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Enriched hydrocarbon miscible flooding case studies

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While enriched hydrocarbon projects are less frequent, these types of projects have been very successful miscible floods when adequate supplies of methane and enriching fluids are available and profitable to inject.

Two case studies of enriched hydrocarbon projects show the field experience:

Prudhoe Bay field

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 productive area is 225 square miles. Production began in 1977.

The reservoir is a structural stratigraphic trap consisting of a faulted, south- and southwestward-dipping, 1 to 2° homocline. 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

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.

Miscible flood specifics

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[11] 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.

Piercement Salt Dome field

This field is composed of upper- and lower-faulted, unconsolidated sands that dip away from the salt dome at 65 to 85°. Porosity averages 26.5%, and permeability is 1.3 darcies. Oil gravity is 38°API.

This project is operated as a gravity-stable hydrocarbon miscible flood. The injection rate corresponds to a velocity of roughly one-half the critical velocity required for gravity-stable operations. A volume, corresponding to 17% PV, of enriched gas [natural-gas liquids (NGLs) plus solution gas] was injected, followed by injection of solution gas alone. When injection is completed, blowdown of the gas cap is expected to recover approximately 90% of the enriched gas and a significant portion of the injected solution gas, thus reducing the effective cost of the solvent.

Constant pressure is being maintained to improve recovery by eliminating shrinkage of oil over the course of displacement. Coreflood experiments gave recoveries similar to those predicted by the simulations. Miscible residual oil saturation in corefloods was 7% of pore volume(PV). Slimtube experiments also were carried out to determine the MME required to achieve miscibility at a given pressure level. An minimum miscibility pressure (MMP) was then selected consistent with the volume of enriching NGL available for the project.

Primary production occurred through gas-cap expansion. Miscible-gas injection began after a short primary-production period. Estimated ultimate recovery is

  • 50% of OOIP for primary recovery in both sands
  • 74% for total recovery after miscible flood in the lower sand
  • 86% total recovery after miscible flood in the upper sand

These recovery levels were determined by tracking gas fronts with pulsed neutron capture (PNC) logging and performing material balance calculations. These recovery levels are consistent with predictions based on simulations. To date, conformance has been excellent, with field recoveries quite similar to those seen in corefloods.

Routine pressure measurements, PNC logs, and pressure-transient testing are used to monitor reservoir performance and contact movements and to identify areas of good and poor communication. Pressure was initially allowed to decline to slightly above the MMP and was then maintained by scheduling injection volumes equal to production. Pressure maintenance became a challenge because of increasing gas/oil ratio (GOR) that resulted in water-cut increases and reservoir pressures below the MMP in some areas. Pressures were increased and maintained by curtailing production from high-GOR wells.

Pressure communication between injectors and producers has been good in the upper reservoir. In the lower reservoir, pressure communication between wells has been sporadic because of faults and shale barriers that act as baffles between injectors and producers.


  1. 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.
  2. Jerauld, G.R. 1997. Prudhoe Bay Gas/Oil Relative Permeability. SPE Res Eng 12 (1): 66–73. SPE-35718-PA.
  3. 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.
  4. 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.
  5. 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.
  6. 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.
  7. 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.
  8. Sneider, R.M. and Erickson, J.W. 1994. Rock Types, Depositional History, and Diagenetic Effects, Ivishak Reservoir, Prudhoe Bay Field. SPE Res Eng 12 (1): 23–30. SPE-28575-PA.
  9. 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.
  10. 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.
  11. 11.0 11.1 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.
  12. 12.0 12.1 12.2 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.

Noteworthy papers in OnePetro

Moulds, T. P., McGuire, P. L., Jerauld, G., Lee, S.-T., & Solano, R. (2005, June 1). Pt. McIntyre: A Case Study of Gas Enrichment Above MME. Society of Petroleum Engineers. doi:10.2118/84185-PA

Reinbold, E.W., Bokhari, S.R., Enger, S.R. et al. 1992. Early Performance and Evaluation of the Kuparuk Hydrocarbon Miscible Flood. Presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, 4-7 October. SPE-24930-MS.

Winter, B.T. and Edwards, K.A. 1995. Reservoir Management and Optimization of the Mitsue Gilwood Sand Unit #1 Horizontal Hydrocarbon Miscible Flood. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October 1995. SPE-30725-MS.

Pritchard, D.W.L. and Neiman, R.E. 1992. Improving Oil Recovery Through WAG Cycle Optimization in a Gravity-Override-Dominated Miscible Flood. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24181-MS.

Hoolahan, S.P., McDuffie, G.S., Peck, D.G. et al. 1997. Kuparuk Large-Scale Enhanced Oil Recovery Project. SPE Res Eng 12 (2): 82-93. SPE-35698-MS.

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See also

Miscible flooding

Compositional simulation of miscible processes

CO2 miscible flooding case studies

Nitrogen miscible flooding case studies

Designing a miscible flood