in the lowest sleeve and the largest ball seat
`
`in the highest sleeve. With this system, stimulation of ten
`separate zones is accomplished with no tubing trips or planned
`shut-down during stimulation services.
`
`Completion and Stimulation. Before running the l\rlS.-\F
`completion. each well was perforated with tul)ing~corrvcye(l
`per‘for'ation (TCP) guns. Multiple packers _\\’er‘e spaced out in
`order to isolate the zones to be stimulated. The completions
`were run in one trip to the safct_\' valve and packers were set
`simultaneously (up to ten packers at a time!) .-\tier‘ all
`the
`surface equipment was
`installed,
`the
`lower most pump
`out/cycle plug was expelled and stimulation operations were
`ready to commence.
`Stinrulrnitm Q/"(Ire A11. The first well, MI. was completed
`and stimulated by the Big Orange XVIII in August I994. A
`total of 200,000 gallons of 28% HCl was used to acidise seven
`zones in less than eight hours. Pump rates during stimulation
`ranged from 25-40 BPM at surface pressures of 5,500 to 8,500
`psi. During stimulation, pumping operations were continuous.
`The pump rates were reduced to 5 BPM to lubricate each ball
`into the wellbore. The pump-rate was then increased to 20 to
`25 BPM to transport each ball to within 500 ft of its mating
`seat. The rate was reduced to 5 BPM until the ball seated.
`
`Once each ball found its seat, the pressure was increased until
`the shear screws sheared, allowing the sleeve to move down to
`the open position. The ball provided positive isolation of the
`zone that had just been treated and allowed stimulation of the
`next zone to commence. The process was repeated until all
`seven zones were stimulated. After treatment, all six balls
`were flowed back to surface and caught
`in a ball catcher
`during clean-up operations.
`Stimulation of the M5. Provisional treatment designs for
`the following three wells required 320,000 to 390,000 gallons
`of 28% HCI per well.” These wells have ten zones each, to be
`stimulated selectively. This presented a new challenge, as
`available raw acid storage capacity on North Sea vessels is
`limited to 180,000 gallons. The use of a single vessel required
`a return to port in order to re-load and a minimum of 36 hours,
`per trip, would be added. The solution was to use two vessels.
`The original plan was to stimulate the first five zones with one
`vessel, then the last five by the second vessel. The M5 was
`stimulated in June 1995 by the Western Renaissance followed
`by the Vestfonn. Unfortunately, surface treating pressures on
`the M5 reached 9,500 psi and subsequently the treatment rates
`had to be reduced. The treatment time was extended, and the
`pumps were required to run at 9,500 psi for the greater part of
`the job. This type of pumping was hard on the conventional
`pumps as the treatment pressures were only slightly below the
`pumps’ 10,000 psi maxirnum.3Z Individual pump failures
`increased the total stimulation time to 24 hours for the M5.”
`In spite of the problems during pumping, the treatment was
`considered a success.
`
`Stimulation ofthe M4 and M3. It was decided that the M4
`and M3 would be treated with both vessels pumping
`simultaneously. The use of I4 pumps, at the same time, would
`lessen the strain on each pump and reduce the consequences of
`
`602
`
`Page 4 of 11
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`

`
`SPE 49523
`
`ENHANCED PROF|TABlLlTY WITH NON—CONVENTlONAL IOR TECHNOLOGY
`
`5 w
`
`individual pump failures.” This would be the first time that
`two dynamically-positioned North Sea stimulation vessels had
`been rigged up on the same well simultaneously. Fewer
`problems were encountered and the time to stimulate each of
`these wells was about halfthe time needed for the M5. Table -1
`
`contains a suminary of the total time to install completions and
`carry out the stimulations on the four Joanne wells.
`
`lield-proven in'l’hiIlips‘
`Results. T.he l\lS.—\F tool was lirst
`Joanne Field. One 7-zone completion and three 10-zone
`completions were run in the summers of I994 and I995. Large
`volumes of fluid, 300,000 gallons of 28% HCI and l50.000
`gallons of gelled pad were selectively placed. An additional
`l0-zone completion was installed in Phillips’ Hewett 48/29-
`Bl 1 well. Most recently, the MSAF completion has been used
`in the Ekofisk Field in the Norwegian sectoriof the North Sea.
