BAKER HUGHES INCORPORATED
`BAKER HUGHES INCORPORATED
`AND
`Exhibit 1020
`BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1020
`Page 1 of 11
`
`

`
`2
`
`MS. VAN DOMELEN
`
`SPE 49523
`
`Case Study 1: Germany's Soehlingen Wells
`
`The Reservoir. The Rotliegendcs formation includes several
`sands that are productive in Gennany. The Netherlands and
`the Sotttllcnl North Sea. Rotliegendes sands are Inassivc (up to
`[000 It _u_ross]I with moderate poi'osity [I0-I2”-o} and t_vpica|l_v
`lo\\ pct"meal‘:ilIty ll'2Il'L.'l_\_' above It} Ind and often as low as 0.lll
`llltl]. The pre.~;e|Ice (1l‘(ll£Igt2llt2llt.' illilo in the pore space is the
`c;nis;e for low penncahi|it_v. Reservoir tlcptli lends to increase
`Iiniu ca. 9.000 feet in the southern North Sea to |6.0[}0 Feet as
`
`the trend Inovcs cast into German_x,'. Permeability also tends lo
`decrease in the eastward direction. (.‘ouunei‘cial production of
`natural gas from these low permeability. deep members of the
`Rotliegcndcs formations requires completion with propped
`hydraulic
`fractures.
`Exatnples
`of
`sttccesslitl
`fracture
`stimulations in the North Sea Rotliegendes can be found in
`references 2 to 5. Fracture stimulation of the Rotliegendcs
`formation in Germany is complicated by the higher reservoir
`temperature (290°F) and increased stress levels due to depth
`{l5_'i'00 ft TV D) and reservoir pressure (8,700 psi).
`
`The History. Germany's first massive hydraulic fiacturing
`[Ml-ll‘)
`treatments were
`conducted in
`[977
`in BEl3'S
`Goldenstedt Z7 wcll.° 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 scfll).
`_A record—serting MHF treatment was conducted on the
`Hauptsandstcin of the Rotliegcndes formation in Mobil Oil
`AG‘s Soehlingen Z4 well in December of [9827 A total of l.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 Soehlingcn 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 ‘.|TlCl fonnation to be
`increased fi'om 1.2 MM scflD at 260 psi to 6.7 MM scf‘/D 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 ofthe
`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 of the treatments were
`not fully satisfactory. The average sustained production rates
`of-1.5 MM sct?'D proved uneconomical,
`
`and
`chilling
`in
`developments
`The Challenge. Recent
`completion Icclmolog_}- allowed for a totally new approach to
`the tlcvclopment ol' the Soclilingen Zlll well. The project's
`ohicctlve was to attain pI'odnclinn rules
`tioln a multiple
`fractured luirizonlal well that are three to the times the rates
`
`attainable limit a vertical. C(}lI\'t?]lT.l(ll]?lll}' liactliicd well.“ This
`translates to a sustained rate of about [3 MM sefi'D.
`
`Siinilar to the previous Sochlingcn wells. the target for this
`well was to treat
`the Hauptsandslein of the Rotliegendes
`formation. The Z10 well was drilled to a total vertical depth of
`l5,688 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 ofthe well is discussed in
`detail by Chambers, ei.aI.'” In the fall of I994, 2.3 MM lbs of
`intcnnediate 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 Pris."
`Two world records were set by this treatment: one for the
`deepest horizontal well drilled and the other for the deepest
`multiple fractilres.”'” Initial post-fracture production was 23
`Min scDD at a flowing tubing head pressure of 4,350 psi.
`After 2 years, a sustained production rate of IS MM scf"D at
`4,350 psi was achieved from all four fractures?’ This rate
`exceeded the original target rate and demonstrated that it is
`technically possible to drill, complete and have multiple
`stilnulations in long horizontal sections in a very deep, light
`reservoir under extreme high pressurefhigh 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 sutrunarizcd in Table 3.
`
`Examination of these three tables provides a good illustration
`of the technological advances made since 1982.
`Fracture 0pa'nu'zrm'tm. 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
`I
`for an illustration of transverse
`fractures in a horizontal wellbore. Production predictions for
`the Zl0 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
`
`Page 2 of 11
`Page 2 of 11
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`

`
`SPE 49523
`
`ENHANCED PROFlTABlLlTY WITH NOMCONVENTIONAL IOR TECHNOLOGY
`
`3 g
`
`discussed by Soliman, el.al."' Norris, et.al. provides a good
`overview of cturent
`technology for prediction of fractured
`horizontal performance.” Once the well was drilled and the
`reservoir’
`permeability more
`accurately
`known.
