The Cambridge Minnelusa field alkaline-surfactant-polymer ͑ASP͒ flood was an economic and technical success, with ultimate incremental oil of 1,143,000 bbl at a cost of $2.42 per barrel. This success was due to an integrated approach of the application, including: reservoir engineering and geologic studies, laboratory chemical system design, numerical simulation, facilities design, and ongoing monitoring. This paper discusses how each of these was used in the design and evaluation of the Cambridge ASP project.

An alkaline-surfactant-polymer flood was initiated in September 1987 in the Minnelusa Lower "B" sand at the West Kiehl Unit. Subsequent to unitization, two producing wells were drilled outside the Unit boundary. While this extended the productive geologic interpretation of the field, it did not effect the Unit interpretation of the alkaline-surfactant-polymer flood. Production from primary and chemical injection into State 31-36 through November 1991 resulted in 517,521 barrels of oil (82,279 m3) from the Unit wells, of which 456,361 barrels (72,555 m3) were from the area swept by injection into State 31-36. The two Kottraba wells (north of the Unit) have produced 180,686 barrels of oil (28,727 m3) as of November 1991. The- original average oil saturation in the gross swept area was 71.8% PV (69.0% PV in stock tank barrels). The gross swept pore volume of the Unit is 1,294,800 barrels (205,857 m3). The oil recovery efficiency in the gross swept area as of November 1991 is 51.1% OOIP. Projected ultimate production from the gross swept area is 541,158 barrels of oil (86,037 m3)- or 60.6% OOIP. Projected ultimate production from the Unit is 602,318 barrels of oil (95,761 m3). This compares with a primary plus waterflood oil recovery estimate of 39.9% OOIP recovery for the West Kiehl Unit gross swept area. Comparison of the oil recovery efficiency of the West Kiehl with other Minnelusa waterfloods and polymer floods suggests the West Kiehl has out performed these other Minnelusa floods. Using the Slider technique, the displacement efficiencies of the areas swept by the State 32-36 and State 42-36 in the Unit and Kottraba Federal 2515 were 71.3%, 52.7% and 58.1%, respectively. Comparative efficiency factors for a waterflood in the Hamm Unit and a polymer flood in the OK Field are 28.5% and 45.6%. The West Kiehl, OK Field, and Hamm Unit are all Lower "B" Minnelusa Fields. A total of 184,794 incremental barrels of oil (29,380 m3) are projected for the Unit at an incremental cost of $393,458- or $2.13 per incremental barrel of oil ($13.40 per m3). No injected chemical production has been observed in the Unit wells- or the Kottraba wells as of November 1991. No changes in the Hall plot slopes were observed once a stable slope was achieved until water break through occurred at State 32-36. Alkali plus surfactant plus polymer was injected without damage to the Minnelusa formation.

This paper was prepared for presentation at the 1999 SPE Rocky Mountain Regional Meeting held in Gillette, Wyoming, 15–18 May 1999.

