ASP System Design for an Offshore Application in La Salina Field, Lake Maracaibo
- Clara Hernandez (PDVSA-INTEVEP) | Larry J. Chacon (PDVSA-INTEVEP) | Lorenzo Anselmi (PDVSA-INTEVEP) | Abel Baldonedo (PDVSA-EP) | Jie Qi (Surtek Inc.) | Phillip C. Dowling (Surtek Inc.) | Malcolm J. Pitts (Surtek Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2003
- Document Type
- Journal Paper
- 147 - 156
- 2003. Society of Petroleum Engineers
- 2.2.2 Perforating, 1.6.9 Coring, Fishing, 5.3.4 Reduction of Residual Oil Saturation, 3.4.5 Bacterial Contamination and Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.5 Processing Equipment, 5.7.2 Recovery Factors, 5.5.8 History Matching, 5.4.1 Waterflooding, 4.3.4 Scale, 6.5.2 Water use, produced water discharge and disposal, 4.1.2 Separation and Treating, 4.2 Pipelines, Flowlines and Risers, 5.2.1 Phase Behavior and PVT Measurements, 2.4.3 Sand/Solids Control, 5.5.2 Core Analysis
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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-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 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.
Waterflood oil recoveries range from 10 to 70%.1 Low waterflood oil recoveries are caused by 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 polymers cannot reduce the residual oil saturation (Sor) in a water-wet reservoir. Addition of an alkali and a surfactant to the polymer-thickened water has been shown to reduce Sor. 3 Alkali addition supplements the surfactant activity and reduces the consumption of both surfactant and polymer.
ASP flooding is a chemical oil recovery method that has been proven to increase oil recovery in the field.2,4-8 Many tertiary waterflood applications of the ASP technology have been performed in the Daqing field, People's Republic of China,9-12 including one at a completely watered-out area.13
This work gives an overview of the project strategy from conception to field implementation. The different stages studied are the development of an optimum ASP formulation for La Salina LL-03/Phase III reservoir; reservoir hydrodynamics; numerical simulation forecasting ASP oil recovery; and design of an ASP injection plant.
Integrated Field Laboratories (IFLs)
Venezuelan light-oil reservoirs have been produced for 40 years. These resources are located in reservoirs with very different characteristics. Their depth ranges from very shallow to 5483 m (18,000 ft), and their expected final recovery is only 29% OOIP. PDVSA is aware of the benefits associated with the application of new and proven technologies. Pilot tests have been conducted with promising results, but transferring technology and applying it on a large scale is usually a very slow process. The IFL approach classifies reserves by reservoir type; a representative area is selected to conduct specific applications. PDVSA adopted this new technological strategy to increase the rate of transfer from idea to field application. Eleven IFLs have been created in Venezuela to date. They are located in western, eastern, and southern Venezuela. La Salina IFL belongs to the first group.
The main goal of the IFLs is to evaluate technologies and provide strategies for the exploitation of similar fields to reduce the time for transferring from lab scale to field scale. A recent publication thoroughly addresses this topic.14
The LL-03 reservoir is located in La Salina field, in Lake Maracaibo, northwest Venezuela. It was discovered in 1926, with exploitation starting in 1935. A water-injection program was initiated in 1972 with nine injectors. In 1976, the program was stopped because of a lack of pressure maintenance. The total volume of water injected was 20 190 000 m3 (127 million bbl), which represented a replacement factor close to 20%.
At the same time, another waterflood exploitation plan was started that consisted of three phases: Phase I (1979), Phase II (1985), and Phase III (1987). At present, 97 200 000 m3 (611.3 million bbl) have been injected into the reservoir. Cumulative oil produced is 70 160 000 m3 (441.3 million bbl), which represents a recovery factor of 19.4% OOIP.
The subject area of the present study is located in the central part of Lagunillas-03 (Phase III), La Rosa formation. Water is injected into 25 inverted 7-spot well patterns. Fig. 1 shows the well locations. The ASP pilot is planned in the uppermost region of the Phase III area.
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