Polymer flooding water saturations

Polymer Flooding. Even in the absence of fractures and thief 2ones, the volumetric sweep efficiency of injected fluids can be quite low. The poor volumetric sweep efficiency exhibited in waterfloods is related to the mobiUty ratio, Af, the mobiUty of the injected water in the highly flooded (low oil saturation) rock, divided by the mobiUty of the oil in oil-bearing portions of the reservoir, (72,73). The mobiUty ratio is related to the rock permeabihty to oil, and injected water, and to the viscosity of these fluids by the following equation ... 

In the next run, a core pack was saturated with 8.6 cp (at 50° C) Ranger-zone crude oil and water flooded to residual oil saturation. Polymer flood was then initiated and about 1.2% of the original oil in place (OOIP) was recovered. The results are shown in Figure 4. The pressure profiles show behavior essentially similar to the previous run except that the pressure drop across the core increased to 100 psi within 4 PV of injection of polymer. The steady state values of pH and viscosity were 7.0 and 0.7 cp. respectively. The oil ganglia retained in larger pores resisting displacement probably reduced the amount of polymer adsorbed and reduced the number of pores that the polymer molecules needed to seal off in order to block the core. This could explain the more rapid plugging of the core. Effluent pH and viscosities remained much lower than influent values. 

FIGURE 2.19 Saturation profile for polymer flood started at interstitial water saturation when... 

FIGURE 2.21 Water saturation profile when a polymer flood is started at a high initial water saturation. 

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... 

For oil and water relative permeability curves after polymer injection, Huang and Yn (2002), and Chen and Cheng (2002) reported their observations, which were similar to residnal permeability reduction after polymer flooding. Compared with the relative permeability curves before polymer flooding, the relative permeability curves had the following three characteristics (1) k was reduced at the same water saturation, and corresponding to the same k, , water saturation was larger (2) immobile water saturation was increased and (3) residual oil saturation was reduced. It is believed this result was caused by polymer adsorption, which made a rock surface more water-wet. 

Figure 6.15 shows the difference in residual oil saturations after glycerin flood and after polymer flood. Because their viscosity and interfacial tension to oil were about the same, the further significant reduction in residual oil saturation by polymer flooding was probably caused by the polymer elasticity. Wang et al. (2000b) showed that the initially oil-wet surfaces became more water-wet after polymer flood, indicating that polymer flood can strip off more oil films from rock surfaces. 

At the same water saturation, the permeability to polymer was significantly lower than that to water. However, the oil relative permeabilities in polymer flooding and waterflooding are not very different. 

At the same saturation, the water cut of polymer flooding was significantly lower than that of waterflooding. At the same water cut, the oil saturation was significantly lower. 

Almost all chemical flood projects are started after some waterflood history. We want to know whether early chemical injection could be a better option. To do that, we change the water injection PV before chemical injection so that average oil saturations (So) before SP are different. The results are shown in Table 9.2. We can see that different total injection PVs are required to achieve about the same incremental recovery factor. The incremental oil recovery factor (RF) is defined as the RF from an SP case minus the RF from the 1.5 PV waterflooding case. The later SP is started, the higher the total injection PV is reqnired. Therefore, it is better to start snrfactant-polymer flood earlier to accelerate prodnction, and thns, less water will be injected. Such results have been confirmed by the ASP corefloods in Daqing (Li, 2007). 

To establish a baseline for the alkaline-polymer flooding, the operator used several empirical correlations and reservoir simulation to estimate the water-flood recovery factor, which was 50%. To study residual oil saturahon distribution, the operator used several approaches such as pressure coring, C/O logging, core wafer, and waterflood performance analysis. Finahy, all data were integrated into a simulahon model to output the residual oil saturation distribuhon. The average residual oil saturahon was 0.33. The gas cap shrank and existed only in the north area to Wells X19 and X35. This area was far away from the AP flooding area so that it was not affected by AP. 

The water cut at which a W/O emulsion is transferred to an 0/W emulsion is called the type transferring point or critical water cut. Table 13.4 lists the critical water cuts for several emulsions at which the emulsions were transferred from W/O to 0/W. From Table 13.4, we can see that adding surfactant and polymer reduced their critical water cuts below 50%, whereas adding 1.2% alkali did not reduce the water/oil critical water cut. Table 13.4 indicates that under ASP flood conditions (high water saturation), most likely, 0/W emulsion will be formed. 

Laboratory studies on oil displacement efficiency by surfactant-polymer flooding process have been reported by a number of investigators (1-10). In general, the process is such that after being conditioned by field brine or preflush, a sandstone core or a sandpack is oil-saturated to the irreducible water content. It is then waterflooded to the residual oil level. Finally, a slug of surfactant solution followed by a mobility buffer is injected. 

Another issue that has only been addressed in a few studies is the effect that polymer adsorption has on the relative permeability of the aqueous and oleic phases that subsequently flood a core. In conventional polymer flooding, this is not a very important consideration since the process usually occurs in one particular saturation direction for example, if the formation is strongly water-wet then the oil displacement by water or polymer solution is an imbibition process. In such a case, the oil would not normally flow at a high saturation in a polymer-flooded zone, although such behaviour is conceivable (but unlikely) in certain polymer oil displacements in layered systems (see... 

