Water bank, waterflood

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... 

A WAG process is to be implemented on a reservoir that was previously waterflooded to a ROS, Sor- Eqs- 5.189 and 5.190 give relative oil and water permeabilities, respectively, of 5/, =0.363 and Sor =0.205. Residual oil is to be displaced by a WAG process where the solvent viscosity is 0.04 cp. Water and oil viscosities are 1.0 and 3.0 cp, respectively. Water and solvent injection rates are to be set so that the water and solvent flow at equal velocities in the solvent/water bank that displaces the oil bank. Calculate the relative water and solvent injection rates. Assume linear flow, as in Example 5.19. 

In accordance with Eqs. 2 and 3, the connate water bank will break through at / = (S - 5,)/fy, and the polymer front and associated saturation discontinuity will break through at / = (S + b)/fg. Fig. 5 shows the oil recovery curve constructed from Eqs. 2 through 4 and, for comparison, the recovery curve for a normal waterflood as calculated by the Buckley-Leverett method. 

From the previous discussions, the residual oil was pulled and stripped from the rock surfaces. As shown in a 2D glass-etched model (see Figure 6.24), the residual oil after waterflood became isolated oil droplets. The polymer solution pulled the oil into oil columns. These oil columns became thinner and longer to form oil threads as they met the residual oil downstream. The oil upstream flowed along these oil threads to meet the residual oil downstream so that an oil bank was built. In the process of residual oil flowing along the oil threads, because of the cohesive force of the oil/water interfaces, it was also possible to form new oil droplets, which flowed downstream and coalesced with other oils. Now we are ready to discuss the role viscoelasticity plays. 

Sodium carbonate and sodium tripolyphosphate were added to the water to obtain the desired interfacial behavior. Figure 7.48 shows that the first peak (marked as 24) represents the maximum surfactant concentration at the effluent end from slug 4 (saline water). The second peak (marked as 26) represents the maximum concentration obtained by less saline waterflooding. Note that peak 26 is higher than peak 24. The second bank of surfactant was formed from the desorption of surfactant left by the first bank of surfactant solution on the solid surfaces. 

Waterflooding recovers oil by the water s moving through the reservoir as a bank of fluid and pushing oil ahead of it. The recovery efficiency of a waterflood is largely a function of the sweep efficiency of the flood and the ratio of the oil and water viscosities. 

If we assume that in these chemical floods in water-wet cores the surfactant sees as much rock surface when oil is present at or below waterflood residual as it sees when there is no oil present at all, we can take PV gp = 0.04 from the flow experiment run under the same conditions in the absence of oil. The oil cut in the clean oil bank in this flood was 0.34, and = 0.82 by... 

The results of the tertiary and Ca(0H)2 secondary floods are presented in Figures 13 and 14. In the waterflood, breakthrough of the flood water occurred after injection of 0.6 pore volumes of distilled water. The secondary waterflood recovered 71.7 percent of the original oil in place. In the subsequent tertiary mode alkaline flood, oil appeared in the effluent after 1.2 pore volumes of calcium hydroxide were injected into the waterflooded core. The tertiary oil production was delayed because a finite residence time is required for emulsification of the entrapped residual oil, coalescence of the water-in-oil emulsion and subsequent mobilization of the coalesced droplets into an oil bank. 

The plot of dimensionless pressure drop versus pore volumes injected for the secondary mode alkaline flood (Figure 15) indicates that breakthrough occurs at the same amount of pore volumes during the waterflood (i.e., T = 0.58 PV approximately) and during the calcium hydroxide flood. However, in the secondary mode alkaline flood, the pressure drop continues to increase because of the in situ formation of a water-in-oil emulsion phase after breakthrough. As in the tertiary mode alkaline flood, the emulsified phase restricts the flow of the displacing phase and increases the pressure drop. The increased AP indicates the formation of an oil bank... 

The pressure history of the secondary alkaline flood reflects the formation of a secondary oil bank behind the immiscible phase oil bank. This secondary oil bank results in an overall recovery which is above that obtained by secondary waterflooding or by secondary caustic flooding with an univalent ion of high electrolyte concentration. The concentration history of the fractional water production during the secondary calcium hydroxide flood represents the total consumption of the hydroxyl ion. This consumption curve is made up of consumption due to adsorption of the silica surfaces and consumption due to the in situ chemical reaction which forms the more oil-soluble, surface-active salt, calcium oleate. 

