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Summary Coalbed methane (CBM) wells usually are dewatered with sucker rod orprogressive cavity pumps to reduce wellbore water levels, although not withoutproblems. This paper describes high-volume artificial-lift technology thatincorporates specifically designed gas-lift methods to dewater Black Warrior CBM wells. Gas lift provides improved well maintenance and productionoptimization by the use of conventional wireline service methods. Introduction Since 1971, CBM wells have been dewatered by conventional artificial lift. To date, Black Warrior basin wells typically have been produced by either rodor Moyno pumps, with few problems. Wells usually are drilled from 1,000 to2,500 ft deep, with some reaching 6,000 ft. Water has been produced inside 27/8-in. tubing, while methane gas has been produced up the annulus. Productionranges from 50 to 1,000 BWPD (averaging 300 to 350 BWPD). The wells generallyrequire 3 to 12 months to dewater. The inherent requirement of a Black Warrior basin completion is that thebottomhole flowing pressure (BHFP) across the coal seams (desorption pressure)must be about 5 to 10 psi. The most effective installation meets this objectiveat an acceptable cost. Many wells in the basin first arc brought on line by single-point injectionof air down the production string. This allows the well to be cleaned of anyremaining sand or coal fines and to reach a lower fluid production rate in lesstime. Upon reaching this rate, the well can be placed on pump lift. A large number of wells are scheduled for completion over the next fewyears, many at greater depths than reached previously (3,500 to 4,500 ft). Artificial-lift technology commonly used in conventional wells now can beapplied to CBM wells to maximize efficiency and recovery while minimizingoverall costs. Historical Experience Over the past few years, gas lift has been introduced to CBM's in Alabama asan alternative method to dewater wells. Gas-lift technology first was used inthe Black Warrior basin in 1984. A principal method of gas lift still in use is single-point injection (Fig.1). One of the first methods to unload oil and gas wells, this technique notonly assists in unloading the well but also can help remove fracture sand andcoal fines from the wellbore before completion. Experience with conventional wells has shown that this procedure is quiteinefficient. procedure is quite inefficient.The rig must be maintained atthe wellsite until the rods have been installed, while it might be betterutilized elsewhere if a more effective lifting system completed the well fromthe start. The rig's air supply must be sufficient to turn the fluid aroundand bring the water back to surface. Such a compressor not only is costly butalso keeps the rig from its primary job. Gas production and bottomholepressure (BHP) cannot be monitored effectively during production. With airinjected down the tubing and air and water returning up the annulus, the casingand tubing are subject to significant, perhaps irreparable, corrosion damage ifair is injected for a prolonged period. The well cannot be watered downeffectively before being placed on a rod pump. If the operator simply startsinjection at a higher point with a "macaroni" -type injection system andadds tubing as required to inject more deeply into the wellbore, a rig will berequired. Conventional casing-flow gas-lift installations also have been tried withgas injected down the tubing through conventional gas-lift valves that arestrategically spaced in the string. Fluid and injected gas are produced up theprimary annular area, while coal-seam gas is produced up the secondary annulararea (Fig. 2). Although considerable fluid is produced, this installation has several shortcomings.Conventional gas-lift valves are a permanent part of the tubing string. As the well is unloaded, production first passes through the ported section ofthe unloading valves. Production fluid often contains coal fines that cut outthe stem and seat. As the well is unloaded to the next operating valve, amultipoint injection failure will occur because of damage to the uppervalve(s). This failure sharply curtails fluid lift efficiency and consumesexcessive quantities of lift gas. Valves cannot be retrieved and repairedwithout the tubing being pulled and a completion workover performed. Theinstallation would cost more than would a conventional rod or gas-liftinstallation. The secondary annulus requires 7-in. minimum casing ID, while theprimary casing string must be 51/2 in. The installations discussed will produce large volumes of water, but neitheris a truly economical or effective gas-lift system. By comparison, asignificantly modified gas-lift completion was developed that allows theoperator to dewater a well efficiently. This installation (Fig. 3) yields thelifting efficiency and capacity of a standard gas-lift completion under theunique conditions of the Black Warrior basin. The completion requires onlystandard oilfield equipment:a side-string side-pocket mandrel (Fig. 4), wireline-retrievable gas-lift valves, a reeled-tubing injection string, and conventional wireline tools. Black Warrior basin wells produce water up the tubing and methane up theannulus. Because of the low desorption pressures required and coal seam spacingvarying from 1 to 2,000 ft, a packer-type completion is out of the question. With a typical gas-lift completion, lift gas cannot be injected down theannulus into the tubing string and still attain the required BHFP. A new methodwas used to direct gas to the desired injection point while keeping the annulusopen for gas production. Reeled tubing was used with side-pocket mandrels in a design that allowedlift gas to be injected selectively into the tubing string. The side-pocketmandrels have ]-in. pockets to accept wireline-retrievable gas-lift valves. These mandrels are designed to provide a full tubing ID. Valves may be servicedthroughout the life of the well without a well workover. These features allowthe operator luxuries not currently available.BHP surveys are better without the concern for the accuracy of soundingdevices. Problem valves can be identified and replaced as required. Valves are not affected by downhole conditions inherently detrimental to pumpinstallations, reducing concerns with fracture sand, coal fines, and rod pumps. Fluid production may be altered by adjusting the injection-gas volume orpressure. SPEPE p. 379
- North America > United States > Mississippi > Yalobusha County (1.00)
- North America > United States > Mississippi > Winston County (1.00)
- North America > United States > Mississippi > Webster County (1.00)
- (35 more...)