`linal
`uptiniimtioii inilicatcd an optinnnn hoi'i'/.ontal length of 2.000
`feel with foul‘ perpendicular li'acItu'es equally spacctl along the
`|rori'/.unl:i| section. The most elTecti\'e li'at:1urc length was
`helietetl to be Frill} fct:l. asstiririlig inlinilt: curitltitztirily. Talile
`l contains the results of |i'actuI'c (rc~]:aiinulalion.~:
`[1L2I'lill‘llIcLl
`\-rill‘: data
`[ruin the Z4
`and ZIU well
`Iiles.
`tlsing 2|
`connnercially available fracture simulator ll-"r'aci’ro).
`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 ofthe horizontal wellbore in the Zl0. It is of
`further
`interest
`to note that
`the calculated total
`pr'up_nct.-’
`fracture areas for the two wells are nearly identical. Yet the
`2.10 well
`significantly out-perfonned the Z4 well. This
`demonstrates that a fiactured horizontal well can eli'ecti\'ely
`cli'ain a larger area than a fracture vertical well.
`Perfiirtttirirt Con.t'ira'er.rm'0rr.s‘. Mitch research has been
`done on the optimization of perforations for horizontal well
`fracttiring.'fi"') Table 2 contains perforation details for the Z4
`and Zl0 wells- along with other relevant design and treatment
`data. A short perforated interval was used in the ZIO well to
`avoid the creation of multiple fractures. High shot density and
`large holes ensured that perforation skin effects would be
`mininrizecl. Extreme overbalance perforating?" was also used
`in the ZIO well to minimize fracture initiation presstnes. The
`fracture-specific perforation design was. combined with the
`placement of SSDS in the horizontal completion to allow the
`four fracturing treatments to be selectively placed and allow
`selective isolation and re-entry. These advances in perforating
`and completion technology contributed significantly to the
`ability to effectively fracture-stimulate the high-pressure
`intervals in the Z|0 well, Specific details of the perforation
`techniques used in the Zl0 well are given in reference 10. A
`simplified completion diagram is show in Figure 2.
`Flair! Crm.1':'derrrtiorr.r. Advances
`in
`fracturing fluid
`technologies
`allowed
`significantly
`higher
`proppant
`concentrations to be placed in the Zl0 well. (See Table 2)
`This contributed to a reduction in fluid volumes and allowed
`
`more efficient packing of the tinctures. Tip Screen Out {T30}
`designs“ were used to provide additional conductivity in the
`near wellbore area, the portion .of fi'actI.ire 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 minimum 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 II. The lluid fonnulation used in the Z10
`well represented one of the most aggressive tests of borate
`cliemistry to date. This is due to the high BIIT [290°F} and
`high coliccntratioris ofcurahle resin coated proppant (up to l2
`ppg). Both of tliesi: [actors are known to :1dvci'.~aely ellect the
`stability of horntc llnirls as well as the pei'llu'rri:Iricc of high
`tr.-nipemttm:
`l)l'C£ll(I.:t'.‘i.
`l3:il:ineing the lluirl
`.N'lItl1llll}'
`(luring '
`puinpirig and the rapitl hreak time \vas a lcchnienl challenge in
`the Zltl well and would not
`l1(l\'L‘ been pussililc with the
`lDCllllt1lttg_)‘
`that was
`a\':iil:tl}lt: wliclt
`the
`'/.-l well was
`completctl.
`Pmpprrmt Iierrrilv. The fracturing treatment on the Z4 used
`high-strength sintercd bauxite. Even though high quality
`intermediate strength ceramic (ISC) 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 [SC
`
`in the Zl0 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 baclt-pl'0CllICllCln. The desire to use RC propparrt with
`a borate fluid necessitated additional testing as high pH fluids
`can adversely affect
`the ultimate
`compressive strength
`obtained with curable RC proppants. 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-
`tempcrature 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
`Trerrmierrr Executr'rm.
`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
`slugsw“ 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-time
`monitoring of the bottom hole treating pressure allowed
`greater confidence in executing the T80 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 I I.
`
`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 tirnes
`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
`from very low permeability gas
`reservoirs. Above all, this represents a breakthrough for the
`future development of light gas reservoirs.“
`
`Page 3 of 11
`Page 3 of 11
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`

`
`4
`
`M.S.\i'AN DOMELEN
`
`SPE 49523
`
`Case Study 2: Phillips UK's Joanne Field
`
`The Reservoir. The .luclyr'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 ofa 24-
`slot platfonn for Jud)‘ and a
`l2-slot subsca template for
`.loaune. Wells in the Joanne produce priInaril_v from Dauirut
`sediments with the iutertals of iI'.IcI'est the likolisk and Tor
`
`chalks. These fonnrttions tend to be snll. Reservoir prcssut'e is
`=':'.ll00 psi 'at1dteInpe1'at1ire is 2~l0°F. Depth ram__vcs litun 9.000
`to l l_000 ii. Experience with other North Sea cltalks showed
`that extensive acid stimulation programs are required in order
`to achieve commercial production rates.‘i5':7 Each chalk well
`would
`contain multiple
`producing
`intervals.