`Cost savings due to rig time reduction more than offset the
`cost of the completion. Tables 5 and 6 illustrated the economic
`value to the customer (EVC) realized through the use of the
`MSAF completion.” Not only was the total number of wells
`required reduced significantly, but significant savings per well
`were demonstrated as a result of the substantially reduced rig
`time. Advances in completion and stimulation technologies
`allowed the marginal Joanne Field to be economic.
`
`Case Study 3: High Relief, Marginal Chalk Fields in
`the North Sea
`
`The History. Chalk fields have been on production in the
`North Sea since the early 19705. The best known are Phillips’
`Ekofisk, Amoco’s Valhall and Maersk’s Dan Field. These
`fields are
`located in the Central North Sea, near
`the
`intersection of the Norwegian, Danish and UK sectors. As
`early as the mid-l970’s, marginal fields were discovered in
`this area, however,
`technology at
`the time did not allow
`commercial development. One of the first marginal fields to be
`developed was Statoil’s Tommeliten Field. This project, a
`subsea development in water depth of 250 ft, is based upon the
`use of existing infrastructure of the Ekofisk Complex.
`Completion and stimulation of the conventional deviated wells
`took place during the
`surmner of
`1988.27 Stimulation
`programs, which consisted of altemating stages of crosslinked
`pad and gelled acid diverted at high rates with ball sealers,
`were very successfiil. Today the Tommeliten wells continue to
`produce above expectation and no interventions have been
`required during the 10 years since initial completion.“
`
`The Challenge. Several marginal fields were discovered in
`the UK sector of the North Sea, in an area that is commonly
`called the Central Graben. Water depth in this area ranges
`from 300 to 350 ft. The distinguishing feature of these fields is
`that the chalk reservoirs are draped over a salt diapir and of
`very high relief (up to 60°). Reservoir uncertainty was high
`due to seismic imaging problems as a result of the steep dip
`and poor reflections off the adjacent salt dome. Appraisal
`
`ells were drilled near—vertical and conventionally deviated.
`Some DST results were promising (2,500 to 3,500 BOPD),
`however, others were lack-luster (400 to 600 BOPD). Less
`than economical
`test
`rates were attributed to both well
`
`these
`ln addition.
`architecture and inadequate stimulation.
`fields dltl not have the benclit of an existing inl’rastructure.
`which C0lllpllC2llC(l and delayed (lc\'elopment_
`
`The Reservoir. Two fields will be discussed: both have a
`similar description. The reservoirs consist of liactured chalk
`adjacent to a large salt diapir. The zones of interest include the
`Ekofisk and Tor. The bulk ofthe reserves lie in the tight chalk
`matrix with production coming from the natural
`fracture’
`network. Due to the high relief and thickness of the reservoir
`rock (200 to 600 ft) the oil columns can be high at 3000 ft.
`Figure 4 shows a typical reservoir cross-section. True vertical
`depths (TVD) can range from 3,500 to 7,500 ft. Bottom hole
`temperatureslrange from l90 to 220°F, depending upon TVD.
`The reservoirs are slightly overpressured with initial gradients
`of about 0.58 psi/ft at
`the top of the structure and fluid
`gradients of 0.28 to 0.30 psi/ft in the reservoir. Identification
`and stimulation of the primary natural fiacture networks is
`considered crucial to the success of the developments.
`
`The Results. Many advances in technology contributed to the
`ability to develop these high relief, marginal chalk fields.
`Structural mapping was improved by the advent of 3D seismic
`data analysis. Natural
`fracture identification was enhanced
`through detailed evaluation of mud losses \vl1ile drilling.“
`Borehole image logs (both sonic and resistivity tools) and
`nuclear magnetic resonance logs complimented the drilling
`data.” Steering using paleontology and advances in directional
`drilling allowed the stratigraphically horizontal wells to be
`accurately positioned.
