Original oil in place

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. 

For the field-scale projects that have been initiated, calculated optimum CO2 injection volumes ranged from 20 to 50 percent of the hydrocarbon pore volume. Predicted carbon dioxide utilization factors ranged from 5 to 15 Mcf C02/bbl of recovered oil. Projected ultimate enhanced oil recoveries ranged from 5 to 30 percent of the original oil-in-place (Soc. Petrol. Engrs. Forum Series, "Monitoring Performance of Full-Scale CO2 Projects," August 17-21, 1987). 

Table II. Comparison of Computer Simulated and Lab Model Enhanced Oil Recoveries (Percent EOR Recovery Basis Original Oil In Place)...

OOIP = original oil in place in a given system, volume units. 

The average oil produced in the two initial waterfloods was 305 cc. With an initial oil volume of 870 cc, the recovery in the initial waterflood phase is 35% of the original oil in place. The total oil produced in the case of the conventional carbon dioxide flood was 510 cc which is 58.1% of the initial oil. When mobility control was used the total oil recovered increased to 585 cc which represents 67.4% of the original oil. A summary of the results are shown in Table II. 

Fiori and Farouq Ali (73) proposed the emulsion flooding of heavy-oil reservoirs as a secondary recovery technique. This process is of interest for Saskatchewan heavy-oil reservoirs, where primary recovery is typically 2-8%. Water-flooding in these fields produces only an additional 2-5% of the original oil in place because of the highly viscous nature of the oil. In laboratory experiments, a water-in-oil emulsion of the produced oil is created by using a sodium hydroxide solution. The viscous emulsion formed is injected into the reservoir. Its high viscosity provides a more favorable mobility ratio and results in improved sweep of the reservoir. Important parameters include emulsion stability and control of emulsion viscosity. 

Reservoir Characterization and Production Status The Xing-28 block had 2.05 km, reservoir thickness of 3 m, and original oil in place (OOIP) of 0.96 million tons. It had an anticline structure and a gas cap of 1.08 km with a thickness of 2.6 m. It also had edge water, and the reservoir... 

In this chapter the properties of nonaqueous hydrocarbon foams will be reviewed and the effects of foam formation on flow of oil—gas mixtures in porous media will be discussed A laboratory technique for investigating the role of foamy-oil behavior in solution gas drive is described, and experimental verification of the in situ formation of non-aqueous foams under solution gas drive conditions is presented The experimental results show that the in situ formation of nonaqueous foam retards the formation of a continuous gas phase and dramatically increases the apparent trapped-gas saturation. This condition provides a natural pressure maintenance mechanism and leads to recovery of a much higher fraction of the original oil in place under solution gas drive. 

The fc mulation concept was one of the aims of a large-scale research effort to develop enhanced oil recovety methods after the 1973 oil embargo. The goal was to inject a surfactant solution in the oil reservoir in order to overwhelm the capillaiy forces that trap the almost 75% of the original oil in place remaining in the reservoir after waterflooding. 

Calculation of natural gas requirements for thermal recovery process such as steam injection for West Sak heavy oil show that approximately 18 TSCF of natural gas would be needed. These calculations assume the heating value of natural gas as 1000 Btu/SCF, efficiency of steam generator to be 70%, oil-steam ratio of 0.2, ultimate oil recovery of 30% of original oil in place and, energy content of steam to be 1160 Btu/lb. 

It has been proven in field projects that polymer flooding can improve the oil yield. This is reflected by a 50% increase in the number of projects from 1984-1986 in the United States. 2). jhe results of these polymer flood projects have confirmed that, if designed properly, polymers can also be applied successfully to highly saline reservoirs, recovering cl,. 10-20% OOIP (original oil in place).(3,4)... 

Below the bubble-point, pressure gas percolates out of the oil phase, coalesces and displaces the crude oil. The gas phase, which is much less viscous and thus more mobile than the oil phase, fingers through the displaced oil phase. In the absence of external forces, the primary depletion inefficiently produces only 10 to 30 percent of the original oil in place. In the secondary stage of production, water is usually injected to overcome the viscous resistance of the crude at a predetermined economic limit of the primary depletion drive. The low displacement efficiencies, 30 to 50 percent, of secondary waterfloods are usually attributed to vertical and areal sweep inefficiencies associated with reservoir heterogeneities and nonconformance in flood patterns. Most of the oil in petroleum reservoirs is retained as a result of macroscopic reservoir heterogeneities which divert the driving fluid and the microscopically induced capillary forces which restrict viscous displacement of contacted oil. This oil accounts for approximately 70 percent, or 300 x 10 bbl, of the known reserves in the United States. 

Recovery of acidic oils with alkaline agents by an emulsification and coalescence mechanism Calcium hydroxide [Ca(0H)2] was used to verify the emulsification and coalescence concept since, as suggested by the theoretical and experimental evidence of an earlier section, the carboxylic salts of divalent ions form unstable emulsions of water-in-oil. The emulsification and coalescence concept was quantitatively verified by secondary and tertiary flooding of partially oil-saturated sandpacks. A tertiary chemical flood with Ca(0H)2 (pH = 12) recovered 44 percent of the waterflood residual oil from a 3.5-darcy Ottawa sandpack the oil had an acid number of 2 and a viscosity of 1.5 cp. A secondary caustic flood with Ca(0H)2 (pH = 12.32) recovered 82.3 percent of the original oil in place from a 0.25-darcy Ottawa sandpack the oil phase in this secondary flood had the same physical and chemical properties as the oil phase used in the tertiary mode flood. It should be noted that the microscopic mobilization efficiencies of these... 

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. 

Enhanced OO Recovery (EOR). This process refers to the recovery of oil that is left behind after primary and secondary recovery methods have either been exhausted or have become uneconomical. Enhanced oil recovery is the tertiary recovery phase in which surfectant-polymer (SP) flooding is used. SP flooding is similar to waterflooding, but the water is mixed with a surfactant-polymer compound. The surfactant literally cleans the oil off the rock and the polymer spreads the flow through more of the rock. An additional 15 to 25 percent of original oil in place (OOlP) can be recovered. Before this method is used, there is a great deal of evaluation and laboratory testing involved, but it has become a reliable and cost-effective method of oil recovery. 

The production of petroleum from a reservoir may be divided into different phases. The, first stage of oil recovery is where the flow is under the reservoir pressure. Very early in the life of a reservoir, energy must usually be supplied to the porous medium, which bears the crude oil so that it continues to flow to the producing wells. This energy is brought into the reservoir by injection of water or gas (nitrogen, methane, COj) (Tunio et al., 2011). With these secondary recovery methods, about 30%-40% of the original oil in place may be recovered, while the rest may be left in the earth. 

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