Improving Polymer Injectivity at West Coyote Field, California

Abstract

Summary. This paper presents a case history where laboratory and simulation results were used to model a single-well polymer injectivity field test in the West Coyote field and to improve injectivity in a sub-sequent field test. The polyacrylamide used in the first tesxhibited low injectivity. Laboratory studies were performed to identify the causes of low injectivity and to model the field test physically. Laboratory core data and reservoir properties were used in a mathematical model to calculate the polymer injectivity, which closely matched that observed in the field. The low polymer injectivity at West Coyote was a result of formation damage caused by the polymer and low-salinity polymer makeup water and the high resistance factor developed by the polymer. These problems were overcome by using a lower-molecular-weight polyacrylamide, preshearing the polymer solution before injection, and increasing the salinity of the polymer makeup water. These improvements resulted in a 50% polymer makeup water. These improvements resulted in a 50% increase in injectivity during the second polymer injectivity field test at West Coyote. Introduction Two single-well evaluation programs for the micellar/polymer process were conducted in the Main and 99 West pools at the West Coyote field. The objectives were to determine oil saturations before and after micellar displacement tests, to characterize the field handling and injectivity of micellar/polymer fluids, and to obtain additional geologic data for an improved reservoir model. This paper focuses on the polymer injectivity tests performed at these field trials. An earlier paper discussed performed at these field trials. An earlier paper discussed the overall program for the first field trial at Well MC-374. The micellar formulation tested at Well MC-374 was effective in reducing the waterflood residual oil saturation from 0.32 to 0. 10, but the polymer injection rate was only 70% of the design rate. Both oil displacement efficiency, and in injectivity are key factors in determining the economics of a chemical flood. The injectivity for the first program at West Coyote was too low to generate an program at West Coyote was too low to generate an acceptable rate of return for a commercial-size project. In subsequent laboratory work, the causes of low injectivity were identified, and a new chemical system was designed and tested at Well MC-375. This paper first describes the field operations and polymer injectivity data for Well MC-374. On the basis of polymer injectivity data for Well MC-374. On the basis of field operations, several causes for the low injectivity were postulated and later verified in laboratory corefloods that postulated and later verified in laboratory corefloods that physically modeled the field test. A reservoir simulator physically modeled the field test. A reservoir simulator incorporated these laboratory data into a mathematical model of injectivity. Next, alternatives for improving polymer injectivity were evaluated, and an improved polymer injectivity were evaluated, and an improved Polymer system was selected for testing at Well MC-375. Polymer system was selected for testing at Well MC-375. Field and laboratory data were compared through reservoir simulation and pressure transient analysis. The premise of this paper is that the chemical solution mobilities measured in laboratory corefloods can be related to mobilities that exist in a field flood. Such laboratory tests can thus be used to predict and to optimize mobility control and injectivity for the field. This approach was used successfully in the chemical slug mobility design for a micellar flood at the Big Muddy field . It was shown there that the slug mobilities measured in the laboratory closely matched those observed in the field. Well testing can also be used to interpret polymer-injectivity field tests and to calculate the in-situ polymer mobility in the reservoir. West Coyote Field The West Coyote oil field is located at the eastern end of the Los Angeles basin, near La Habra, CA. This field has six oil zones. The Main and Upper 99 zones contain the most oil in place and are the subject of this paper. The Main and Upper 99 are divided into eight subintervals, six in the Main and two in the Upper 99. The field is a candidate for EOR because the current water cuts are in excess of 98% and the waterflood is forecasted to last only into the 1990's. Micellar flooding was selected as a potential EOR process, because West Coyote is a light-oil reservoir with a moderate temperature and low salinity. Reservoir properties are listed in Table 1. Well MC-374 Polymer-injectivity Test A polymer-injectivity test was performed in the top 20 ft [6 m] of the Main zone Sand B in March 1982 (Fig. la), starting a few weeks after a micellar oil displacement test in the same interval. The results of a single-well tracer test indicated that the micellar solution reduced the average oil saturation to 0. 10 in the near-wellbore region (20-ft [6-m] radius). SPERE P. 271