Polymer concentrations, injected-water

Linear and radial core flood tests were conducted to determine the polymer concentration for mobility control requirement. Figure 13.39 shows Brookfield (UL adapter) viscosity properties for the Alcoflood 1275A polymer in injection water and in an alkaline-surfactant solution. Note that the AS dramatically decreased the viscosity, and a higher polymer concentration was required to provide the same viscosity. 

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). 

In the extensive literature on polymer drag reduction, it has occasionally been reported that a continuous thread of a high-concentration polymer solution injected into the axis of a pipe produces a drag-reduction effect on the water flow in the pipe [856]. The thread seems to persist through the length of the pipe and little, if any, diffusion of polymer to the walls of the pipe is apparent. 

A polymer of the polyacrylamide type was injected as a 0.5% solution from an axially-placed nozzle at the bellmouth entrance. The experiments showed that the central thread provided drag reduction almost equivalent to premixed solutions of the same total polymer concentration flowing in the pipe. Overall concentrations of 1, 2, 4, and 20 ppm were used. Moreover, the effects were additive 2 ppm thread overall concentration plus 2 ppm premixed gave drag reductions equivalent to 4 ppm of either type. Reynolds numbers of up to 300,000 were investigated. In other experiments, a number of different polymer fluids were injected on the centerline of a water pipe-flow facility [857]. Two distinct flow regions were identified ... 

When dissolved in more saline waters, xanthan gum produces a higher apparent viscosity than the same concentration of polyacrylamide (292). Prehydration of xanthan in fresh water followed by dilution in the saline injection water has been reported to provide higher viscosity than direct polymer dissolution in the same injection water. Optical rotation and intrinsic viscosity dependence on temperature indicate xanthan exists in a more ordered conformation in brine than in fresh water (293). 

Experimental. The differential refractive indexes of polymer solutions were measured at 25°C with a Waters Scientific R-403 differential refractometer connected on-line with a size exclusion chromatograph. The refractometer was calibrated to refractive index units (Riu) with benzene/carbon tetrachloride solutions. The rationale behind using the refractometer on-line with the chromatograph is the elimination of impurities in the sample (water, residual monomer etc.) which affect the refractive index measurements particularly at low polymer concentrations and to calibrate the detectors at the flow conditions at which they were normally operated. Polymer solutions of several concentrations (0.015-0.0025 wt %) were injected repeatedly to verify the reproducibility of the measurements, which was typically An 0.5 x 10-6 for replicates on the same solutions. 

In most cases, polymer adsorption is considered irreversible that is, it does not decrease as polymer concentration decreases (Szabo, 1979 Lakatos et al., 1979 Gramain and Myard, 1981). The irreversible effect is caused by polymer adsorption on rock. However, this is not exactly true because small amounts of polymer can be removed from porous rock using prolonged exposure to water or brine injection. Usually, however, the rate of release is so small that it is not possible to measure the concentrations accurately. It is thus more accurate to state that the rate of polymer retention is much greater than the rate of polymer removal. Retention also may occur when flow rates are suddenly increased. This process is called hydrodynamic retention, which is reversible (Green and Willhite, 1998). 

The polymer injection was started on August 8, 1997. A unique polymer injection scheme was designed well by weU. The injected polymer concentration in each well depended on the injection pressure, as shown in Table 5.17 (Yi et al., 1999). The overall design for the graded injection scheme was 1700 mg/L and 0.06 PV followed by 1300 mg/L and 0.27 PV. The total amount of polymer injection was then 453 mg/L PV. In this case, the following three observations were made (1) polymer injection was effective, resulting in increased injection pressure, decreased liquid offtake rate, decreased water cut, and increased oil rate (2) the average well sand production increased from 0.69 m to 1.22 m and (3) the vertical injection profile was improved. 

Laboratory and Numerical Simulation Studies Both 2D and 3D physical models were built to study the effectiveness of the profile control. In the 2D model, the incremental oil recovery factor was 8.19% over aquifer drive. In the 3D model, the incremental oil recovery factor was 6.2% (Li et al., 2005c). In the 3D model, 0.08 PV of 3000 mg/L polymer was injected. When crosslinked polymer was injected, high permeability channels were immediately blocked, the injection pressure rose, and the water cut fell. However, because of strong edge water, water bypassed the blocked zone, the injection pressure fell, and the water cut quickly rose again. A numerical simulation was carried out to study the feasibility of polymer injection and optimize the program (Yao et al., 2005). The optimum concentrations from the laboratory results were 0.3 to 0.5% polymer, 0.2% crosslinker concentration, pH 5,... 

