This pawr was prepmwcf for pmsentafion at the t998 sPGDOE Improved oil Recoww SwnposRttm held in Tulsa, Oklahoma, f9-22 April 19!38, his papar was selected for presentation by an SPE Program Comm"tiee following review of information confained in an absf roct submfttckf by the author(s). Contents of the paper, as presented, hava not been revfewed by fhe %&fy of Petroleum Engineers and are subject to .xmucifon by the authoi[s). I'fffi nmtwfal, as pr&mted, does not necessanfy reflect any pcdion of the Society of PefroIeum Engineer8, ifs ofiicem, or members. Papers presented at SPE meetings am subJecf ?O pubficafion re@ew by Mforial Commiffeea of the Society of Petroleum Engineers. Efecfronic reproduction, distniution, or storage of any part of this paper for commerclat purposes wffhouf the wrfften consent of the Society of Petroleum Engineers is prohibied. Permission to reproduce In prfnf Is restricted to an abstract of not more fhan 300 words illustrations may not ba copied. The abstract must contain conaplcuoua acknowfedgmon~of%%=e~ntf by whom the papar was presenf ed. W rite Librarian, SPE, P.O. Box 833838, Richardson,~7S083-3E3S, U. S.A., fax 01-972-952-9435.Abstract"

This paper summarizes the conceptual development, reservoir simulation, and field testing of a new miscible EOR recovery process at Prudhoe Bay. Two distinct variations of this process 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. It also creates a mobilized oil bank in the vicinity of the production well. The well is then recompleted at the top of the reservoir and returned to production service. It is particularly advantageous to utilize this vertical drive process in conjunction with horizontal wellbores. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or 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 indicate that the vertical MIST process could recover over 200 Mstb of incremental oil per well at initial rates of up to 1000 stb/D. Calculations for the lateral MIST process indicate potential recovery of more than a million barrels of incremental EOR per lateral. Field results have been mixed, but are encouraging. The vertical well MIST showed litfie response, but it did provide valuable insight into the performance of the MIST process. Incremental EOR from the three MIST lateral wells is over 1.3 MMstb, with current rates of about 4000 stb/D. P. 249

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe North Slope of Alaska has billions of barrels of heavy oil residing in largely undeveloped reservoirs. Despite this large volume of heavy oil in place, the majority of reserves development on the slope to date has been focused on light crude. However over the past 20 years Arco, BP, Conoco and now ConocoPhillips have begun to develop the North Slope's vast heavy oil resource base. Recently a sand/solids control study was undertaken by ConocoPhillips and BP in order to determine the most economic strategy for solids control and well design in future heavy oil developments.The study was integrated across companies, organizations and discipline boundaries in order to include completion, rock mechanics, laboratory research, drilling, reservoir, geological, operations, facilities and field personnel. With this diverse team, actual solids production and solids predictions were investigated from a number of different perspectives. Solids production predictions were made based on core measurements, log analysis, simulators that predict formation failure and sand production rate, laboratory core flow tests, 2 years of field shakeout data, and multiple field measurements of solids production. Probabilistic predictions were then generated based on these investigations rather than deterministic "best guesses" for the economic analysis. These different methods for predicting solids production will be discussed and illustrated in this case study.The study and ensuing strategy determined that sand management or using non-sand exclusion slotted liners and sand tolerant facilities was the highest value development scenario over the life cycle of the North Slope Heavy Oil Developments.

Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River Unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped due to the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy oil resource are primarily technology and favorable economics. This paper is focused solely on the technology hurdles. Development of heavy oil in the Arctic represents a significant departure from conventional oil developments on the North Slope as well as established heavy oil developments elsewhere in the world. The combination of low well rates, high costs, and arctic conditions require a sustained commitment to developing new approaches for unlocking the resource. To progress this opportunity BP initiated an appraisal program involving resource characterization, production pilots, and development screening. This paper describes early appraisal results from a cold heavy oil production with sand (CHOPS) flowback and multi-zone drill-stem testing to obtain quality reservoir fluid samples.

Summary This paper summarizes the conceptual development, reservoir simulation, and field testing of an unconventional application of the miscible enhanced oil recovery (EOR) process at Prudhoe Bay. The miscible injectant stimulation treatment (MIST) process involves completing a well at the bottom of a thick, continuous, watered-out interval. A horizontal lateral is drilled along the base of the reservoir, and 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. 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 indicate that each MIST well could recover up to 1,000 MSTB of incremental oil at initial rates of up to 1,000 STB/D. Field results have been encouraging. Incremental EOR from the three MIST lateral wells is over 2.1 MMSTB, with peak production rates of about 6,000 STB/D. Background The Prudhoe Bay field, located on the north coast of Alaska, is the largest oilfield in North America, with total estimated reserves of roughly 13 billion barrels and a current production rate of approximately 700 MSTB/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 enhanced oil recovery (EOR) operations at Prudhoe Bay, which are confined to the downstructure and peripheral areas of the field, are producing roughly 300 MSTB/D. Prudhoe Bay EOR began in late-1982 with an 11-pattern pilot project. The Prudhoe Bay Miscible Gas Project (PBMGP) was initiated in 1987, and now consists of about 130 patterns (Fig. 1). The patterns are typically inverted nine-spots with 80-acre well spacing. The PBMGP currently has a miscible injectant rate of over 500 million scf/D at an average water-alternating-gas (WAG) ratio of about 3:1. 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 (FS-2) area, these shales create up to four completely isolated flow intervals. Fig. 2 is a detailed map of the FS-2 area showing the MIST wells. A type log of this area is shown in Fig. 3. MIST Concept 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, since 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 thoroughly documented 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, solvent did not contact the bottom 100 ft of the interval. Simulation studies showed that recovery could be increased by utilizing 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-section map of oil saturation showing the increased sweep due to 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 wellwork complicated the analysis, but it appears that the large MI slug was responsible for over one million barrels 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, then perforating near the base of the reservoir. A large slug of MI (from 1 to 4 Bscf) is injected at high rates (about 40 MMscf/D). The solvent slug is followed by a short period of water injection, which insures 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. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or injection well. MI is injected sequentially into several intervals (MI "bulbs") along the lateral to mobilize EOR oil in unswept areas. Because gravity segregation is dominant, the MI can sweep a much larger reservoir volume by injecting at full well rates into each bulb separately, rather than injecting MI along the entire length of the well at once. This results in multiple point sources, each of which has a high viscous-to-gravity ratio (VGR), rather than a single line source with a low VGR. Each slug of MI is about 3 Bscf, and is injected as quickly as possible (typically about 30 MMscf/D). Each solvent slug is followed by a short period of chase water injection. After injection for each interval is completed, a bridge plug is set and the next interval is perforated. The lateral well is then returned to normal production or injection service. Fig. 6 illustrates both MIST processes.