Summary This paper describes the impact that thermally induced fracturing (TIF) hashad on the North Sea Ula field injection wells, allowing higher thananticipated water injection rates to be achieved. This work also discusses howthermal stress reduced fracture propagation pressures by 2,000 psi and how a 3Dsimulation code developed to model TIF was used. Injection-water-qualityspecifications and techniques to optimize TIF are presented. presented. Introduction The performance of all the Ula field water-injection wells has been stronglyinfluenced by TIF, a phenomenon reported and modeled in several reservoirs. Thepractical consequences of TIF depend on several factors, which are discussed inthis paper and have resulted in different behaviors in individual Ula wells. After more than 8 months of successful injection with the first injector (WellA-03), a second injector (Well A-04) was started up in mid-Nov. 1988. Thiswell, however, achieved an injection rate of only 18,000 B/D at the maximumavailable injection pressure. This was not unexpected considering the poorerreservoir quality at this reservoir location than at Well A-03, but work was toidentify means of improving well performance. After several weeks of stableinjection, the performance of Well A-04 improved very rapidly. The injectionrate increased by 6,000 B/D and the injection pressure decreased by 70 psiwithin a 15-minute period. During a second, slower, increase in performance 3days later, the period. During a second, slower, increase in performance 3 dayslater, the injection rate built to 29,000 B/D. However, the injection pressureremained at the same level as a week before when the rate had been 18,000 B/D. Both events correlated with drops in injection-water temperature resulting fromoperational changes. Further examples are given for a variety of wells and areex-plained in terms of TIF. These follow a description of the Ula field, theinjection hardware, and an introduction to the theory and modeling of TIF. Finally, the impact of TIF on operations is discussed. Fig. 1 gives an overviewof each well's performance and shows the timing of events that are the mostsignificant to performance and shows the timing of events that are the mostsignificant to our understanding of Ula injection-well behavior. Ula Field Reservoir Description. The Ula field is an undersaturated oil reservoirlocated in Block 7/12 of the Norwegian sector of the North Sea, about 180 milessouthwest of Stavanger. The reservoir lies in laterally extensive Upper Jurassic shallow marine sandstones formed in a four-way-dip, closed domalstructure. It consists of several upward-fining sequences that are grouped intofive reservoir zones-Zones 1A, 1B, 2A, 2B, and 3A-from the top downward. Thesezones are characterized by rock properties resulting from perceived changes insea level. The individual zones correlate across the perceived changes in sealevel. The individual zones correlate across the field but thin away from thecrest. Horizontal and vertical pressure communication is good, althoughporosity and permeability both deteriorate downdip. Of the reserves of 435million STB, 115 million STB was produced from seven wells between fieldstartup in Oct. 1986 and the end of June 1990. Six water injectors have beendrilled to supplement the negligible aquifer support. All injectors werecompleted directly above the oil/water contact to maximize recovery whileavoiding the poorer-quality reservoir farther downdip. Fig. 2 shows the welllocations on the reservoir structure. The reservoir crest is about 10,825 ftbelow sea level, and the reservoir is hot, with an average temperature of 295degrees F. Reservoir pressure has fallen by about 3,800 psi from the initial7,110 psig. psig. Injection Hardware. All injection wells were deviated from asingle platform and completed with 7-in. tubing. The design specification forthe platform and completed with 7-in. tubing. The design specification for theseawater injection system was to deliver 120,000 B/D at a wellhead injectionpressure (WHIP) of 3,000 psig. The discharge pump characteristics allowedhigher manifold pressures at lower rates early in the field life when few wellshad been drilled. Two additional pumps were added 3 years after field startupto boost the pressure into two of the low-rate wells (Well A-05 and A-08)drilled in the poorer-quality reservoir. The response of Well A-08 to thehigher injection pressure is discussed later. Fig. 3 is a schematic of theinjection hardware. A side of the injection water was originally passed througha heat exchanger to cool produced oil before being remixed with the remainderof the injection water. Increasing the water temperature to 104 degrees Fimproved deoxygenation efficiency, and cooling of the process fluids aidedoptimization of gas/liquids recovery. The water leaving the heat exchanger waslater dumped overboard to lower the overall injection-water temperature to aid TIF. The water-quality specification originally required removal of 98% ofparticles greater