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Prudhoe Bay field

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The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America.[1][2][3][4][5] The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains > 20 × 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6°API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).

Although the field was discovered in 1968, because of its remote location, first production did not begin until 1977 after an oil pipeline across Alaska to the southern port of Valdez was built and extensive oilfield facilities were installed. The initial facilities had a gas-handling capacity of about 2 Bcf/D to separate and compress the produced gas for reinjection into the updip gas cap. For the regulated oil production rate of 1.2 × 106 BOPD, this was sufficient for more than the first decade of field operations. No gas pipeline has been built from the North Slope of Alaska that would enable production of the gas.

Reservoir characteristics

The permotriassic-aged Ivishak (also known as Sadlerochit) reservoir, the largest producing horizon in the field, is a series of clastic zones ranging from near-shore marine deposits in the lower sections to sandstones and conglomeratic braided-stream deposits in the remaining, more productive units that contain most of the original oil in place (OOIP). The reservoir is a structural stratigraphic trap consisting of a faulted, south- and southwestward-dipping, 1 to 2° homocline. The reservoir is bounded on the north by major faults and on the east by a major lower Cretaceous truncation. The productive area is 225 square miles.

The main and western areas contain gas caps with different gas/oil contacts (GOCs). Both have an oil/water contact (OWC). The reservoir has an average thickness of more than 500 ft (1600 m). Average rock and fluid properties include

  • Porosity of 22%
  • Initial water saturation (Swi) of 35%
  • Net-to-gross ratio of 0.87
  • Oil gravity of 28° API
  • Oil viscosity of 0.8 cp

Permeability averages 500 md and ranges from <100 md in the western area and the deeper deltaic sands up to several darcies in some of the open-framework conglomerate deposits. While the reservoir is connected to a sizeable aquifer, rock properties degrade rapidly off structure, and the light oil column is separated from the aquifer in portions of the field by a heavy-oil tar mat.

The primary-depletion mechanisms were

Development history

The initial spacing of 320 acres per well was quickly reduced to 160 acres per well and then further reduced to 80 acres per well to sustain production levels and contact more of the reservoir.

Waterflooding (planned as part of the original development plan) was started in conjunction with the 80-acre infill-drilling program. Source water was obtained from the Beaufort Sea. Inverted seven- and nine-spot injection patterns were used in areas of the oil column not overlain by the gas cap.

The gas-cap cycling project was begun in 1977. Gas-handling facilities subsequently were expanded three times and reached a capacity throughput of 8.0 Bcf/D by the late 1990s.

An enriched-hydrocarbon miscible (methane with propane and butane added) water-alternating-gas (WAG) injection project was initiated in 1983 with the Flowstation 3 Injection Project. This was expanded to additional areas of the field in 1987. Fig. 1 shows the type of recovery mechanisms being managed in various parts of the field.

Immiscible gas displacement

Immiscible gas/oil displacement has been the production mechanism at work over much of the Prudhoe Bay oil column (Fig. 1), and waterflooding and miscible water-alternating-gas (WAG) processes have been used in the very downdip portions of the oil column. More recently, horizontal wells are being used nearer the gas-oil contact (GOC) to exploit the thin oil columns that cannot be drained with existing wells. During the first decade of operations, the original gas cap had expanded to drape over much of the oil column area, but the producing GOR was kept low by perforating the production wells as far as possible, both vertically and laterally, from the gas cap. By the mid-1980s the engineers determined that maintaining the oil production rate depended on expanding the field’s gas-handling capacity. Two major projects were undertaken. First, a central gas facility was constructed to strip the produced gas of many of the hydrocarbon components for sale as blendable NGLs and for use as miscible injectant. This project also increased the field gas handling capacity to 3.3 Bcf/D. The second project was a sequence of gas-handling facility expansions that increased overall capacity to > 7.5 Bcf/D.

The reinjection of residue gas served two purposes.

  • It maintained reservoir pressure, which helped increase oil recovery; the reservoir pressure declined only by ≈1,000 psi (from 4,300 to 3,300 psi) during the production of the first 10 × 109 bbl of oil.
  • The very lean residue gas has vaporized large amounts of hydrocarbon components from the relict oil saturation in the original gas cap[6] and from the remaining oil behind the gas/oil front.

Simulations showed that the vaporization mechanism would contribute recovery of an additional 4 to 6 STB/MMcf of additional gas produced.[1] During the past 15 years, the average API gravity of the marketed Prudhoe Bay hydrocarbon liquids has increased by > 5°API.