`In later developments, water-based
`drilling fluids were used to minimize damage to the natural
`fracture network. The use of early production systems (EPS)
`allowed the opportunity to resolve reservoir uncertainties prior
`to full
`field de\r'eloptnerit.37‘38 Finally,
`the integration of
`completion and stimulation design delivered the
`high
`productivity essential for economic de\'elopmerit.39‘4°
`BP Il’I(lC/1(1)’. Located in Block 23/26a of the UK sector of
`
`the North Sea, the Machar Field represents the next step up
`from an Extended Well Test (EWT) to an EPS, ultimately
`resulting in full field development of a marginal field. A 300-
`day EWT following completion and stimulation of the Machar
`wells is thought to have lead to a reserves upgrade, estimated
`at about 62 million barrels.36'37 Details of the well design and
`stimulation treatments
`in the Machar
`are presented by
`Gilchrist, et.al.39 Drilled at z55° deviation, the objective of the
`Machar wells was to intersect as many of the primary natural
`fracture systems in the reservoir as possible. The main
`completion
`design
`objective was
`to
`ensure
`good
`wellbore/fracture communication. Two completion options
`were considered; an uncemented liner with external casing
`packers (ECPS) or a cemented liner, selectively perforated
`across the zones of natural fracturing. Although cementing
`
`603
`
`Page 5 of 11
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`

`
`6
`
`MS. VAN DOMELEN
`
`SPE 49523
`
`posed the risk of either damaging or “missing” the natural
`fractures,
`the cemellted liner approach was selected based
`-upon wellbore stability studies and reservoir management
`C0lISl(I6ffilIOIIS. Although it was recognized that a water—based
`mud was preferred to an oil-based olle (froln a formation
`danlagc viewpoint). drilling problclrls on all earlier well
`necessitated tlle switch to all oil-based lriud system.
`l\lassi\'c acid fracturing treatments were perfonned on the
`l\lac|lar ltlz and 20y wells in tlle summers of I994 and 1995.
`respectively. The treatment design was very similar to the
`approach that had been used successfully in the Tolnlnelitell
`Field." Specific attention to the execution and evaluation of
`the Machar stimulation treatments was given by Lietard, et.
`al.“ Examination of Table 7 shows solne very interesting
`highlights froln the stimulation treatment results. In all of the
`treatments, the number of stages was related to the number of
`perforated intervals. Note that although stimulation of the near
`vertical
`l3z well ‘resulted in a substantial
`increase in the
`Productivity Index (Pl), production for this well was not
`economic. The two stratigraphically horizontal wells not only
`showed a record increase in Pl” but also resulted in sustained
`average production rates of 23,000 BOPD and the production
`of 14.6 million barrels over the 21-month project.“
`results
`Conoco Btmf/I Encouraged by the
`positive
`achieved by BP in the Machar EWT/EPS; Conoco and
`partners entered into Phase I of the Banff development
`in
`Blocks 29/2a and 22/27a in the summer of I996. Phase I
`
`consisted of two stratigraphically horizontal production wells
`and one. truly horizontal water injection well. The drilling,
`colnpletion and stimulation strategies
`for
`the two Banff
`producers were almost identical to the BP Machar plans, with
`the exception being that recent advances ilr drilling fluid
`technology allowed water-based muds to be successfully used
`in Banff. Details of the well tests before and after stimulation
`
`in Banff are not published, however, production during the last
`3 months of 1996 was reported to average 25,630 BOPD.“
`This represents a substantial improvement over the discovery
`well results which ranged from a low of 563 BOPD to a high
`of 8,200 BOPD.‘° Results of the 6-month EWT allowed
`Conoco to better estimate the oil reserves at about 60 million
`
`barrels.“ Approximately 5 million barrels were produced
`during Phase 1.45 First oil from Phase II is scheduled for June,
`1998.
`
`Improved Recovery. The BP Machar and Conoco Banff
`examples demonstrate how advances in technology can be
`lead to IOR. The importance of designing a well “from the
`reservoir up” and integrating drilling, logging, completion and
`stimulation design is clearly illustrated.In the short term, the
`EPS phase of these projects resulted in the recovery of nearly
`20 million barrels of oil, which could not have been
`economically produced several years
`ago.
`In addition,
`approximately 120 billion barrels of reserves were added to
`these two company’s assets.
`
`Conclusions
`
`1. The Soehlingen case history demonstrates that economic
`production can be achieved from deep, low penneability
`reservoirs through application of fracturing technology in
`horizontal wells.
`
`2.
`
`.3.
`
`The Joanne case history illustrates the importance of
`evaluating a project “as a whole“. What might have been
`viewed as all increase in completion costs. was more than
`offset by reductioll ill drilling and stilnulation costs.
