This paper describes the conceptual development, reservoir simulation, and field testing of a new miscible enhanced oil recovery (EOR) technique at Prudhoe Bay. Two distinct variations of this technique have been evaluated.
The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers.
In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production well or an injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.
Simulation data indicated that the vertical MIST process could recover more than 200,000 STB of incremental oil per well at initial rates of up to 1,000 STB/D. Calculations for the lateral MIST process indicated potential recovery of more than 1 million bbl of incremental EOR per lateral.
Field results of the MIST process have been mixed but are encouraging overall. Incremental EOR response from the first MIST lateral well through July 2000 was approximately 1,400,000 STB, resulting in a technical and economic success.
Response from three subsequent MIST lateral injectors varied widely. The first vertical well MIST showed little response, but it did provide valuable insight into the performance of the process at Prudhoe Bay. The subsequent vertical well MIST, which had a much larger volume of injected MI, was very successful and has currently recovered over 1,100,000 STB. Cumulative incremental EOR from the MIST wells through July 2000 was more than 5,000,000 STB, with average incremental oil-production rates of approximately 4,000 STB/D. Based on these successful results, an ongoing program of additional MIST wells is planned.
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 barrels and a current production rate of approximately 600,000 STB/D. The field is overlaid 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 with an 11-pattern pilot project (Fig. 1). The Prudhoe Bay Miscible Gas Project (PBMGP) was initiated in 1987 and now consists of approximately 160 total patterns.1–5
Typically, the patterns are inverted nine-spots with 80-acre well spacing. Approximately half the patterns are suspended for either mechanical reasons or EOR process maturity. The PBMGP currently has a miscible injectant rate of approximately 400 MMscf/D into roughly 80 active EOR patterns at an average water alternating- gas (WAG) ratio of about 1:1. MI composition varies somewhat, with a typical composition of 20% CO2, 35% C1, 19% C2, 23% C3, and 3% C4. The MI has a minimum miscibility pressure of roughly 3,300 psi at 220°F. Average reservoir pressure is approximately 3,400 psi, while formation temperature in the PBMGP ranges from 170 to 235°F.
The Sadlerochit Group, the major productive interval of the field, includes a thick section composed of high-permeability fluvial sands and interbedded shales. In the Flow Station 2 (FS2) area, these shales create up to four completely isolated flow intervals. Fig. 2 is a detailed map of the FS2 area showing the MIST wells. A type log of this area is shown in Fig. 3.
The Victor hydraulic interval, consisting of Zones 2B, 2C, 3, and part of 4A, is typically about 150 ft thick with few, if any, extensive shales or other vertical permeability barriers. MI is injected throughout the section, while producers are typically completed near the top of the reservoir because the bottom is completely watered out. The WAG flood is strongly gravity-dominated, with rapid vertical segregation of the MI. Horizontal flow in the reservoir is dominated by very thin, extremely high-permeability thief zones, which usually occur in the upper half of the Victor. The MI sweeps oil near the injection wellbore but leaves large areas of the reservoir unaffected.
The actual MI sweep efficiency in the Victor was determined by coring Well 3-18A and has been documented thoroughly in a previous paper.1 A history-matched, fully compositional reservoir simulation of WAG in the Victor showed a very limited area in which EOR oil was actually mobilized. Although the entire interval was open to injection, the bottom 100 ft of the interval were not contacted by solvent. Simulation studies showed that recovery could be increased by using an optimized WAG process. In this optimized WAG, a large MI slug is injected into the bottom 20 to 30 ft of the Victor interval. The entire interval is then perforated for subsequent WAG cycles. Fig. 4 is a cross-sectional map of oil saturation showing the increased sweep caused by optimized WAG. This process was implemented in Well 3-18A, which received a 9.5 Bscf solvent slug between September 1994 and June 1995. Well 3-25A responded strongly, with incremental EOR rates of up to 2,000 STB/D, as shown in Fig. 5. Operational issues and well work complicated the analysis, but it appears that the large MI slug was responsible for more than 1 million bbl of incremental EOR production from the 3-18A pattern.
Even with the optimized WAG, most of the interval is not affected by MI. This unaffected area is the target for MIST. In the vertical MIST process, a production well is temporarily converted to injection by squeezing the perforations at the top of the Victor and then perforating near the base of the reservoir. A large slug of MI (from 2 to 8 Bscf) is injected at high rates (approximately 40 MMscf/D). The solvent slug is followed by a short period of water injection, which ensures safe well operations and drives the MI slug deeper into the reservoir. The bottom perforations are covered with sand or by a bridge plug, and the well is recompleted as a producer at the top of the Victor.