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.

Single well chemical tracer tests (SWCT) were carried out at the VLA-1325 well located in Lagomar, C4 reservoir, Lake Maracaibo, Venezuela, to measure residual oil saturation in zone C4-U3 before and after an ASP injection, in order to determine the swept efficiency of a custom made blend. The tests included: Phase I, measurement of residual oil saturation to water (SorW) of the pay zone, previous to an ASP application and after waterflooding procedure; Phase II, application of an ASP blend, specially designed for the aforementioned zone; and Phase III, second measurement of residual oil saturation to ASP (SorASP) after ASP application. The results show that prior to the ASP injection, the residual oil saturation at the VLA-1325 was (31 ± 3)%. This saturation measurement represents pore space in a 6.7 m (22 ft) thickness portion (1,842.4 – 1,849.1 m; 6,048 – 6,070 ft) of the C4-U3 zone from the well bore to a radial position of about 3.04 m (10 ft). A few days after this initial residual saturation, measurement was completed. A 0.35 porous volume, Vp, (1,750 bbl) ASP injection was carried out in the same 6.7 m (22 ft) completion of the C4-U3 zone. This ASP mixture was followed by 0.15 Vp (750 bbl) polymer drive solution, and a 1.2 Vp (6,000 bbl) of fresh water to push the ASP mixture and any mobilized oil about 15.8 m (52 ft) away from the test well-bore. After ASP treatment, the residual oil saturation measurement was repeated in the same pore space as the initial SWCT test investigated. This post-ASP flood SWCT test showed that the residual oil saturation in this pore space had been reduced to (16±3)%. This reduction in the SorW represents (48±1)% mobilized oil by the chemical treatment. The reported Sor measurements represent the average Sor s for the sub-zones penetrated by the tracer fluids during the test. The field data recorded during the test are presented, and compared with best-fitting simulation model results. Introduction The alkaline-surfactant-polymer technology has been widely applied in many reservoirs in order to reduce waterflood residual oil saturation. The technology combines, sinergistically, the interfacial tension reducing effect of added surfactants and those produced in the acidic crude oil by alkaline reaction of organic acids, with the mobility control improvement obtained adding a water soluble polymer. Many papers have been recently published regarding application and design of ASP formulations [1–6]. The Lagomar "Field Integrated Laboratory" (FIL, i.e. LIC after its initials in Spanish), was conceived to evaluate some IOR technologies [2,7]. It was one of the main goals of such a FIL, the design and application of a chemical tracer test using a single well in order to determine the efficiency of an ASP custom made formulation [2] for the VLA-6/9/21 area of the C4 reservoir at Lagomar FIL. This combined SWCT-ASP-SWCT is the next step in the evaluation process before a potential massive application [8–11]. Geology of the Pilot Area The VLA-6/9/21 area is located in northern Lake Maracaibo (Figure 1). It covers an area of 65 km2 (16,056 acres). The reservoir C4 is one of the many composing the Eocene Misoa Formation. The pilot area selected for the FIL is 10 km2 (2,470 acres) in extention and is located at the southern part of the VLA-6/9/21. It is confined between two major sealing faults to the South and West respectively and an oil-water contact to the East. To the North, there is an arbitrary limit. The member C4 contains light crude oil 34.6 °API, a pressure of 6,894 kPa (1,000 psi), and thickness of 137.1 m (450 ft). The C4 member, Shalow Eocene, is divided in five submembers. These are named: C4-U1, C4-U2, C4-U3, C4-M, and C4-L. Submember C4-U3 has a thickness between 12.1–30.5 m (40–100 ft). Its porosity ranges from 17–26% with an average value of 21%. Geology of the Pilot Area. The VLA-6/9/21 area is located in northern Lake Maracaibo (Figure 1). It covers an area of 65 km2 (16,056 acres). The reservoir C4 is one of the many composing the Eocene Misoa Formation. The pilot area selected for the FIL is 10 km2 (2,470 acres) in extention and is located at the southern part of the VLA-6/9/21. It is confined between two major sealing faults to the South and West respectively and an oil-water contact to the East. To the North, there is an arbitrary limit. The member C4 contains light crude oil 34.6 °API, a pressure of 6,894 kPa (1,000 psi), and thickness of 137.1 m (450 ft). The C4 member, Shalow Eocene, is divided in five submembers. These are named: C4-U1, C4-U2, C4-U3, C4-M, and C4-L. Submember C4-U3 has a thickness between 12.1–30.5 m (40–100 ft). Its porosity ranges from 17–26% with an average value of 21%.