Gas shutoff gel treatment

Sanders, Chambers, and Lane[7] reported on 37 chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gel gas-shutoff treatments that were applied to 31 production wells in the 190 to 220°F reservoir of Alaska’s Prudhoe Bay field. It reported that these gas-shutoff gel squeeze treatments cost 75% of comparable Portland cement gas-shutoff squeeze treatments in this field and afforded a higher success rate. Sanders, Chambers, and Lane[7] also reported that these gel gas-shutoff treatments had been credited with a gross initial (one month of production) incremental oil production rate of 22,000 barrel of oil/day (BOPD) and that these gel treatments reduced gas production to 213 MMscf/D. Sanders, Chambers, and Lane[7] stated that “squeeze longevity has been greater than one year [to date] in some cases with drawdown pressures exceeding 1,500 psi.”

Enriched hydrocarbon miscible flooding

An enriched hydrocarbon miscible (methane with propane and butane added) water-alternating-gas (WAG) injection project started in 1983. The method for optimizing the WAG ratio has shifted with time. Initially, all patterns received a solvent injection (miscible injectant, or MI) of 1% of total pore volume per year. This scheme was changed to a tiered allocation process whereby the more efficient patterns received more MI. When implementation of most miscible injection patterns (149) was completed, the allocation scheme was changed again to direct MI to the most-efficient patterns (on the basis of a detailed analysis of field-performance data) using a binary method. All patterns are ranked in order of efficiency (production per volume of returned MI, or RMI), and solvent is allocated on a WAG ratio of 1 based on a pattern’s throughput until available MI is assigned. The less-efficient patterns are shut in until another reallocation is made. A workover to correct well problems such as flow behind pipe or to open new zones or decline in another pattern’s performance can result in a shut-in pattern being ranked higher and placed on the active list. Gas samples are routinely collected from production wells to measure RMI as part of the MI allocation process.

Estimated ultimate recovery in the main part of the field is more than 60% OOIP and 80% original condensate in place. Of the total oil recovery, the miscible contribution is 10% OOIP in affected areas. Because the miscible project was started early in field history, a primary-waterflood base production curve was not established to provide an estimate of incremental recovery because of miscible injection. The miscible contribution is based on saturation changes measured by logs run in observation wells and simulations that match actual performance. Also, both tracer and log-inject-log tests have been conducted, and specialized core data have been obtained to measure and improve the effectiveness of the WAG miscible project.

Waterflood and WAG pattern recoveries can be improved with more focus on the management of individual injector/producer pairs within the floods. The objective is to ensure better vertical and areal distribution of the injectant. Patterns with the best performance have recovered in excess of 70% of the OOIP, while the poorer patterns have recovered less than 50% OOIP.

Miscible injectant stimulation treatment

As would be anticipated in a high-quality sand with good vertical permeability, the miscible recovery process has been dominated by gravity forces. Rapid gravity segregation of MI away from the injection well prevents the MI from contacting a significant portion of the target waterflood residual oil, as illustrated in Fig. 2. As shown on the right, only a small portion of the reservoir is contacted in clean sand intervals typical of much of the miscible flood area. As shown on the left, shale lenses tend to mitigate gravity override, resulting in more of the reservoir being contacted. Both vertical and lateral miscible injectant stimulation treatment (MIST) processes[8] are being implemented to improve volumetric sweep. A vertical MIST process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of solvent is injected, followed by a small slug of chase water. The solvent sweeps rock not contacted by previous solvent injection.

In the lateral MIST process, horizontal wells are placed in the bottom of the overridden portion of the oil column to distribute injectant laterally (Fig. 3). A series of injection cycles (referred to as MI bulbs) can be scheduled along the horizontal wellbore to sweep more of the oil column in the pattern. After an MI bulb is complete, the perforations are isolated with a packer or sand, and new perforations are added for the next bulb.

Fig. 3 shows the production history of one producer in a lateral MIST pattern. There are distinctly recognizable production increases because of miscible injection. The first response was injection in MIST injector 9-31C, where production doubled above the base rate. The second response was injection in conventional WAG injector 9-39. The correlation between response and RMI is consistent with compositional simulation runs that show that the rapid response is caused by vapor phase transport. The more subdued response that occurs when liquid oil is displaced and banked by MI is more difficult to discern from other factors affecting producing rate.

Recovery efficiency

Haldorsen et al.[5] have studied the efficiency of the Prudhoe Bay gravity drainage mechanism by means of laboratory experiments and field cased-hole log evaluations. They concluded, "The ‘most likely’ displacement efficiency, through the stochastic approach, was 68 percent after three years and 76 percent after 30 years of gravity drainage."

Ultimate recovery

The ultimate Prudhoe Bay oil recovery has increased from initial estimates of 9.6 to 13 × 109 bbl oil, much of which is related to exploiting the immiscible gas/oil gravity drainage and oil stripping mechanisms. This has been accomplished by massive expansions of the gas handling facilities and extraction of the maximum volume of blendable NGLs from the produced gas stream. Application of the immiscible gas processes at Prudhoe Bay has been aided by the lack of alternative uses or markets for the produced gas.

