La Salina Field, on the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, or IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina IFL was to evaluate the alkaline-surfactantpolymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium-gravity crude oil (25°API) from the LL-03/Phase III Miocene reservoir at 915 m (3,000 ft). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, phase behavior, interfacial tension between crude oil and ASP solution, chemical retention by the porous media, and physical simulation with reservoir core samples. The laboratory design involved 23 commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000-fold were observed for a variety of ASP solutions. Type II-and Type III phase behaviors were observed. Linear coreflood results indicate that high-molecular-weight, partially hydrolyzed polyacrylamide polymers can be injected into La Salina sand. Radial sandpack floods produced an average oil recovery of 45.6% original oil in place (OOIP) with water injection. Injection of 30% pore volume of ASP solution, followed by 30% pore volume of polymer drive solution, produced (on average) an additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task because this will be the first offshore application of the ASP technology in the world. The initial decision for the plant design was to use an existing platform instead of a barge for the construction of facilities. As a result, critical parameters such as treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered. Preparation and transport of a phase-stable ASP solution through the injection lines and into the reservoir are crucial. Designed chemical concentrations and physical characteristics must be maintained.

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.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Big Sinking Field is a mature waterflood in the Appalachian Basin of Eastern Kentucky. The 100 plus million barrel (15.9 million m 3 ) field is primarily a shallow tight oil reservoir at 1,150 feet (350 m). A primary constraint to production is the ability to inject fluid into the reservoir. This project was an effort to increase injectivity by injecting an alkali-surfactant solution to reduce the residual oil saturation with a resultant increase in effective permeability to water. Oil is mobilized away from the injection well bore where a substantial portion of the injection pressure is lost by reducing capillary forces that trap oil. A new well was drilled and cored, and a laboratory program performed prior to field implementation. A variety of mixtures of alkali and surfactant reduced the interfacial tension between oil and water to 0.001 dyne/cm from 23.6 dyne/cm. Injection of a Na 2 CO 3 plus ORS-62HF alkaline-surfactant solution increased the relative water permeability by 425% and a NaOH plus AX-210-6 alkaline-surfactant solution increased the effective water permeability by 310%. Subsequent fresh water injection resulted in a loss of effective permeability to water to 155% times the original waterflood base for the Na 2 CO 3 plus ORS-62HF solution. The NaOH plus AX-210-6 coreflood maintained injectivity at 325% with subsequent water injection. In September 2003, injectivity testing began with injection of fresh water into a newly completed well to establish initial injection rate. A 1,500 barrel (238 m 3 ) injection of NaOH plus ORS-162HF alkaline-surfactant solution followed. Return of fresh water injection showed an increase in fresh water injection from 41 to 75 barrels per day (6.5 to 11.9 m 3 ).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe La Salina Field in the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina FIL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium gravity crude oil (25 °API) from LL-03/Phase III Miocene reservoir at 915 m (3,000 feet). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, spontaneous emulsification, interfacial tension between crude oil and ASP solution, chemical retention in the porous media, and physical simulation using reservoir core samples. The laboratory design involved twenty-three commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000 fold were observed for a variety of ASP solutions. Type IIand Type III spontaneous emulsification, both considered optimum, were observed. Linear coreflood results indicate that high molecular weight (partially hydrolyzed polyacrylamide) polymers can be injected into La Salina sand at about 800 mg/L. Radial sandpack corefloods produced an average oil recovery of 46% OOIP with water injection. Injection of 30% pore volume of ASP solution followed by 30% pore volume of polymer drive solution produced an average additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task since this will be the first offshore application of the ASP technology in the world. Preparation and transport of a phase stable ASP solution, through the injection lines and into the reservoir, that has the designed chemical concentrations and physical characteristics are crucial for a successful project. The initial decision for the plant design was to use an existing platform instead of a barge for construction of facilities. As a result, critical parameters such as: treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered.