Incremental oil

For a single stage separator i.e. only one separator vessel, there is an optimum pressure which yields the maximum amount of oil and minimises the carry over of heavy components into the gas phase (a phenomenon called stripping). By adding additional separators to the process line the yield of oil can be increased, but with each additional separator the incremental oil yield will decrease. 

Figure 10.9 Incremental oil yield versus separator stages...

Oil-field chemistry has undergone major changes since the publication of earlier books on this subject Enhanced oil recovery research has shifted from processes in which surfactants and polymers are the primary promoters of increased oil production to processes in which surfactants are additives to improve the incremental oil recovery provided by steam and miscible gas injection fluids. Improved and more cost-effective cross-linked polymer systems have resulted from a better understanding of chemical cross-links in polysaccharides and of the rheological behavior of cross-linked fluids. The thrust of completion and hydraulic fracturing chemical research has shifted somewhat from systems designed for ever deeper, hotter formations to chemicals, particularly polymers, that exhibit improved cost effectiveness at more moderate reservoir conditions. 

Major disincentives to enhanced oil recovery are the lack of tax incentives and a substantial decline in the price of oil since the end of 1981. All the investment in new wells and surface facilities and injectants must take place before any incremental oil is produced. 

Increasing the water-wet surface area of a petroleum reservoir is one mechanism by which alkaline floods recover incremental oil(19). Under basic pH conditions, organic acids in acidic crudes produce natural surfactants which can alter the wettability of pore surfaces. Recovery of incremental oil by alkaline flooding is dependent on the pH and salinity of the brine (20), the acidity of the crude and the wettability of the porous medium(1,19,21,22). Thus, alkaline flooding is an oil and reservoir specific recovery process which can not be used in all reservoirs. The usefulness of alkaline flooding is also limited by the large volumes of caustic required to satisfy rock reactions(23). 

TFSA molecules have been extensively and successfully used as steam additives in cyclic steam operations(27-32). Recently, results of a TFSA-waterflood which was conducted in West Texas were reported(33). The purpose of the work described in this paper was to further evaluate the feasibility of recovering incremental oil in a mature waterflood by injection of surfactants which change the wettability of reservoir rock surfaces. In this paper, we present the results of laboratory studies with Thin Film Spreading Agents and the results of a carefully conducted TFSA-waterflood pilot in the Torrance Field located in the Los Angeles Basin of California. 

RECOVERY MECHANISMS. Being surface active, TFSAs lower oil-water inter facial tension, but not by the three orders of magnitude needed to increase the capillary number sufficiently to recover a substantial amount of incremental oil. Instead, TFSAs enhance the recovery of oil by changing the wettability of reservoir rock surfaces from oil-wet and intermediate wettability to strongly water-wet, and by coalescing emulsions in the near-wellbore region of the production wells. 

Incremental oil production for each of the pilot wells was calculated by subtracting the extrapolated production decline curve which was established prior to TFSA injection from the actual production after TFSA injection. Results of this analysis indicate that a total of 8150 + 850 bbl (1295 + 135 m3) of incremental oil were obtained due to injection of TFSA. 

Incremental oil production was assumed to have ceased by October 10, 1987 when the two high brine producing Wells TU-107 and TU-104 were shut in. 

In the first case, the minimum values for the economic yardsticks were evaluated assuming that a conservative 7300 bbl (= 8150 bbl -850 bbl 1160 m3 = 1295 m3 - 135 m3) of incremental oil had been produced by the end of the project. Maximum values for the economic data were calculated by assuming that 9000 bbl (= 8150 bbl + 850 bbl 1430 m3 = 1295 m3 + 135 m3) of incremental oil were produced by only 61.6 % of the TFSA which had been injected into Well TU-120 this assumption is based on the results of the tracer study which showed that as much as 38.4 % of the injected fluids flowed out of the pilot pattern. In the final case, the most probable values for the economic yardsticks were calculated assuming the 8150 bbl (1295 m3> of incremental oil were produced by 90 % of the TFSA. 

At a sales price of 13.00 per barrel, the value of the incremental oil produced by the TFSA was between 94,900.00 and 117,000.00. This revenue was generated at a chemical cost of between 1.93 and 3.87 per incremental barrel. Cumulative incremental oil production, shown in Figure 5, indicates that the volume of incremental oil produced reached a constant and maximum value 18 months after the pilot was started. Of the total incremental oil recovered, 37.5 % was produced in the first six months of the pilot and 81.25 % was produced by the end of the... 

Assumes minimum amount of incremental oil production and that none of the TFSA flowed out of the pilot. 

Figure 5. Cumulative incremental oil production indicates that 8150 bbl of incremental oil were recovered by TFSA.

Since Thin Film Spreading Agents do not produce ultralow interfacial tensions, capillary forces can trap oil in pore bodies even though the oil has been displaced from the surface of the porous medium. Therefore, recovery of incremental oil is dependent on the formation of an oil bank. Muggee, F. D. U.S. Patent 3 396 792, 1968. 