than 2 m by fine filtration but was subsequently relaxed. TIF Theory. Rock at depth is compressed by high levels of stress in bothvertical and horizontal directions. When the pore pressure of the fluid in therock exceeds this compressive stress, a fracture forms. Rock toughness, whichmust be overcome when the fracture is first formed, can increase the fractureinitiation pressure by 500 to 1,000 psi above the minimum compressive stress. At Ula depth, vertical stresses exceed horizontal stresses, so the fractureforms in the vertical plane. However, cold-water-injection wells often arefractured at bottomhole injection pressures (BHIP's) lower than the originalminimum compressive horizontal stress because of a reduction in the compressivestress in the rock surrounding the wellbore caused by cooling. This process offracturing cooled rock at injection pressure less than the in-situ stress isknown as TIF. The minimum compressive horizontal stress in Ula, before coolingor pressure depletion, is about 10,500 psig. However, as demonstrated later, pressure depletion, is about 10,500 psig. However, as demonstrated later, fracturing occurs at pressures below the maximum BHIP of about 8,500 psigavailable from the injection wells. When rock around the wellbore is cooled byinjection water, it tends to contract, shrinking away from the hot rocksurrounding it. This sets up tensile stress in the cooled rock and reduces theinitial rock compressive stress. The thermoelastic stress reduction may reach11 psi/degrees F of cooling. It increases linearly with temperature change anddepends on the shape of the cooled region and the rock properties. Additionaltensile stresses resulting from poroelasticity, which occur in regions wherereservoir pressure is reduced, can aid fracture initiation. Horizontalcompressive stresses are rarely homogeneous and can be resolved into orthogonalminimum and maximum. The fracture will open against the direction of leastresistance, perpendicular to the direction of least compressive stresses. Therefore, it propagates parallel to the direction of maximum horizontalin-situ stress. Fig. 4 shows the fracture orientation and position relative tothe horizontal stress directions and injection front. Fracture initiation atthe wellbore is expected to occur at the point where stress reduction isgreatest. P. 384
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.94)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Zechstein Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019B > Block 2/1-3 > Gyda Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
Summary Through a variety of field examples, this paper describes how increased production rates were obtained from gas-lift wells. These results were achieved through a wide range of activities, including special training for production operators, optimizing gas injection rates, modifying surface piping systems, identifying and replacing defective wireline-retrievable gas-lift valves, and improving gas-lift design techniques. A major modification of a standard gas-lift design technique is discussed in detail. The modification optimizes the depth of gas injection throughout the life of a well. An empirically derived chart, which relates valve spacing to the PI of a well, is also presented. Introduction The Teak, Samaan, and Poui oil fields lie between 12 and 25 miles [20 and 40 km] off the east coast of Trinidad, as shown in Fig. 1. Ten drilling platforms and three central field production platforms have been set in a water depth of 180 ft [55 m] to develop these fields. The producing formations are mainly Pliocene Age sandstones. Measured depths of wells range from 4,000 to 12,000 ft [1200 to 3660 m], and average hole angle sometimes exceeds 50 degrees Sand production is a problem, and the majority of wells are gravel-packed. Oil production began from the Teak and Samaan fields in 1972 and from the Poui field in 1974. By Dec. 1984, 85 % of the 111 producing oil wells were on gas lift, and production from these wells represented 78% of the total daily oil and condensate production of about 100,000 B/D [15 900 m3/d]. A total of 165 MMscf/D [4.7 ร 10(6) std m3/d] of gas-lift gas was needed to maintain this level of oil production. About 75% of the gas came directly from high-pressure gas wells, while the remainder was supplied by semiclosed rotative compressor systems. The available gas injection pressure was 1, 150 psi [7930 kpa] in Samaan, 800 psi [5520 kPa] in Teak, and 850 psi [5860 kPa] in Poui, During 1984, special attention was paid to optimizing production from gas-lifted oil wells. As Fig. 2 shows, this made a significant contribution to the reversal of a declining production trend. Comparing individual well tests from Jan. and Dec. 1984 shows a total of more than 6,000 B/D [950 m3/d] of increased oil production through gas-lift optimization. Although less readily quantified, it is believed that, as a result of the introduction of improved gas-lift design techniques, the production from new