`Selective
`placement of the acid stimulatious was therefore critical to the
`success of the project.
`
`The History. Phillips’ original plan was to drill up to I2
`deviated. wells, however, because drilling horizontal wells
`would allow a reduction in the nulnber 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 stimulations, 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 altematit-"e
`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 3'ears.2°‘m 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
`afier the previous zone. Simplicity, rig savings and stimulation
`cost reduction were the primary driving factors during the
`design stage.
`
`The Solution. An innovative completion design that allows
`rapid, multiple
`stimulations
`(fracture or matrix)
`to be
`perforrned in horizontal wells was developed. Specific system
`details are given by Thomson and Nazaroo.” This field-
`proven system allows acid stimulation of up to I0 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
`nin 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 si_de 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\-IS.-\l-'
`completion. each well was peifotntctl
`\\'llll
`luhin_t,'-convc_vctl
`perforation {TCP} grins. Multiple packers were spacer! out in
`order to isolate the zones to be slimulzttetl. The completions
`were run in one trip to the safety valve and pa-:l~:ers were set
`sin1u|taneousl_\' (up to ten packers at a time!) .-\|"ter all
`the
`surface equipment was
`installed.
`the
`lower most pump
`outfcycle plug was expelled and stimulation operations were
`ready to commence.
`.5'rr'mu!trt'r'mt of the MT. The first well, Ml _ was completed
`and stimulated by the Big Orange XVIII in August I994. A
`total of 200,000 gallons of 28% H Cl 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 continttous.
`The pump rates were reduced to 5 BPM to lubricate each ball
`into the wellbore. The pnmp- 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.
`Srr'm:rIm‘iwt of the M5. Provisional treatment designs for
`the following three wells required 320,000 to 390,000 gallons
`of 28% HC I 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 retum 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 maximum.” Individual ptunp 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.
`
`Srinurlrtrion aftlie M4 rim! M3. It was decided that the M4
`and M3 would be
`treated with both vessels pumping
`simultaneously. The use of l4 pumps, at the same time, would
`lessen the strain on each pump and reduce the consequences of
`
`Page 4 of 11
`Page 4 of 11
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`

`
`
`
`ENHANCED PROFITABlL|TY WITH NON—CONVENTlONAL IOR TECHNOLOGYSPE 49523 5
`
`
`
`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 4
`
`contains a summ2u'_v ofthc total time to install completions and
`earn’ out the stimulalions on the tour .loaune wclls.
`
`tie|tl—proven i|rl’l1i|lips'
`tool was lirst
`Results. The h|S.—\l-‘
`Joanne Field. One 7—zone completion and three
`I0-zone
`completions were run in the summers ol‘ I994 and I995. Large
`volumes of fluid. 300,000 gallons of 28% HCI a11d l30_000
`gallons of gelled pad were selectively placed. An additional
`I0-zone completion was installed in Phillips’ Hewett 48129-
`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 (E\/C} 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 1970's. The best known are Phillips’
`Ekofisk, A1noco's Valhall and Maerslfs 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-l9?0’s, marginal fields were discovered in
`this area, however,
`technology at
`the time did not allow
`colnmercial development. One of the first marginal fields to be
`developed was State-il's Tommeliten Field. This project, a
`subsea development in water depth of 250 ii, is based upon the
`use of existing infrastructure of the Ekofisk Complex.
`Completion and stimulation of the conventional deviated wells
`took place during the
`summer of
`1988.21 Stimulation
`programs, which consisted of alternating stages of crosslinked
`pad and gelled acid diverted at high rates with ball sealers,
`were very successful. Today the Tommcliten 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
`
`wells 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.
`arcliilccunc and inadequate stimulaiimi.
`tiehls dirl not have the hen-zlil
`tit‘ an existing infrastructure.
`whieli cmnplicuterl :u1d delayed tlcvelopnient.
`
`The Rt-‘servuir. Two lields will he discussetl: both have a
`similar Llescription. The reservoirs consist of fracttircd chalk
`adjacent to a large salt diapir. The zones otiiutcrest include the
`El-colisk and Tor. The bull: ofthe reserves lie in the tight chalk
`matrix with production coming from the natural
`fracturér
`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 (TV[)} can range from 3,500 to 7,500 ft. Bottom hole
`temperatures range from I90 to 220°F, depending upon TVD.