The evolution of the polymer flood is explained by Pope in terms of the fractional flow (/ )/saturation (S ) curves for both the water and injected polymer solutions. A typical diagram showing the water and polymer solution fractional flow curves is shown in Figure 8.6. In the theory outlined below the following nomenclature is used. 

Figure 8.5. Water saturation fronts in a linear polymer flood showing the nomenclature for the fractional flow theory in the text (after Pope, 1980).

Example 5,6—Estimation of Pressure Drop Through a Reservoir. A polymer flood is being designed that uses 1,000 ppm xan-than biopolymer. The polymer solution will be injected into a sandstone reservoir at a rate of 10 B/D-ft. The permeability of the reservoir is 200 md, porosity is 0.19, and thickness is 50 ft. Initial oil saturation is 0.70, and ROS is 0.30. A five-spot pattern is planned on 10-acre spacing. Radius of the injection well is 3.25 in., and there is no wellbore damage. At the beginning of the polymer flood, the reservoir is at interstitial water saturation and contains a crude oil with a viscosity of 1.0 cp at reservoir temperature and pressure. For this example, the displacement process is considered piston-like so that a sharp displacement front will form between the displaced oil and the injected polymer solution. Polymer retention and inaccessible PV are ne ected. Determine the bottomhole pressure (BHP) in the injection well when 1,000 bbl of polymer solution have been injected. The average reservoir pressure at the effective radius of the five-spot pattern is 400 psi. 

Example 5.7—Polymer Flood in a Linear Reservoir Originally at Intensdtial (Immobile) Water Saturation. The potential of using polymer-augmented waterflooding to increase oil recovery from a uniform reservoir must be evaluated. For the purposes of this example, consider a linear reservoir segment that is 500 ft wide and 20 ft Ihiek. Production and injection wells are 1,000 ft apart. Properties of the reservoir rock and fluids, summarized in Table 5.19, are identical to those used in Example 3.1. Injection rate is constant at 200 B/D. Relative permeability relationships are =0.8(1.(5.66)... 

Two flood fronts form in this case because S i>S f. The saturation profile is similar to Fig. 3.34 and is characterize by a flood front with saturation S f, an oil bank where the water saturation is constant, and a polymer flood front with saturation 5 3. Table 5.20 presents saturations and fractional flows corresponding to each saturation. Velocities of the three distinct banks calculated from Eqs. 3.142 and 3.143 are also included. Oil recovery during a continuous polymer flood is computed by tracking the three regions as they are displaced through the linear system and then making a material balance as described in Sec. 3.2.7,... 

The drive water is moving faster than the saturations in die polymer bank and gradually overtakes the polymer bank. The drive water arrives at the end of the linear system at the same time as the polymer flood front, x. Fig. 5.59 shows the path traced by the rear of the polymer bank. The location of the rear of the polymer slug is almost a linear function of time for this example. Thus, for this case, the rear of the polymer slug appears to travel at a constant velocity. Fig, 5.59 also shows the waterflood front, oil bank, polymer flood front, and paths of selected saturations in the polymer slug. Saturations in the drive-water region are discussed later. 

The location of the rear of the oil bank at tp is determined by making a material balance on the water phase. Fig. 5.61 is a generalize saturation profile for the displacement of the oil bank by the drive water after the polymer flood front has been overtaken. The total volume of water injected (polymer water and drive water) is given by... 

Solution. During polymer injection (f/j 0.212), the polymer flood performs exactly as described in Examples 5.7 and 5.8. A waterflood front forms at saturation S, followed by an oil bank that has constant water saturation Sw. The oil bank is displaced by a polymer flood front, Sj. Table 5.20 presented properties of these fronts. 

Example 5,11—Estimation of Pressure Drop During a Continuous Polymer Flood in a Linear Reservoir. Determine the pressure drop for the polymer flood in Example 5.7 when the waterflood front, xpf, is located at a distance of 0.75 from the entrance of the system. Base permeability, the permeability to oil at interstitial water saturation, is 250 md. The ipjection rate is constant at 200 B/D. Recall that the linear segment of the reservoir being simulated is 500 ft wide and 20 ft thick. Injection and production wells are 1,000 ft apart. 

In principle, these models simulate the polymer-augmented water-flood performance in each streamtube at constant pressure drop. Fig. 5.70 illustrates the fractional-flow, saturation, and production profiles used in each streamtube. Performance of the pattern is determined by combining the displacement performance of each stream-tube at the same point in time. A model based on streamtube concepts, develops by the U.S. DOE, is available to the public and documented in a report. ... 

An interpretation of these data shows that a water flood would reduce the oil saturation to 60 per cent at 84 per cent water cut while the polymer flood would reduce the saturation to 40 per cent at the same water-cut value. Correspondingly, at 60 per cent oil saturation, the water flood would produce at 84 per cent water cut while the polymer flood would be producing at 25 per cent water cut. Thus, the polymer solution will produce much more oil at a lower water cut. 

There was some variation in the quality of the several patterns with respect to water saturations, as shown by the iso-water cut lines of Fig. 12, so the best, or C, pattern was used for the water flood. D pattern was a flood which was started on brine and then was followed by the polmer solution. E pattern was used to demonstate the use of polymer solution continuously throu out the life of the flood to determine just how much oil could be recovered. F pattern was a modified polymer flood wherein a partial pore volume of polymer solution was injected and then followed by brine. 

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