wells and workovers was also greater than might otherwise have been possible. Gas-Lift Production Optimization Optimum production from gas-lifted wells was achieved through a comprehensive approach to the problem. Education. An experienced consultant was engaged to present a school on gas-lift operations. An important aspect of this school was that it was held on site at Galeota Point, so both engineers and field production personnel could attend and discuss local field examples. Well-Performance Analysis. An extensive program of flowing-pressure- and temperature-gradient surveys was came out to identify the potential for increased production. After analysis of these survey results, oil production increases (of more than 10% for some wells) were quickly achieved, simply by correctly adjusting the gas injection rate. Valve Replacement. Performance analysis also indicated the need for wireline work. The flowing-pressure-gradient survey of Samaan Well C-7 in April 1984, for example, showed that gas was being injected through the second valve at 3,400-ft [1035-m] true vertical depth (TVD), yet there was adequate injection pressure to unload below the third valve at 4,700-ft [ 1430-m] TVD, as shown in Fig. 3. The valves were wireline retrievable, 1 1/2 -in. [38.1-mm] OD, set in 3 1/2-in. [88.9-mm] nominal OD sidepocket mandrels. It was decided that the second and third valves should be replaced and the test-rack opening pressure, for at 60 degrees F [15.5 degrees C] of the new second valve set 10 psi [68.9 kPa] higher to encourage it to close. Numerous wireline trips into the well, several improvised tool modifications, and 3 working days were required to carry out the work on this 5-year-old, deviated-hole completion. As a result, however, oil production increased by more than 650 B/D [100 m3/d] and gas-lift gas consumption fell by more than 500 Mscf/D [14.6 ร 10(3) std m3/d]. Had the original design incorporated an additional mandrel at 5,500 ft [1676 m], production could have been even higher. Having more mandrels does not necessarily ensure a better design, as Fig. 4, the flowing-pressure-gradient survey of a 7-year-old completion in Samaan Well B-1, reveals. One more mandrel at 5,200-ft [1585-m] TVD would have done much more for the well than the eight below 6,000-ft [1,830-m] TVD. It is the correct anticipation of the approximate depth of continuous injection that is important. The flowing-pressure-gradient survey in Samaan Well B5 (Fig. 5) revealed another common problem. All valves had 3/16-in. [4.8-mm) ports. A single valve could not pass the 1,700 Mscf/D [48.1 ร 10(3) std m3/d] of gas-lift gas required by the well, so the result was inefficient multipoint injection over the large depth interval covered by the top three valves. The third valve was replaced with a valve having a 7/16-in. [11.1-mm] port. Production subsequently increased by more than 300 B/D (48 m3/d) of oil, and the injection-gas requirement was reduced by 500 Mscf/D [14.16 ร 10(-3) std m3/d]. Gas-Lift Gas Distribution and Measurement. Inaccurate measurement and control of the gas flow rate to each well was an obvious handicap to production optimization. The gas flow rate to an individual well could not be measured in some existing distribution systems, except by shutting off the supply to the well and recording the drop in total flow rate to the platform. More recently installed distribution manifolds incorporated a loop line with an orifice meter through which the flow to any individual well could be directed, while gas to other wells flowed unmetered directly to the wellheads. In both cases, the valves isolating the individual flowlines from the main distribution header or from the loop line eventually developed leaks owing to wear and tear through regular use. To overcome this problem, all wells now have their own orifice flange meter tube, located between the distribution manifold and the wellhead. Surface Flowing Tubing Pressure. Various efforts were made to reduce surface flowing tubing pressures. In some wells, known to have a scale problem, reduced bore choke bodies and reverse-flow check valves were removed from the well flowline. Flowing tubing pressure typically dropped by 5 to 10 psi [35 to 70 kPa], but any resultant change in production rates fell within the range of normal fluctuations in well test results and was therefore difficult to establish. The most successful solution, where practical, was to "twin" the 4-in. [101.6-mm] well flowline from the wellhead area to the production header, a distance that varied from 15 to 50 ft [4.6 to 15.2 m], depending on the slot occupied by the well. SPEPE P. 135^
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Atwater Valley > Block 140 > Claymore Field (0.99)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > TSP Block > Teak Field > Moruga Formation > Gros Morne Formation (0.94)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > TSP Block > Samaan Field > Moruga Formation > Gros Morne Formation (0.94)
- (5 more...)