Region 1 Waterflooded residual oil saturation, only water is flowing. Region 2 An oil bank is formed, both oil and water are flowing. 

Low Tension Polymer Water Flood. In oil reservoirs, where the critical capillary number is relatively low, a significant amount of waterflooded residual oil can be displaced by surfactants of high efficiency even at two-phase flood conditions. This was demonstrated by the snccessfnl second Ripley surfactant flood pilot test in the Loudon field where approximately 68% of waterflooded residual oil was recovered by injecting a 0.3 PV microemulsion bank [63]. The microemulsion bank was followed by I.O PV of higher viscosity polymer drive. The chemical formnlation consisted of a blend of two PO-EO sulfates. 

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. 

When the polymer front is overtaken by the drive water, the process becomes a waterflood. For example, when tpp=DJ2 (in Example 5.8), the polymer front is overtaken at =0.5/1.2377= 0.404. Fig. 5.61 shows the saturation distribution at this instant. Note that the oil bank created by the polymer front is present, with a saturation discontinuity from to 5 ,x at the rear of the oil bank. This saturation discontinuity is not stable. Because of miscibility, the velocity of this discontinuity 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. 

Displacement of oil by waterflooding is increasingly dominated by viscous forces as the viscosity of the oil displaced increases. When the oil mobility is less than that of the injected water, the oil-water interface is not a piston-like front." Instead, instabilities occur at the flood front in the form of viscous fingers which tend to penetrate the less mobile oil bank. The magnitude of these protrusions, or the degree of channeling, increases... 

We have found that solutions of typical waterflooding polymers do not occupy all of the connected pore volume in porous media. The remainder of the pore volume is inaccessible to polymer. This inaccessible pore volume is occupied by water that contains no polymer, but is otherwise in equilibrium with the polymer solution. This allows changes in polymer concentration to be propagated through porous media more rapidly than similar changes in salt concentration. At the front edge of a polymer bank the effect of inaccessible pore volume opposes the effect of adsorption and may completely remove it in some cases. 

Fig. 16 shows the numerically calculated oil recovery for the three cases of 0.13, 0.3 and 0.3 PV polymer bank sizes. The numerically calculated five-spot waterflood recovery curve is shown for comparison. The calculated recoveries for the waterflood and the 0.3 PV bank polymer flood after injection of 1 PV are 0.237 and 0.366 PV oil, respectively. These figures give 0.109 bbl incremental oil from the polymer flood for 0.3 bbl of polymer water injected, or 0.363 bbl oil per bbl of polymer water. This represents about 8.33 incremental oil per 11.00 of polymer injected. This figure is based on 3/bbl of oil and a polymer cost of 13 /bbl of 270 ppm Kelzan solution. In addition, the lower water-oil ratio during the polymer flood will reduce water handling costs. 

Several cases were studied in which the sensitivity of oil recovery to variations in polymer-bank size, polymer concentration, heterogeneity, retention, resistance factor, crossflow, and degradation was determined. Incremental oil recovery of polymer flooding over waterflooding was determined by comparing the oil recovered from a base waterflood with the oil recovered from the various polymer floods at an arbitrary WOR of 24 (96-percent water cut). Tables 4 and 5 give a detailed description of all the cases considered in this study. 

In general, the effect of polymer-bank size and concentration is predictable in the sense that the more polymer injected, the more oil will be recovered. Fig. 8 shows a plot of WOR vs oil recovery for the base waterflood, a 20-percent-PV, 600-ppm polymer bank, and a 30-percent-PV, 600-ppm bank. Incremental oil recoveries for the 20- and 30-percent banks are 43 and 51 STB/acre-ft, respectively. Fig. 9 shows the same plot for 20-percent-PV, 300- and 600-ppra banks with incremental oil recoveries of 23 and 43 STB/acre-ft, respectively. The effect of preinjecting water can be strong, depending on heterogeneity (Table 4). 

Subsequently, close to 2 pore volumes of polymer solution, at a concentration of 1,500 ppm, were injected into the core after the initial waterflood (see Figure 1). Injecting the polymer formulation with an effective viscosity of 25 mPa s, at a rate of 2 ml/hr, caused a rapid pressure increase. The oil was banked ahead of the polymer front, and the water cut decreased to 40%. The oil... 

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