`The high relief chalk case histories confirm the NPD
`definition of IOR. Technological advances allowed these
`marginal
`fields
`to be economically produced in the
`l990’s, nearly 20 years after initial discoveries.
`4. The importance of designing a well “from the reservoir
`up" and integrating drilling,
`logging, completion and
`stimulation design is clearly illustrated.
`
`Acknowledgments
`In many ways, it is not fair for me to be the only author on this
`paper. Although I have been involved to some extent in all of
`the case histories presented,
`I can not ignore the significant
`contributions of my colleagues at Halliburton and some of the
`customers who have been instrumental
`in these projects’
`success. These people have often provided guidance and
`many stimulating conversations.
`In particular, I would like to
`mention Klaas van Gijtenbeek, of Halliburton’s EuroFrac
`Team, and the researchers at Halliburton’s European Research
`Centre.
`I would also like to thank the crew of the Skandi
`
`Fjord with whom it has been my pleasure to work with and
`learn from on many projects. Last but not least, special thanks
`to both Ibrahim Abou-Sayed and Wadood El Rabaa, Mobil,
`botll of wholn have helped to expand my expertise from
`acidising into hydraulic fracturing.
`
`References
`l. Economides, M. and Ogle, K.C.: “Horizontal Wells: Completion
`& Evaluationz, PE307 Petroleum Engineering 519931 IHRDC.
`2. de Pater, C.J., et.al.: “Propped Fracture Stimulation in Deviated
`North Sea Gas Wells”, paper SPE 26794 presented at
`the
`Offshore European Conference, Aberdeen, September 7-10,
`1993.
`
`“Fracture Stimulation of Horizontal
`3. Baumgartner, W.E., et.al.:
`Well
`in a Deep, Tight Gas Reservoir: A Case History from
`Offshore The Netherlands", paper SPE 26795 presented at the
`Offshore European Conference, Aberdeen, September 7-10, 1993.
`4. Rylance, M., et.al.: “Novel Fracture Technology Proves Marginal
`Viking Prospect Economic, Part I Implementation of Fracture
`Treatrnents”, paper SPE 36472 presented at the Annual Technical
`Conference and Exhibition, Denver, CO, October 6-9, 1996.
`5. Haidar, S., et.al.: “Novel Fracture Technology Proves Marginal
`Viking Prospect Economic, Part II Well Clean-Up, Flowback and
`Testing”, paper SPE 36473 presented at the Annual Technical
`Conference and Exhibition, Denver, CO, October 6-9, 1996.
`6. Brinkman, F.W.:
`"Status report on fracturing of deep and low
`permeability formations in West Germany," paper SPE/DOE
`9852, presented at the SPE/DOE Low Pemleability Symposium,
`Denver, Colorado, May 27-29, 1981.
`7. Bleakley, W.B.: "Mobil AG scores with massive frac," Pet. Eng.
`I_ntL, (Jan. 1984), p 72-83.
`
`604
`
`Page 6 of 11
`Page 6 of 11
`
`

`
`SPE 49523
`
`ENHANCED PROFITABILITY WITH NON—CONVENTlONAL IOR TECHNOLOGY
`
`“Fraced horizontal well shows
`Schueler, S. and Santos, R.:
`potential ofdeep tight gas”, Oil& Gas J. (Jan. 8, 1996) pp. 46-53.
`Pust, G. and Schamp, J.: “Soehlingen Z10: Drilling Aspects ofa
`Deep Horizontal Well for Tight Gas”, paper SPE 30530 presented
`at
`the Offshore Europe Conference. Aberdeen, Scotland,
`September 5-8, 1995.
`“Well
`.v\;
`l\l.\\".. and Grossm:m.
`Chambers,
`l\l.R.,
`l\lueller,
`Completion Design and Operations for it Deep llor'i7.ontul Well
`with ;\lultiple Fractures", paper SPE 311-117 p1‘L.’SC11lCtl at
`the
`Offshore Europe Conference, Aberdeen. Scotland. September 5-
`8, I995.
`Fracture
`1-Iydraulic
`“Multiple
`et.al.:
`I.S.,
`Ahou-Sayed,
`Stimulation in a Deep Horizontal Tight Gas Well“, paper SPE
`30532 presented at
`the Annual Technical Conference and
`Exhibition, Dallas, TX, October 22-25, 1995.
`for Mobil,"
`"Halliburton F