`The reservoirs are slightly overpressured with initial gradients
`of about 0.58 psilft at
`the top of the structure and fluid
`gradients of 0.28 to 0.30 psifft in the reservoir. Identification
`and stimulation of the primary natural fracture networks is
`considered crucial to the success of the developI'nenls_
`
`The Results. Many advances in tecluiology 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 while 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 Cl€\-'ClD[JlTlEt‘ll,'“"‘s
`Finally,
`the
`integration of
`completion and stimulation
`design delivered the high
`productivity essential for economic development. “H”
`B!’ Mr:c'I:nr. Located in Block 23i'26a of die UK sector of
`
`the Nort.h 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,"""“ Details of the well design and
`stimulation treatments
`in the Machar are presented by
`Gilchrist. stat.-‘° 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;"fi'acture 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
`
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`6
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`M.5. VAN DCIMELEN
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`SPE 49523
`
`posed the risk of either damaging or ‘‘missing'' the natural
`fractures,
`the cemented liner approach was selected based
`-upon wellbore stability studies and resen'oir management
`considerations. Although it was recognized that a water-based
`lI'IllLl was preferred to an oil-based one (from a formation
`tlntnagc viewpoint). drilling problems on an earlier well
`iicccssitatcd the switcli to an oil-based tnnd system.
`|\lassi\'e acid li'acluring treatments were perfonncd on the
`i\|ui:|1:n' liiz and 205' wells in the Sll!‘Itlt1Cl'S of I99-l and I995.
`I'c.~:pccti\'ely. The treatment design was very similar to the
`approach that had been used successfully in the Tonuneliten
`Field.” Specific attention to the execution and evaluation of
`the Machar stimulation treatments was given by Lietard, et.
`al.“ Examination of Table '2’ shows some very interesting
`highlights from 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 132 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
`sltowecl a record increase in PI” but also resulted in sustained
`average production rates of 23,000 BOPD and the production
`of 14.6 million ban'els over the 21-month project.”
`results
`(fmmco Bmrflf Encouraged by
`the
`positive
`achieved by BP in the Machar EWTIEPS; Conoco and
`partners entered into Phase l of the Banif development
`in
`Blocks 29r‘2a and 22f2?a in the summer of 1996. Phase 1
`
`consisted of two stratigrapliically horizontal production wells
`and one truly holizontal water injection well. The drilling,
`completion and stimulation strategies
`for
`the two Banff
`producers were almost identical to the BP Machar plans, with
`the exception being that recent advances in 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 3,200 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 I.” First oil from Phase II is scheduled for June,
`I998.
`
`Improved Recovery. The BF 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 illustratedln 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 [20 billion barrels of reserves were added to
`these two compar1y’s assets.
`
`Conclusions
`
`l.
`
`The Soehlingen case history demonstrates that economic
`production can be achieved from deep, low permeability
`reservoirs through application of fracturing technology in
`horizontal wells.
`
`'4.)
`
`2. The Joanne case history illustrates the importance of
`evaluating a project “as a whole". What might have been
`viewed as an increase in completion costs. was more than
`offset by reduction in drilling and stimulation 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
`1990'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 Ha1liburton’s EuroFrac
`Team, and the researchers at Hallibur1on'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,
`both of whom have helped to expand my expertise from
`acidising into hydraulic fracturing.
`
`References
`l. Econornides, M. and Ogle, K.C.: "Horizontal Wells: Completion
`& Evaluationi, PE307 Petroleum Engineering! 1993} I]-IRDC.
`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 Fracttire
`Treatments”, paper SPE 36472 presented at the Annual Technical
`Conference and Exhibition. Denver, CO, October 6-9, 1996.
`S. Haidar, S., et.al.: “Novel Fracture Technology Proves Marginal
`Viking Prospect Economic, Part 11 Well C]ean—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 fonnations in West Germany," paper SPEIDOE
`9352, presented at the SPFJDOE Low Penneability Symposium,
`Denver, Colorado, May 27~29. 1981.
`7. Bleakley, W.B.: "Mobil AG scores with massive frac,“ Pet. Eng
`l_1'_t§l_., (Jan. 1984}, p 72-83.
`
`Page 6 of 11
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`SPE 49523
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`ENHANCED PROFITABILITY \t‘li'lTH NOMCONVENTIONAL IOR TECHNOLOGY
`
`10
`
`I5.
`
`“Fraced horizontal well shows
`Schueler, S. and Santos, R.:
`potential of deep tight gas”, Oil_& Gas .1. (Jan. 8, 1996) pp. 46-53.
`Pust, G. and Sch-amp, J.: “soehlingen Z I 0: Drilling Aspects of a
`Deep Horizontal Well for Tight Gas“, paper SPE 305 30 presented
`at
`the Offshore Europe
`(‘c-nference. Alierdecn, Scotland,
`September 5-8, I995.
`“Well
`.-\'.
`i\l_\\-'_ and (ii'tissttitti1.
`Cltrtmbers,
`l\I.l{., Mueller,
`('un1p|ction D-.'si:__-n and Operaliotts liar