Summary. An innovative high-pressure N2 gas-lift design has been used to return several wells to production in the Jay/Little Escambia Creek (LEC) field of northwest Florida. The N2 was available from a field tertiary in injection project and provided the means for the first continuous N2 lift system, and some of the deepest gas-lifted wells in operation. The design accommodates the unique demands of gas-lifting a deep, sour oil well with high water cuts through the operation of a continuous N2 lift system. Because the project design was not limited to conventional artificial lift techniques, a solution was achieved with the resources available. The high-pressure N2 lift enabled wells to return to production that would not have been economically attractive or mechanically feasible with a standard hydrocarbon gas lift or submersible pump design. Introduction The Jay/LEC field, located in the Florida panhandle and south Alabama (Fig. 1), has been in production since 1970. The production fluids contain 10% H2S and flow from the Smackover production fluids contain 10% H2S and flow from the Smackover formation at a depth of 15,500 ft [4275 m]. In 1981. a tertiary oil-recovery project was initiated that used high-pressure N2 injection. The system consists of a compressor station designed to compress 67 ร 106 ft3 [1.9 X 106 m3] of N2 and to distribute the high-pressure gas through a series of field flowlines to targeted injection wells. The high-pressure injection helps maintain field reservoir pressures and enhances oil recovery, but several of the producers were identified as being partially or totally isolated from any tertiary response and were shut in because of a combination of increased water cuts and the lack of downhole pressure support. The solution involved tapping the high-pressure tertiary N2 laterals as an unusual source for a lifting gas. The high-pressure lift required several innovative measures, including modifications for valve spacing and valve setting pressures. Special metallurgy and safety features were necessary for producing the sour fluids, and a casing pressure relief system was installed to relieve the tubing/casing annulus from any excessive pressures. N2 Gas Lift The Jay/LEC field consists of 127 wells, including 40 injection wells. The EOR project initiated in 1981 uses high-pressure N2 as a miscible agent for oil displacement. A compressor station compresses N2 up to 7,000 psi [48 MPa] and feeds it through a series of high-pressure flowline laterals to tertiary injection wells throughout the field. Various N2 profiles left several areas isolated from receiving any tertiary support. These wells had died from an increase in water cuts but were not seeing the increases in reservoir pressure support expected from the N2 injection. As a result of a combination of permeability and field position, these wells had significant secondary permeability and field position, these wells had significant secondary reserves that would not be captured unless the wells were returned to production. Because the estimated date for a tertiary breakthrough was several years away, if at all, there were also accelerated reserves that increased the profitability of the project. Several artificial-lift methods were reviewed as alternatives to return some of these wells to production. A conventional gas-lift design was not economically attractive because of the well depths and field size. The producing intervals are below 15,500 ft [4725 m], with water cuts ranging from 50 to 95%. The sales gas pressure of 950 psi [6.6 MPa] would have to be boosted considerably pressure of 950 psi [6.6 MPa] would have to be boosted considerably to optimize the lift design for operating depths capable of maintaining a continuous lift at the present water cuts, as well as the increased water cuts expected in the future. The targeted wells were several miles from the treating facility, so flowline purchase and installation costs were considerable. A submersible pump design was also studied, but the packoff requirements, depth of operation, and H2S concentration made such a proposal impractical. Jet pump designs that use fresh water as proposal impractical. Jet pump designs that use fresh water as the circulating, fluid had been tried, but they could not be successfully sealed off inside the existing production string. The proposed solution was to design a gas-lift system using the high-pressure N2 available from the field tertiary injection project. The project included a series of 7,000-psi [48-MPa] N2 laterals that fed targeted injection wells throughout the field. This gas would provide a high-pressure lifting medium for the required depth of operation provide a high-pressure lifting medium for the required depth of operation and was easily accessible from the field lateral installations. A closed-loop design was possible through the field tertiary project's nitrogen rejection unit. This facility would enable all the project's nitrogen rejection unit. This facility would enable all the N2 to be separated from the produced gas through a series of six "cold" boxes operating at supercryogenic temperatures. The high percentage of N2 in the produced gas could then be recycled to percentage of N2 in the produced gas could then be recycled to the compressors