Polymer flooding produced water from

S. Deng, R. Bai, J. P. Chen, et al.. Produced water from polymer flooding process in crude oil extraction characterization and treatment by a novel crossflow oil-water separator. Sep. Purif Technol. 29, 207-216 (2002). 

After being treated, produced water from polymer flooding and dehydration stations can be reused and reinjected in new well patterns. In locations where the produced-water quantity cannot satisfy the injection requirements, underground water and surface water are treated to reach the quality required (Liu et al. 2006 Xia et al. 2001). 

Liu, S., Zhao, X., Dong, X., Miao, B., and Du, W. 2005. Treatment of Produced Water From Polymer Flooding Process Using a New Type of Air Sparged Hydrocyclone. Paper SPE 95343 presented at the SPE Asia Pacific Health, Safety and Environment Conference and Exhibition, Kuala Lumpur, 19-21 September. DPI 10.2118/95343-MS. 

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). 

Salt Sensitivity. The viscosity of mobility control polymers is a strong function of their environment. The ionic composition of a petroleum reservoir determines the conformation that the polymer chains assume in it. This very fact is one of two reasons why the salt sensitivity of the polymer solutions need to be studied. The second incentive for an investigation of this kind is the possibility of using the water produced from a flooded field in making the new polymer solution. Since the produced water contains many salts and minerals, knowing how the viscosity changes as a function of ion concentration is important. 

When the polymer flood front arrives at the end of the linear system, the displacement process becomes a waterflood. The WOR jumps from 3.53 in the oil/water bank to 27.2 at the polymer flood front and then continues to increase. The remainder of the oil will be produced at high WOR. Oil recovery when the polymer front reaches the end of the linear system is identical to that in Table 5.22 at ( =0.8079, corresponding to polymer-flood-front breakthrough. Remember that in the case of slug injection where the PV of polymer injected equals Dp, the polymer flood front disappears just as the polymer reaches the end of the linear system. Incremental oil displaced at this time is 27,658 STB from the injection of 0.424 PV of polymer solution. Polymer required in the slug is... 

Oil production from the 10 pilot area producing wells increased from 12 to 95 B/D within eight months after beginning polymer flood operations. Oil production has averaged nearly 100 B/D during the past 22 months which represent a peak oil rate approximately one-third the injection rate (Fig. 7). Cumulative recovery on May 1, 1966, was 243 bbl/acre-ft at a producing water-oil ratio of 0.76. Ultimate pilot recovery is estimated to be 350 bbl/acre-ft after six years flood life. These predictions were made from individual well decline curve analysis and theoretical approaches based on Refs. 3 and 4. 

One natural core was used to compare the performance of waterflood (W), AP flood, and ASP flood. The recovery factors for W, AP, and ASP were 50%, 69.7%, and 86.4%, respectively. These core flood tests were history matched, and the history-matched model was extended to a real field model including alkaline consumption and chemical adsorption mechanisms. A layered heterogeneous model was set up by taking into account the pilot geological characteristics. The predicted performance is shown in Table 11.3. In the table, Ca, Cs, and Cp denote alkaline, surfactant, and polymer concentrations, respectively. After the designed PV of chemical slug was injected, water was injected until almost no oil was produced. The total injection PV for each case is shown in the table as well. The cost is the chemical cost per barrel of incremental oil produced. An exchange rate of 7 Chinese yuan per U.S. dollar was used. From... 

The next phase shows an increase in salinity from 50 to about 80 g/1. This phenomenon has been observed in most of the producers of different projects and confirms that the advancing polymer front is invading pore volumes that were not involved during the preceding water flood. 

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