Figure 7.2 Wildcat and incremental oil exploration in the Persian Gulf...

Table 11.2 Illustration of the effect of changing the composition of injected solution on incremental oil recovery in an enhanced oil-recovery process. ... 

It can be anticipated that all gas-flood projects, as they are presently being carried out, will leave a large fraction of the reservoir oil uncontacted by the injected fluids. This bypassed oil will remain in place, undisplaced by the injected fluid. Thus, in each current field project, the amount of incremental oil produced by gas flooding could be substantially increased if the uncontacted oil could be reached. The improvement of the vertical and areal distribution of injected fluids throughout the reservoir, so that they contact substantially more oil, will require much better methods of sweep and mobility control. 

We have seen that a very large amount of oil is believed recoverable by gas flooding (more than 15 billion barrels in the United States alone) and that large financial commitments already have been made to produce that target oil. Over 60 field projects are planned and many of these are already in operation and beginning to produce incremental oil. 

Field Application. Field trials of classical alkaline flooding have been disappointing. Mayer et al. (60) indicated that only 2 of 12 projects had significant incremental oil recovery North Ward Estes and Whittier with 6-8 and 5-7% pore volume, respectively. Estimated recovery from the Wilmington field was 14% with a classical alkaline flooding method (61). However, post-project evaluation of that field indicated no improvement over water-flooding (62). 

This developed miscibility process results in a miscible fluid, that is capable of displacing all the oil which it contacts in the reservoir... The efficiency of this displacement is controlled by the mobility (ratio of relative permeability to viscosity) of each fluid. If the displacing fluid (i.e. carbon dioxide) is more mobile than that being displaced (i.e. crude oil) then the displacement will be relatively inefficient. Some of the residual oil saturation will never come into contact with carbon dioxide. Both laboratory and field tests have indicated, that even under favourable condition, injection of 0.15-0.6 10 m of carbon dioxide is required for recovery of an additional barrel (0.16 m ) of oil". Here our goal is to obtain a mass ratio of CO2 to incremental oil of 1 to 4, on the basis of the Bonder s data. 

Oil recovery has been significantly enhanced by the injection of CO2 and hydrocarbon gases. The typical incremental oil is about 8-14% OOIP for tertiary injection. For example, the SACROC field quadrupled the oil production rate and produced more than 10% of the OOIP. In secondary injections, for example, in Block 31 field in Texas, the oil recovery is close to 60% of the OOIP. Improved reservoir management in the preparation of CO2 flood also added to improved recovery. For example, in the Means field, well spacing was changed from 20 acre/pattern to 10 acre/pattern and five-spot to inverted nine-spot. These changes increased oil production rate from 7,000 to 10,000 b/d, even before CO2 injection. 35% of the FOR oil was produced because of improved reservoir management. 

A common measure of the success of an EOR process is the incremental oil recovery factor. Figure 1.3 shows the schematic of incremental oil recovery from an EOR process. The oil production rates from B to C are extrapolated rates, and the cumulative oil at D is the predicted ultimate oil recovery had the EOR process not been initiated at B. The time from B to C is required to... 

Another measure of the success of chemical EOR is the amount of chemical injected in pounds per barrel of incremental oil produced (Ib/bbl), or tons of oil produced per ton of chemical injected, a figure often used in China to represent polymer flooding efficiency. Chang et al. (2006) reported that incremental oil recovery factors of up to 14% of the OOIP have been obtained in polymer flooding good-quaUty reservoirs, and incremental oil recovery factors of up to 25% of OOIP have been reported in ASP pilot areas. 

BP laboratory results (Lager et al., 2006) showed an average benefit of 14% with low-salinity brine, and a large scatter of results from -e4 to -t40% was observed. Such a wide spread of results was also observed by Morrow and coworkers. In some core floods, no incremental oil recovery was observed. 

Martin (1959) and Bernard (1967) observed that clay swelling and/or dispersion accompanied by increased pressure drop resulted in incremental oil recovery. Tang and Morrow (1999) concluded that line mobilization (mainly kaolinite) increased recovery based on their observations (1) fired/acidized Berea core showed insensitivity of salinity on oil recovery, whereas unlired Berea core did show sensitivity and (2) for clean sandstones, the increase in oil recovery with the decrease in salinity was less than that for the clay sands. Figure 3.4 shows some of their results. In the tests, the reservoir CS core was used. The reservoir brine, CS RB, was used as connate brine for the entire CS core tests. 

Eor a typical well. Well 95-18, a gel solution was injected from July 26 to August 6,2003, with the total injection volume of 1800 m. The well treatment radius was 10 m. After the treatment, the water intake thickness increased from 9.6 to 20.4 m, and the water intake layers increased from 6 layers to 8 layers. The effective time was 219 days. The cumulative incremental oil was 986 tons (Chen et al., 2004). A similar laboratory evaluation report of the polymer was done by Li et al. (2006b), and a more detailed report of the field trials was made by Li et al. (2006a). 

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