Performance Evaluation of the Salem Unit Surfactant/Polymer Pilot
- R.H. Widmyer (Texaco Inc.) | D.B. Williams (Texaco Inc.) | J.W. Ware (Texaco U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1988
- Document Type
- Journal Paper
- 1,217 - 1,226
- 1988. Society of Petroleum Engineers
- 4.3.4 Scale, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating, 5.4.10 Microbial Methods, 2.4.3 Sand/Solids Control, 5.3.4 Reduction of Residual Oil Saturation, 5.4.1 Waterflooding, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.1 Phase Behavior and PVT Measurements, 5.6.5 Tracers, 5.6.1 Open hole/cased hole log analysis, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.7.2 Recovery Factors
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The Texaco operated surfactant-polymer project at the Salem Unit, Marion County, Illinois contains twelve patterns totaling sixty acres. A brine tolerant surfactant formulation, requiring no formation preconditioning, was injected into the watered out Benoist Sandstone and followed with a biopolymer. Different tracers were injected with the surfactant at the various injection wells. From the produced tracer concentrations, the relative distribution of surfactant in all 48 pattern quadrants was determined. pattern quadrants was determined. Initial production rates were higher than planned and resulted in uneven surfactant planned and resulted in uneven surfactant distribution. Further flow distortion occurred due to uneven pressure build-up at the surrounding backup injection wells.
Log interpretation, etc. indicated that the top third of the Benoist Sand had not been completely waterflooded. Thus, it was not unexpected when most of the chemical flood entered the lower two-thirds of the reservoir.
Interpretation of logs run in monitor wells indicated that oil saturation was reduced to 2-8% in some intervals. Analyses of periodic samples from adjacent monitor wells revealed component changes as the surfactant moved from injectors to producers. producers. Pressure changes during polymer injection and produced liquid analyses from monitor wells produced liquid analyses from monitor wells indicated an early loss of polymer effectiveness attributed to bacterial degradation. The resultant waterflood type displacement mechanism substantially slowed the mobilized oil displacement and recovery rate. However, current projections of ultimate tertiary oil recovery are approximately 47% of the oil-in-place in the total Benoist Sand. Assuming that all of the oil was produced from the lower interval, the recovery efficiency will be 76%. These recoveries illustrate the capability of the brine tolerant surfactant system. It is also apparent that positive means for maintenance of polymer viscosity and chemical placement must be polymer viscosity and chemical placement must be employed.
The design and implementation of the Salem Unit Surfactant/Polymer Project was described in 1983. In review, the Salem Unit is located in South Central Illinois about 70 miles (113 km) east of St. Louis, Missouri. Figure 1 shows the project site location.
The subject chemical flood was conducted at 1750 ft (533 m) in the waterflood depleted Benoist Sand. The project configuration and well layout are shown in Figure 2. Twelve 5-acre (2 ha) elongated, inverted five-spot patterns comprised the designated 60-acre (24.3 ha) chemical flood area. It is noted that there are two totally enclosed interior patterns. For ease and identification, each pattern is numbered the same as its injection well. There are a total of 12 chemical injection wells and 20 producing wells. A total of 24 surrounding backup injection wells were used to confine the chemical flood to the designated area. Injection rates of the backup injection wells on the immediate east and west sides of the project area were scheduled so that, theoretically, there would be a no flow zone between the inner and outer rows of backup injection wells on those sides. The total area associated with this effort was about 200 acres (81 ha).
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