An alkaline-surfactant-polymer flood was implemented in the Tanner Field, Campbell County, WY, after waterflooding to a 43% oil cut. Tanner is a Minnelusa B sand with one injection well and two production wells. Primary production began in April 1991 with a waterflood starting in October 1997. Peak waterflood production reached 19,000 bbls oil per month in February 1999. Waterflood continued through April 2000 at which time oil production had declined to 9,500 oil bbls per month at an oil cut of 43%. In May 2000, an alkaline-surfactant-polymer solution was injected. A solution of 1.0 wt% sodium hydroxide plus 0.1 wt% active ORS-41HF plus 1000 mg/L Alcoflood 1275A dissolved in Fox Hills water was injected through January 2005. A tapered concentration polymer drive began in February 2005. Oil recovery through December 2005 is 1,013,944 bbls from the total field and 874,490 bbls from the floodable pore volume or 44% OOIP. Incremental oil to date is 199,670 bbls or 10% OOIP. Projected ultimate oil recovery is 65% OOIP. Ultimate waterflood oil recovery was calculated to be 48% OOIP. This paper will discuss all aspects of alkaline-surfactant-polymer flood implementation from the laboratory evaluations to the field. Chemical Enhanced Oil Recovery in the Minnelusa Minnelusa fields in the Powder River Basin have been chemical flooded for over 30 years. Polymer flooding began in the Minnelusa trend in 1972 at Stewart Ranch.[1,2] Mobility control, profile modification, and combination mobility control-profile modification floods have been applied to the Minnelusa fields in secondary and tertiary modes..[3,4,5,6] Alkaline-surfactant-polymer flooding began with a secondary application at the West Keihl field in 1988.[7,8] The Cambridge alkaline-surfactant-polymer flood was the second Minnelusa alkaline-surfactant-polymer flood also performed as a secondary application.[9] Other Minnelusa floods such as Mellott Ranch and Driscoll Creek implemented an alkaline-surfactant-polymer flood in a tertiary mode after years of waterflood. Tanner is unique in that alkaline-surfactant-polymer injection began after a short waterflood when the oil cut was 43%. Reservoir Description Discovered in 1991, Tanner produces a 21º API gravity crude oil with a viscosity of 11 cp at the reservoir temperature of 175ºF from the Minnelusa B sandstone at a depth of 8915 ft with an average porosity of 20% and an average permeability of 200 md. Average thickness is 25 ft. Tanner is a small field consisting one injection well and two production wells, north and south of the injector. A net pay Isopach is shown in Fig. 1. Floodable pore volume is 2,560 Mbbls distributed equally with 1,280 Mbbls north of the injection well and 1,280 Mbbls south of the injection well. Original oil in place is 2,000 Mbbls or 80% oil saturation. Bo is 1.02. The floodable pore volume and original oil in place represents about half the toal field, as seen in Fig. 1.

The Illinois and Appalachian Basins contain many mature and economically marginal waterfloods. These fields produce at high water-oil ratios that have proportional fluid handling costs. Approximately 60% of the oil resource remains in the reservoir rock at these conditions. The Alkaline-Surfactant-Polymer, ASP, technology has been field demonstrated to recover 15% OOIP to 30% OOIP of this residual oil by minimizing capillary forces which trap oil, improving areal and vertical contact efficiency, and mobility ratio.Mechanisms of ASP flooding are discussed and field performance is compared with micellar technologies that were tested in the Illinois Basin. Introduction Almost 40 years ago micellar technologies demonstrated that by reducing the capillary forces trapping oil, a significant portion of waterflood residual oil could be produced. Incremental recoveries of 20% to 30% OOIP at Marathon's Robinson Sand, Exxon's Louden, Texaco's Salem, and Pennzoil's Bradford Fields demonstrated this approach was technically successful, but also economically unjustifiable at oil prices below $30/bbl. Prior to these field trials, Reisberg and Doscher demonstrated that alkali produced interfacial activity related to certain components of oil and that the addition of surfactant could enhance this activity.1 The Alkaline-Surfactant-Polymer, ASP, technology development began in the 1980's in an environment of $15/bbl oil. This technique uses similar mechanisms as the micellar technology to mobilize the residual oil, but reduces the expensive surfactant concentration by 20 to 70 fold. The added alkali generates natural surfactants by reaction with components in oil, and reduces chemical consumption losses. ASP field tests in mature waterfloods have demonstrated oil cut increases and incremental oil recoveries of over 20% OOIP. Early and ongoing US projects are mainly confined to the Rocky Mountain States. Incremental oil recovery from these projects historically have been less than $4.50/bbl and as low as $1.46/bbl. The technology is also being applied in Canada, China, and Venezuela. A review of mechanisms of ASP flooding and performance of secondary and tertiary ASP projects are provided and compared with some of the Illinois Basin micellar projects. The paper will discuss laboratory and facility design required for implementing an ASP project, and address complexities and pitfalls to avoid for successfully applying the ASP technology. Mechanisms of ASP Flooding ASP is an acronym for Alkaline-Surfactant-Polymer, which describe the classes of the three chemicals used. ASP flooding combines various mechanisms into a process. Table 1 lists the functions of each of the chemicals, and the general Enhanced Oil Recovery (EOR) mechanism involved.