References

  1. 1.0 1.1 1.2 Simon, A.D. and Petersen, E.J. 1997. Reservoir Management of the Prudhoe Bay Field. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38847-MS. http://dx.doi.org/10.2118/38847-MS
  2. Metz, W.P. and Elliot, R.A. 1991. Gas Handling Expansion Facilities at Prudhoe Bay, Alaska. Presented at the International Arctic Technology Conference, Anchorage, Alaska, 29-31 May 1991. SPE-22113-MS. http://dx.doi.org/10.2118/22113-MS
  3. Addington, D.V. 1981. An Approach to Gas-Coning Correlations for a Large Grid Cell Reservoir Simulator. J Pet Technol 33 (11): 2267-2274. SPE-8332-PA. http://dx.doi.org/10.2118/8332-PA
  4. Erickson, J.W. and Sneider, R.M. 1997. Structural and Hydrocarbon Histories of The Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field. SPE Res Eng 12 (1): 18-22. SPE-28574-PA. http://dx.doi.org/10.2118/28574-PA
  5. 5.0 5.1 Haldorsen, H.H., Rego, C.A., Change, D.M. et al. 1985. An Evaluation of the Prudhoe Bay Gravity Drainage Mechanism by Complementary Techniques. Presented at the SPE California Regional Meeting, Bakersfield, California, 27-29 March 1985. SPE-13651-MS. http://dx.doi.org/10.2118/13651-MS
  6. Dyes, A.B., Caudle, B.H., and Erickson, R.A. 1954. Oil Production After Breakthrough as Influenced by Mobility Ratio. J Pet Technol 6 (4): 27-32. SPE-309-G. http://dx.doi.org/10.2118/309-G
  7. 7.0 7.1 7.2 Sanders, G.S., Chambers, M.J., and Lane, R.H. 1994. Successful Gas Shutoff With Polymer Gel Using Temperature Modeling and Selective Placement in the Prudhoe Bay Field. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25–28 September. SPE-28502-MS. http://dx.doi.org/10.2118/28502-MS
  8. McGuire, P.L., Spence, A.P., and Redman, R.S. 2001. Performance Evaluation of a Mature Miscible Gasflood at Prudhoe Bay. SPE Res Eval & Eng 4 (4): 318-326. SPE-72466-PA. http://dx.doi.org/10.2118/72466-PA
  9. 9.0 9.1 McGuire, P.L. and Holt, B.M. 2003. Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary. SPE Res Eval & Eng 6 (1): 17-27. SPE-82140-PA. http://dx.doi.org/10.2118/82140-PA

Noteworthy papers in OnePetro

Simon, A.D. and Petersen, E.J. 1997. Reservoir Management of the Prudhoe Bay Field. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38847-MS. http://dx.doi.org/10.2118/38847-MS

Szabo, J.D. and Meyers, K.O. 1993. Prudhoe Bay: Development History and Future Potential. Presented at the SPE Western Regional Meeting, Anchorage, Alaska, 26-28 May 1993. SPE-26053-MS. http://dx.doi.org/10.2118/26053-MS

McGuire, P.L. and Stalkup, F.I. 1995. Performance Analysis and Optimization of the Prudhoe Bay Miscible-Gas Project. SPE Res Eng 10 (2): 88–93. SPE-22398-PA. http://dx.doi.org/10.2118/22398-PA

Wingard, J.S. and Redman, R.S. 1994. A Full-Field Forecasting Tool for the Combined Water/Miscible Gas Flood at Prudhoe Bay. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25–28 September. SPE-28632-MS. http://dx.doi.org/10.2118/28632-MS

Dawson, A.G., Jackson, D.D., and Buskirk, D.L. 1989. Impact of Solvent Injection Strategy and Reservoir Description on Hydrocarbon Miscible EOR for the Prudhoe Bay Unit, Alaska. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. SPE-19657-MS. http://dx.doi.org/10.2118/19657-MS

McGuire, P.L. and Holt, B.M. 2003. Unconventional Miscible EOR Experience at Prudhoe Bay: A Project Summary. SPE Res Eval & Eng 6 (1): 17-27. SPE-82140-PA. http://dx.doi.org/10.2118/82140-PA

Weaver, J.W. and Uldrich, D.O. 1999. Optimizing Solvent Allocation in the Prudhoe Bay Miscible Gas Project. Presented at the SPE Western Regional Meeting, Anchorage, Alaska, 26-27 May 1999. SPE-54615-MS. http://dx.doi.org/10.2118/54615-MS

Cockin, A.P., Malcolm, L.T., McGuire, P.L. et al. 2000. Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas Flood at Prudhoe Bay. SPE Res Eval & Eng 3 (6): 544-551. SPE-68051-PA. http://dx.doi.org/10.2118/68051-PA

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