Polymer flooding tests

In the Shengtuo commercial polymer flooding test, KAPAM and MO-4000 were injected in two separate areas (Li, 2004a). The test areas are described in Table 5.6, and the water composition is shown in Table 5.7. The formation temperature was 80°C. The injection start dates were as follows ... 

Li, Z.-Q., 2004b. A commercial scale polymer flooding test in Gudao Zhong-1 block of high water cut. Petroleum Exploration and Development 31 (2), 119-121. 

Li, Z.-Q., 2004c. Polymer flooding test progress in Shengtuo block 1 of Shengli Field. Petroleum Processing and Petrochemicals 35 (10), 56—59. 

The measurement points represent the polymer retention at one and six cm distances from the injection face after polymer flooding tests. The injected polymer solution volumes during oil recovery cycles are shown in Figure 29. After the oil recovery cycles, 5-6 pore volumes of brine were injected through the sandpacks. 

Waterflooding was initiated in 1964 in the Ranger zone area that was later to be polymer flooded. Response to the waterflood was generally favorable, but WOR s showed a steady increase. The waterflood mobility ratio was about 14, indicating that improved sweep efficiency might be expected from polymer flooding. Tests with a polyacrylamide indicated that the mobility ratio could be reduced to just slightly above 1.0 with a polymer concentration of 250 ppm. Resistance factor measured in the laboratory was 10.7, and polymer adsorption was measured and predicted to be 85 Ibm polymer/acre-ft. 

An alternative to this process is low (<10 N/m (10 dynes /cm)) tension polymer flooding where lower concentrations of surfactant are used compared to micellar polymer flooding. Chemical adsorption is reduced compared to micellar polymer flooding. Increases in oil production compared to waterflooding have been observed in laboratory tests. The physical chemistry of this process has been reviewed (247). Among the surfactants used in this process are alcohol propoxyethoxy sulfonates, the stmcture of which can be adjusted to the salinity of the injection water (248). 

The state of the art in chemical oil recovery has been reviewed [1732]. More than two thirds of the original oil remains unrecovered in an oil reservoir after primary and secondary recovery methods have been exhausted. Many chemically based oil-recovery methods have been proposed and tested in the laboratory and field. Indeed, chemical oil-recovery methods offer a real challenge in view of their success in the laboratory and lack of success in the field. The problem lies in the inadequacy of laboratory experiments and the limited knowledge of reservoir characteristics. Field test performances of polymer, alkaline, and micellar flooding methods have been examined for nearly 50 field tests. The oil-recovery performance of micellar floods is the highest, followed by polymer floods. Alkaline floods have been largely unsuccessful. The reasons underlying success or failure are examined in the literature [1732]. 

Recent research and field tests have focused on the use of relatively low concentrations or volumes of chemicals as additives to other oil recovery processes. Of particular interest is the use of surfactants as CO (184) and steam mobility control agents (foam). Also combinations of older EOR processes such as surfactant enhanced alkaline flooding and alkaline-surfactant-polymer flooding have been the subjects of recent interest. Older technologies polymer flooding (185,186) and micellar flooding (187-189) have been the subject of recent reviews. In 1988 84 commercial products polymers, surfactants, and other additives, were listed as being marketed by 19 companies for various enhanced oil recovery applications (190). 

The pilot area used for this test was relatively small, 0.71 acres. However, the test was a technical success, recovering 68% of the water-flood residual oil. The pilot began in 1982 and ended in November 1983. Since that time, Exxon has initiated two other micellar-polymer floods in the Loudon field, one a 40-acre pilot and the other an 80-acre pilot. 

C. Tielong, S. Zhengyu, F. Song et ah, A Pilot Test of Polymer Flooding in Reservoir, In... 

Wang et al. (2001c) performed polymer and ASP flooding tests after the cores were completely watered out. Increasing displacing fluid viscosity leads to a... 

This chapter first introduces different types of polymers and polymer-related profile confrol systems used in enhanced oil recovery (EOR), although the list is in no way comprehensive. Then the chapter discusses several polymers developed in China, especially those used in field tests. Then it focuses on the polymer solution properties and polymer flow behavior in porous media. Numerous special subjects regarding polymer flooding (PF) are discussed, and field pilot tests and application cases are presented. Finally, the chapter summarizes the field experience and learning of polymer flooding. 