The VLA 6/9/21 Field is a waterflooded light crude oil reservoir located in Maracaibo Lake, West Venezuela. In the last two years PDVSA E & P has developed Integrated Laboratory Fields (ILF) as a strategy to evaluate new technologies and EOR methods in order to improve light and medium oil recoveryfactors. Alkali/Surfactant/Polymer (ASP) is one of the chemical flooding technologies that has recently been evaluated in Venezuela. The objetive of this study is to describe the followed methodology to develop ASP formulas, describe the pilot test planned for this year and also to determine whether ASP technology can produce incremental oil in the Eocene C-4Unit of VLA 6/9/21 Field economically. The study was performed at reservoir temperature of 90°C with dead crude oil and rock sandstones from the oil producing zone located in the pilot area. Several ASP formulas were developed for the VLA 6/9/21 Field with comercial petroleum sulfonates. Each ASP solution gave interfacial tension (IFT) values below 9×10-3 dynes/cm. Rheologic studies with polyacrylami depolymers using different additives indicate that the solution viscosity can be mantained over the time at least 2 cp above the crude oil viscosity (2,5 cP) atreservoir temperature. Surfactants, alkali and polymer retention were below 0,08 mg/g rock. Incremental oil recoveries were higher than waterflood, obtaining recoveries between 22 and 39% OOIP for 0,3 PV ASP and 0,15 PV polymer injection in reservoir cores. The positive results of this laboratory study provided an ASP formula for a pilot test supported with the injection of oil partitioning tracers before and after the chemical additives as part of one ofthe ILF of PDVSA E & P. Introduction PDVSA´s light oilfields in Lake Maracaibo have been under exploitation formore than four decades. To date, the expected recovery factor is only 29% ofthe OOIP. As these resources approach maturity, it has been realized tha timproving recovery will demand the earliest use of many technologies, provenand new, in an integrated manner and tailored to solve specific regional problems. The Integrated Field Laboratory (IFL) philosophy is one of PDVSA´s main technology strategies designed to accomplish these goals. Three Field Laboratories are being developed in the Maracaibo Lake Basin: one for heavy oils and two for light oils: shallow and deep reservoirs. Lagomar´s VLA-6/9/21 area was selected as representative of a large numberof shallow (less than 10000´) light oil reservoirs in the Maracaibo Lake basinwith similar reservoir characteristics, currently under water injection and atan advance stage of depletion. Resent characterization studies indicate that there exists a large volume of reserves not contacted in the VLA-6/9/21 area which need new strategies of exploitation to bring them to production. Venezuela has over 50000 MMSTB of oil currently in place in reservoirs with similar condition [1]. The area selected for the IFL has an approximate aerial extension of 10Km2. It is confined between two major sealing faults to the Southand West and the OWC to the East. To the North, an arbitrary line (Figure 1)limits it. There are six overlying reservoirs in the IFL´s area: Basal la Rosa,C-4, C-5, C-6-S/M, C-6-I and C-7. Most of the remaining reserves are concentrated in the three uppermost reservoirs, which were selected for the multi-reservoir water injection project.

In La Salina field, located in the Maracaibo Lake, Venezuela, which produces a medium gravity crude oil (25 ° API) from a Miocene reservoir at 3,000 feet, a series of EOR processes were proposed to be evaluated under field conditions. Results from laboratory tests indicated that Alkali-Surfactant-Polymer technology (ASP) might be a potential EOR process to improve the oil recovery factor. However, ASP processes involve the injection of a significant volume of chemicals, therefore, costs associated with this technology could exceed the economical limit permissible. For this reason, it is necessary to use simulation tools to predict reservoir production response when this technology is applied.Results from early ASP simulations have been reported elsewhere [1,2].The present study shows the results of modeling the injection of ASP in a pilot area of La Salina field, using two commercial simulators. The pilot area has been partially depleted by waterflooding, therefore the reservoir still contains mobile oil saturation. Based on laboratory history matches of radial core floods, several field predictions were carried out which show an incremental oil recovery factor between 6% and 16.7% compared to waterflooding, depending on the selected well arrangements and the volume of injected chemicals. The results of the two simulators were compared at both PETROLEUM SOCIETY CANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUMscales, and in spite of formulation differences between them, the answers were very similar. Additionally, sensitivities on certain critical variables that can influence the success of future tests were established. These include chemical formulation variables such as interfacial tension reduction and component adsorption levels, as well as field injection rates, treatment volume, and injection time. Also, different well arrangements were evaluated, including drilling and positioning of infill wells. The simulations have given confidence with regard to the applicability of ASP in the La Salina field, and preparations for a pilot test are underway.

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.