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 ... 

Before PF, 0.1153 PV water had been injected from October 1996 to August 1997. A total polymer injection of 597.64 mg/L PV was started on August 28, 1997, and ended in October 2002. The average injected polymer concentration was 892 mg/L, and the injection PV was 0.67. The viscosity at the injection wellhead was 20 mPa s. In this case, the incremental oil recovery factor was 8.55%. 

Low water cut. During 0.15 to 0.35 PV injection, the water cut is low, and the minimum water cut and higher oil rate appear in this period. The liquid production rate declines, polymer concentration starts to decrease, and polymer starts to be produced. The injection pressure increases slowly. The water intake in low permeability layers starts to decrease, and the injection profile starts to return to its initial profile. About 39% of the cumulative oil is produced in this period. 

Water cut starts to increase. After 0.35 PV is injected, the water cut increases, oil rate decreases, and produced polymer concentration and injection pres-snre are high. About 33% of the cumulative oil is produced in this period. 

Post-water drive. The water cut continues increasing and injection pressure decreases. Water breaks through high permeability channels. Polymer concentration decreases and liquid offtake rate increases. About 11% of the cumulative oil is produced in this period. 

Daqing polymer flooding performance shows that oil rate increased before produced polymer concentration increased. Produced polymer concentrations peaked at 400 to 900 mg/L, approximately half of the injected concentration. As mentioned earlier, the produced water with polymer may be re-injected to save water cost and polymer cost. 

As we know, adding alkali in a polymer solution will reduce the polymer solution s viscosity. We may take advantage of this fact in low-injectivity wells. Initially, the polymer solution with alkali has a low viscosity. As the alkah is consumed by reacting with formation water and rocks, the polymer solution s viscosity will become higher than the initial value. Thus, initially the injectivity and later the sweep efficiency will be improved. Note that the polymer concentration will also be reduced by adsorption. The final effect is determined by the balance between the two effects of the reduced alkaline and polymer concentrations. 

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 injection scheme for this test was 0.25% A1 + 0.5% A2 + 0.06% S -e 0.15% P. The pilot was started in October 1997 and was stopped in June 1999 because the casing for the injector 125 was broken. The test was resumed in October 1999, and a chemical injection was ended in June 2000. Only the wells on the southern and northern sides of the injector 125 responded to the chemical injection (water cut reduced and oil rate increased), not the wells on the eastern and western sides, because the main water injection stream was oriented in the eastern-western direction so that the wells in this direction were well flushed by waterflood before the ASP injection. The ASP injection improved sweep efficiency on the southern and northern sides. Thus, the wells on these sides responded to the ASP injection. The injected surfactant concentration was low (0.06%), and the crude oil had a low acid number. The main mechanism in this pilot was probably the sweep efficiency improvement by polymer injection. 

The variations of reduced polymer concentration C/Co and intrinsic viscosity [ulr = [ul/[ul, where Cq and [ri] are the values at the inlet, are plotted in Fig. 1 to 5 as a function of the volume of polymer solution injected Vp, and of water volume injected Vw. both expressed in terms of pore volume PV. 

The requirements for the presentation of the general flow characteristics of polymer solutions were best met by high molecular mass (3.5 10 ) hydrolyzed (40%) polymer. Concentration of the polymer was 100 ppm, viscosity of the solution under laboratory conditions (24 C) was 3.05 mPas. Taking into consideration the rock s permeability (59 10 and 62 10" ym ) and the equivalent diameter of the random coils (2600A), the polymer-rock system may be regarded as compatible. In the course of the experiments, comparison is made between the flow phenomena observed in the porous cores considered to be water wet and oil wet, respectively. When the permeability was determined by "connate water" (2% sodium chloride solution), the injection sequence of the fluids was as follows 1) polymer solution, 2) connate water, and 3) distilled... 

The injection of polymer solution was started after the brine permeability measurements. At a constant flow rate (6 ft/d) several pore volumes of polymer solution were injected through a sandpack. After the polymer flow cycle, the water lines before the sand face were flushed out with brine, and the injection of brine was initiated. During polymer flow and brine flush the injection pressures were recorded. Liquid samples were taken during both flow cycles. The polymer concentrations were determined from the radioactivities of the liquid samples. 

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