The 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 II- and 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.
Most injection systems are conventional waterfloods. Oil recoveries for waterfloods(1) range from 10–70%. Most low oil recoveries are due to adverse mobility ratios, poor location of wells, and geologic setting. If mobility ratio is properly adjusted by adding polymers, sweep efficiency and recovery can be improved(2), but it cannot reduce Sor in a water-wet reservoir. Addition of an alcali and a surfactant(3) to the polymer thickened water have been shown to reduce S or. ASP flooding is a chemical oil recovery method that has(4–7) proved to increase oil recovery in the field. Alkali addition supplements the surfactant activity and reduces the consumption of both surfactant and polymer.
This work shows an overview of the project strategy from conception to field implementation. Different stages studied are: development and qualification of the optimum ASP formulation for the La Salina LL-03/Phase III reservoir, reservoir hydrodynamics, numerical simulation to forecast of ASP oil recovery, and design of an ASP injection plant.