Performance Evaluation of a Mature Miscible Gasflood at Prudhoe Bay
- P.L. McGuire (Arco Alaska Inc.) | A.P. Spence (Arco E&P Technology) | R.S. Redman (Arco Alaska Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2001
- Document Type
- Journal Paper
- 318 - 326
- 2001. Society of Petroleum Engineers
- 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.1 Waterflooding, 5.6.5 Tracers, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 5.1.5 Geologic Modeling, 1.6.9 Coring, Fishing, 5.4 Enhanced Recovery, 5.3.4 Reduction of Residual Oil Saturation, 5.1 Reservoir Characterisation, 5.4.9 Miscible Methods, 1.10 Drilling Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 4.1.9 Tanks and storage systems, 5.5 Reservoir Simulation, 5.4.3 Gas Cycling, 5.5.2 Core Analysis, 1.6 Drilling Operations, 5.6.1 Open hole/cased hole log analysis, 4.1.5 Processing Equipment, 5.4.2 Gas Injection Methods, 4.1.2 Separation and Treating, 5.6.2 Core Analysis, 5.5.8 History Matching
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This paper summarizes the acquisition, conventional and compositional core analysis, and reservoir-simulation history match of a core taken roughly 300 ft from a production well in the most mature area of the Prudhoe Bay Miscible Gas Project (PBMGP). Compositional analysis of the core yielded a great deal of in-situ enhanced oil recovery (EOR) performance data and provided insights that could not be obtained from routine core analysis or production data. Fine-gridded reservoir simulations yielded a good match of the offset well-production rates and the observed compositional behavior of the core. The simulations and core data showed a complex layered displacement with alternating intervals of stripped and enriched oil. The data showed that roughly 70% of the cumulative EOR came from reducing the residual oil saturation near the injection well. The remaining 30% was caused by oil swelling.
The Prudhoe Bay field, located on the north coast of Alaska, is the largest oil field in North America, with total estimated reserves of roughly 13 billion bbl and a current production rate of approximately 600,000 STB/D. The field is overlain by a large gas cap, and the majority of the field is being produced by gravity drainage. Waterflood and miscible EOR operations at Prudhoe Bay, which are confined to the downstructure and peripheral areas of the field, are producing roughly 200,000 STB/D.
Prudhoe Bay EOR began in late 1982. The Flow Station 3 Injection Project (FS3IP) was an 11-pattern pilot project in the Drillsite (DS) 13 area. The PBMGP was initiated in 1987 with 43 additional patterns. There are now about 160 total EOR patterns at Prudhoe Bay (Fig. 1). The patterns are typically inverted nine-spots with 80-acre well spacing. Approximately half the patterns are suspended either for mechanical reasons or for EOR process maturity. The PBMGP currently has a miscible injectant (MI) rate of about 500 MMscf/D into roughly 80 active EOR patterns at an average water-alternating-gas (WAG) ratio of about 1:1.
The Sadlerochit Group, the major productive interval of the field, includes a thick section composed of moderate- to high-permeability fluvial sands and interbedded shales.1 In the Flow Station 3 (FS3) area, the dominant pay interval is Zone 4, which is overlain by the nonpay Shublik limestone and the low-permeability Sag River sandstone. Although the Sag River is perforated in both injection and production wells in the FS3 area, it contributes very little production and receives very little injection at FS3, and it will not be discussed further in this paper. An extensive nonpay heavy-oil/tar (HOT) zone underlies the oil column and prevents aquifer influx in most of this area. Fig. 2 is a detailed map of the FS3 area showing the cored well. A gamma ray log cross-section of this area is shown in Fig. 3. Procedures for analyzing EOR performance have been described in detail in previous papers.2-4
Sidetrack Core Design
Well 13-06 was an original pilot injector with a cumulative MI volume of 17.0% total pore volume (TPV) injected from 1983 through 1997. The pattern was very mature, and Well 13-06 was at the end of its useful life as an injector. Engineering studies indicated that reconfiguring the injection pattern by converting side-well producer 13-05 to WAG injection would sweep portions of the reservoir that had not previously been contacted with MI. The average production of Well 13-05 was approximately 100 BOPD at water cuts of more than 98%. This conversion would serve as a pilot test to determine if pattern reconfiguration of a mature WAG flood in this part of the field was economic. However, Well 13-05 had severe mechanical problems and was not suitable for injection service. The cheapest option was to sidetrack the 13-06 injector to a location near the 13-05 bottomhole location. This sidetrack provided an opportunity to acquire cost-effective core data on miscible flood performance in this mature area.
As shown in Fig. 2, the 13-06 pattern contained Well 13-98, a fiberglass-cased observation well that has been the subject of previous papers.3,5 The core, when combined with the observation-well data, was expected to yield a very good evaluation of WAG performance in the 13-06/13-98/13-06A/13-05 cross section.
Well 13-06 was given one last, very large slug (4.0 Bscf, or 5.1% TPV) of MI to provide clear data on the solvent utilization efficiency at large cumulative MI volumes, and also to give a large EOR signal for the core. The large MI slug, which was injected from 15 March through 12 November 1997, produced very little additional oil, but it did produce a large volume of returned MI (RMI). Well 13-05 was produced until 10 November 1997. The last test on 8 November showed production rates of 347 BOPD with a gas/oil ratio (GOR) of 21 Mscf/STB and a water cut of 95%. RMI rates at that time were in excess of 6 MMscf/D. The incremental EOR response of several hundred STB/D was disappointing for such a large MI slug. Continued production at such modest oil rates would not significantly reduce the oil saturation in the 13-05 area. A proper analysis of the 13-06A core should therefore give an accurate assessment of the ultimate performance of the waterflood/EOR process in Zone 4.
A total of 244 ft of low-invasion conventional core was cut at the DS 13-06A sidetrack well over a 9-day period. Total core recovery was 243 ft (more than 99%). Five 60-ft aluminum core barrels were used. The core diameter was 4 in. A 30,000-ppm KCl mud with bentonite, starch, polymers, and calcium carbonate solids was used to obtain both low invasion and good shale stability. Mud weight was 10.5 ppg. Deuterium oxide (D2O) was used as a tracer to monitor filtrate invasion.
One 22-ft core was taken in the Sag River formation on 31 December 1997. Massive lost circulation problems were encountered for the next 4 days while drilling through the Shublik formation, with total losses of roughly 3,500 bbl of mud. All the D2O tracer was lost in the Shublik, so sodium bromide (NaBr) was used as the tracer in Zone 4. After the fluid loss was brought under control, a total of four Zone 4 cores were taken from 5 to 8 January 1998. The top 2 to 5 ft (uncertain) of Zone 4 were not cored in 13-06A because of concerns about the brittle pyrite interval jamming the core barrel. Coring rates in Zone 4 averaged 42 ft/hr. Directional surveys indicated that Zone 4 in the 13-06A sidetrack, which had a 9° hole angle, was roughly 300 ft from the 13-05 production wellbore and roughly 1,500 ft from the original 13-06 injection wellbore.
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