Luo et al (2002). The tested core permeability was 0.7 to 1.8 and the porosity was 0.2. In addition, the displaced oil was 9.5 mPa s at 70°C. Table 5.5 compares the performance of KYPAM with HPAM 1285 at a concentration of 1000 mg/L. A 0.4 PV injection volume was used. We can see that the flow behavior of KYPAM was better than HPAM 1285. KYPAM has been widely used in polymer flooding, ASP, and profile control projects in Daqing, Shengli, Huabei, and Xingjiang fields. Several field test cases are presented next. 

Before inverse emulsion was injected, the field went through primary depletion, waterflooding, polymer flooding, and post-polymer waterflooding. By July 2004, the water cut in the test area was 90.64%, with a recovery factor of 50.1 %. With 1 injector, Well 21-4, and 5 producers, the injection of inverse emulsion was started in December 2004 at one injection well pattern. The injection program was 10 m polymer solution of 8000 mg/L concentration, 15 m inversion emulsion with 6000 mg/L polymer, and 1167 mg/L phase inversion agent, followed by chase water drive. Four producers out of 5 wells responded to the injection in this test. The injection pressure increased from 7.5 to 9.5 MPa, the water cut reduced from 92.5 to 91.4%, the oil rate increased from 31.9 to 44 fid, and the liquid rate increased from 423.1 to 513.2 fid for the well pattern (Lei et al., 2006). 

Conduct core flood tests with the polymer solution at different injection rates. Measure the pressure drop, Ap, corresponding to each injection rate (velocity u). The core permeability and porosity are measured before the core flood tests. 

When comparing the viscometric and core flood data, the reader should be reminded that several factors could lead to incorrectly estimated values of Tipp in the core flood tests. The polymer may be adsorbed and retained in the porous media, or there is microgel, which would lead to reduced permeability. Thus, if the permeability reduction is not considered, the estimated Papp using the Darcy eqnation conld be higher than the actual viscosity values because the shear rate is underestimated (see Eq. 5.25). There is also the slip effect (Sorbie, 1991), which occnrs in a low-shear regime and in a low-concentration polymer... 

Figure 5.54 shows an example of relative permeability curves in an oil-wet rock. The water relative permeability curve after polymer contact, k p, was parallel but signihcantly lower than the water relative permeability curve before polymer flood, kj i. k, with S increasing and kj 2 with Sw decreasing were different owing to hysteresis. The residual oil saturation decreased in the polymer/oil test as the k 3 shifted toward higher water saturation, as shown... 

Special Cases, Pilot Tests, and Field Applications of Polymer Flooding... 

SPECIAL CASES, PILOT TESTS, AND EIELD APPLICATIONS OF POLYMER FLOODING... 

Bei-l-Qu-Duan-Xi was the first large-scale polymer flooding field application in the northern Saertu field, Daqing. There were 25 injectors and 37 producers in the test area in five-spot patterns. The target layers were PI1.4. The well spacing from injector to producer was 250 to 300 m. Some of the reservoir and flnid data are shown in Table 5.22 (Chang et al., 2006 Yan et al., 2006). 

Before polymer flooding, 0.66 PV water had been injected with a recovery factor of 28.5%. The water cut was 88%. Polymer injection was started in Jannary 1993 and ended in April 1997 with a total 592 mg/L-PV. Approximately 40% of the polymer used in the first sing was high MW polymer (17 to 19 million) the MW in the main sing was 11 to 12 million. The polymer concentration was 800 to 1000 mg/L. The post-PF water drive was completed in October 1998. Some observations regarding this test are summarized here ... 

Most of polymer floods in Daqing were conducted in oil zones. There are a significant amount of reserves in transition zones. In 1995, the Sabei transition zone was selected for a polymer flooding pilot test. The target formation was PI1.4. The basic reservoir, fluid, and well data are shown in Table 5.24 (Niu et al., 2006). The well pattern was irregular four-spot. 

This section snmmarizes the experience and learning on several subjects gained dnring more than 20 years of pilot testing and large-scale commercial applications in polymer flooding in China. 

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