and reinjected as lifting gas, providing the only closed-loop N2 gas lift in operation. Few data were available, however, on gas-lift designs fed by a high-pressure N2 source. The design data and computer simulator programs normally used for company gas-lift designs all used hydrocarbon gas as the lifting fluid. Being a heavier gas (0.97 specific gravity) with a different compressibility, N2 presented a much different injection gas gradient and required corrective factors to be applied to the simulator models. As Fig. 2 shows, the N2 gradient is heavier than a hydrocarbon gas gradient, allowing for a wider valve spacing. High-Pressure Design Injection-Pressure Limitations. Because of the uncertainties involved in lifting with high-pressure gas down the production casing/ tubing annulus, 3000 psi [21 MPa] was chosen as the operating injection pressure. This pressure provided for a minimum safety factor of 2.8 in the casing burst analysis, allowing for a substantial corrosion allowance. This was an important factor because many of the casing strings had been in corrosive service for 8 to 10 years. Obviously, a 7,000-psi [48-MPa] injection would be ideal, allowing the 15,200-ft [4630-m] operational depth to be reached in one or two steps. The decision was made, however, that the additional safety afforded by 3,000-psi [21-MPa] injection was worth the added cost of two or three more gas-lift mandrels. The design could be optimized because the 3,000-psi [21-MPa] injection pressure would still provide a high enough pressure for a pressure would still provide a high enough pressure for a lifting depth of 15,200 ft [4630 m] under the worst expected conditions. This is the deepest possible gas-injection depth. A deep gas-injection depth minimizes the injection gas volume required to reach the mininmum flowing gradient, providing for the maximum drawdown at the perforation depth. SPEPE P. 100
- North America > United States > Florida (0.24)
- North America > United States > Alabama (0.24)
Summary A completion technique for steam-injection wells that ensures improved profile distribution of steam into several independent sands is being used at the South Belridge field in California. Previously, steam profiles were poor for many of the conventionally perforated (two 3/8-in. profiles were poor for many of the conventionally perforated (two 3/8-in. [9.5-mm] -diameter holes per foot) injection wells. This standard completion does not guarantee that the thicker, higher-permeability sands will not act as thief zones with respect to the thinner, tighter sands open in the same wellbore. Limited-entry perforating (typically one hole per 15 to 20 ft [4.6 to 6.1 m] of gross interval with at least one in each major sand member) provides the best assurance of achieving a uniform injection profile in single-wellbore multisand completions. profile in single-wellbore multisand completions. Introduction The South Belridge field, located in Kern County, CA, was discovered in 1911. The Tulare formation is steamflooded to recover 13 degrees API 10.98-g/cm ] oil from at least seven independent unconsolidated sands at depths ranging from 400 to 1,300 ft [122 to 396 m]. For steamflooding purposes, the reservoir has been divided into two zones of approximately equal thickness: the Upper Tulare (Sands A through C) and the Lower Tulare (Sands D through G) (Fig. 1). Each zone is steamed and produced independently. All projects newly installed by Shell California Production Inc. are developed on 5-acre [2-ha] patterns with inverted nine- or five-spot geometry. patterns with inverted nine- or five-spot geometry. Three steam-injection well completion designs have been used (Fig. 2):openhole, gravel-packed, slotted-liner completion, cased to total depth with two 1/8-in. [9.5-mm] -diameter perforations per foot, and cased to total depth with 1/4-in. [6.4-mm] -diameter limited-entry perforations. All injection wells installed before the Shell perforations. All injection wells installed before the Shell Oil Co. acquisition were completed with open hole, were gravel packed, and had slotted liners. Efficient profile control with these multisand completion wells is extremely difficult; consequently, many sands were not effectively steamed and produced (Fig. 3). The initial injection wells installed by Shell California Production Inc. were cased to total depth and perforated Production Inc. were cased to total depth and perforated with two 3/8-in. [9.5-mm] -diameter holes per foot in the desired injection intervals. However, this design did not eliminate the possibility of a poor injection profile when thick, higher-permeability sands were opened with thinner, lower-permeability stringers in the same wellbore. The use of limited-entry perforations in steam-injection wells was briefly mentioned in 1975. Limited-entry perforating was first tested in Shell's portion of the South perforating was first tested in Shell's portion of the South Belridge field in Sept. The marked improvement in injection profile has made it the exclusive completion scheme for all new Tulare injection wells.
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > United States > California > San Joaquin Basin > San Joaquin Valley > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > Belridge Field (0.99)