Planning And Development Of Polymer Assisted Surfactant Flooding For The Gullfaks Field, Norway
- T. Maldal (Statoil) | E. Gilje (Statoil) | R. Kristensen (Statoil) | T. Karstad (Statoil) | A. Nordbotten (Statoil) | B.E.R. Schilling (Statoil) | O. Vikane (Statoil)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 1998
- Document Type
- Journal Paper
- 161 - 168
- 1998. Society of Petroleum Engineers
- 1.8.5 Phase Trapping, 5.6.4 Drillstem/Well Testing, 5.6.5 Tracers, 5.4.1 Waterflooding, 5.6.9 Production Forecasting, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 1.8 Formation Damage, 4.6 Natural Gas, 4.1.2 Separation and Treating, 4.1.5 Processing Equipment, 6.5.2 Water use, produced water discharge and disposal, 5.5 Reservoir Simulation, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.1 Phase Behavior and PVT Measurements, 2.2.2 Perforating, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6.9 Coring, Fishing, 5.3.2 Multiphase Flow, 5.3.4 Reduction of Residual Oil Saturation
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This paper presents parts of the work performed in order to develop and qualify a Polymer Assisted Surfactant Flooding (PASF) system for economical use in the Gullfaks Field. The paper addresses experimental work done in the laboratory, numerical simulation of PASF, and the evaluation of the potential for PASF in full field scale.
The experimental part comprises core flooding experiments at different temperatures, pressures, and gas-oil ratios in order to optimise the PASF system for the Gullfaks Brent formation conditions. The surfactant in the PASF system is a branched sulphonate (5000 ppm) and xanthan (500 ppm). The surfactant-polymer slug is followed by a slug of xanthan (500 ppm) for mobility control. No cosolvent is used. In coreflood experiments more than 70 percent of the waterflood residual oil was recovered.
By using reservoir simulation a suitable pilot area was found in the Brent reservoir. Additional results from simulations were the amount of chemicals, the time needed for the pilot test, and additional oil recovery.
Much effort was put into estimating the full field PASF potential. Firstly, the areas of the field where PASF possibly could be used were selected. Key factors were existing and planned well locations, production data, and long term production forecasts. Then the amount of chemicals needed and the expected technical efficiency for each area were calculated. To verify these calculations, an area of the field containing two possible injection wells, and three producers, was selected for a simulation study. This area was considered as the most promising area for PASF.
The main conclusion from this work is that, with the present crude oil price and chemical costs, the PASF process is not economical attractive for use in the Gullfaks field, mainly because the residual oil was considerable lower than believed at project start.
The Gullfaks field is located in the north-eastern part of block 34/10 in the Norwegian sector of the North Sea. The oil production started in December 1986 and the cumulative oil production to date is 168 mill. Sm3 or 59 % of recoverable reserves. Water injection is the current drive mechanism, aiming at maintaining reservoir pressure above the bubble point.
At the project start in 1989, the Gullfaks field was from a technical standpoint a prime target for enhanced oil recovery . The residual oil saturation after waterflooding was believed to be about 0.35, which indicated a high technical potential for surfactant flooding. Most of the reservoir characteristics are favourable for PASF, i. e. multidarcy sands, low oil viscosity ( 1.5 cP), relatively low reservoir temperature ( 70 C) and low salinity of the formation water ( 42000 ppm) and moderate low clay content (5-10 %).
A single well injection test with surfactant alone was performed during the first half of 1992. The surfactant was successfully injected without any special treatment of the injection water, and the test confirmed that residual oil was mobilised by the surfactant.
Exxon conducted a series of five pilot tests in the Loudon field from 1980 to 1989. The test sizes ranged from a single pattern of 2800 m2 to multi-pattern tests with pilot areas of 161600 m2 and 323200 m2 areas, respectively. For the 2800 m2 pilot, recovery was 68 % of the waterflood residual oil. In the larger multi-pattern floods, oil recovery dropped to 26.9 % in the 161600 m2 and 33.4 % in the 323200 m2 project.
The tests showed that the use of polymer in the injection water is crucial for obtaining a successful surfactant flooding. An other observation in these field tests was that the surfactant retention was less than half of that measured in conventional laboratory coreflood experiments. This was explained by a change of wettability from aerobic, oxidising conditions, in the laboratory, to the anaerobic, reducing conditions, in the reservoir.
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