Chemical enhanced oil recovery is of increasing interest and importance because of high oil prices and the need to increase oil production. The conventional oil recovery methods leave large amounts of oil in the reservoir. This thesis improves the understanding of the chemical enhanced oil recovery processes in order to optimize the chemical flooding operational strategy. The flooding experiments and simulation studies that have been performed shows that the Surfactant, ASP and Polymer strategies successfully recover the oil trapped after water flooding. First, detail laboratory studies for screening of surfactant, alkali and polymer were performed. The laboratory studies included Interfacial Tension, Critical micelle concentration, Dynamic and Static adsorption studies for surfactant and shear thinning viscosity of polymer.
The second task of this project work relates to detailed simulation studies for core and pilot area of field with the help of UTCHEM Compositional Simulator. The purpose of simulation of the core flooding was to match the core flooding laboratory results with the simulation results. Whereas the field scale simulations were done for two different oil fields with different chemical formulation. In the first field the surfactant (low tension water) flooding were done in two different sequences i.e. secondary stage or flooding of chemicals after primary recovery, and the tertiary or flooding of chemical after water flooding. The tertiary stage flooding of chemicals is the conventional procedure. It was found that the surfactant flooding at secondary stage appears to be more beneficial than the tertiary stage flooding. Second field scale simulations were done for the Alkaline, Surfactant, Polymer (ASP) and Polymer Flooding. The selected pilot area for chemical EOR was 170000m2 with five and six spot type pattern. Simulation studies and core flooding were showed that Alkaline, Polymer and Surfactant flooding appears to be more beneficial than the polymer flooding.
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This study showed that it is very important to model both surface active components and their effect on phase behavior when doing mechanistic chemical simulations. The reactions between the alkali and the minerals in the formation depend very much on the type of alkali used, the minerals in the formation, and the temperature. This project work helped us increase our understanding on the process of chemical (ASP/Surfactant/Polymer) flooding. In general, these mechanistic simulations gave insights into the propagation of alkali, soap, surfactant and polymer in the core and will aid in future core flood and field scale chemical flooding designs.
In most light oil reservoirs, over one-half of the oil originally in place remains unrecovered even after a water flood. Some of this oil may be recovered by an appropriate enhanced oil recovery (EOR) method, such as chemical flooding, miscible displacement, or carbon-dioxide flooding. In rare circumstances, even thermal methods may be applicable, although they are better suited for heavy oils.
Chemical methods have great promise for the future in the context of light oils. Chemical EOR methods have been the subject of many laboratory studies and field tests and include such methods as polymer, surfactant, micellar, emulsion, and alkaline flooding techniques and their combinations. Although many field tests have been carried out , chemical floods have not performed as well in the field as in the laboratory, partly because the experiments are usually un scaled. Scaling criteria for chemical floods have been obtained, but are difficult to satisfy consequently, laboratory results. Such as oil recovery vs. pore volumes injected, are not directly applicable to field situations. The extent of reliability of laboratory data for field use depends on the process under consideration.
This study focused on modeling processes to improve oil recovery through the use of a displacing fluid that has a low interfacial tension (IFT) against the displaced crude oil. The IFT between brine and oil must be reduced from 10-30 dynes/cm to about 10-3 dynes/cm to reduce the residual oil saturation to nearly zero under typical reservoir flooding conditions (Green and Willhite, 1998). The effect of IFT on oil recovery is modeled by the capillary desaturation curve where residual oil saturation is correlated as a function of capillary number. To be able to obtain low IFT and achieve good oil recovery, surfactant and polymer are added to the injection water. Surfactant is responsible for reducing the IFT and consequently the residual oil saturation. However, polymer is also necessary for mobility control (Sorbie, 1991). In a typical surfactant/polymer flood, a small slug of about 30% PV containing a relatively low concentration of surfactant and polymer is injected. The injection of the surfactant slug is followed by a polymer drive to maintain mobility control (Green and Willhite, 1998). In alkaline/polymer flooding, only polymer and alkali are injected and the process relies solely on the generation of surfactant in-situ. Jennings et al. (1974) described recovery by emulsification and entrapment.
1.1.1 Enhanced Oil Recovery Mechanisms
Always on Time
Marked to Standard
Based on the overall materials balance of the reservoir, the overall oil recovery efficiency can be defined as:
where N is the Original Oil in place,
Np is the cumulative oil recovered after the recovery process.
The overall efficiency consists of volumetric sweep efficiency Evo and displacement efficiency Edo as the equation (1.2) shows
volumetric sweep efficiency Evo is the fraction of the volume swept by the displacing agent to total volume in the reservoir (Lake, 1989). It depends on the selected injection pattern, character and locations of the wells, fractures in the reservoir, position of gas-oil and oil-water contacts, reservoir thickness, heterogeneity, mobility ratio, density difference between the displacing and the displaced fluid, and flow rate etc. Usually, sweep efficiency can be decomposed as the product of areal sweep efficiency and vertical sweep efficiency. Areal sweep efficiency represents the fraction of total formation area swept by the injected displacing agent; vertical sweep efficiency denotes the fraction of the total formation volume in the vertical plane swept by the injected displacing agent. Poor sweep will significantly reduce the total recovery efficiency and increase recovery costs by increasing the volume of displacing agent required. Sweep efficiency can be greatly improved with mobility control methods, such as polymers, foams and WAG process (alternate water and gas injection). The polymer in ASP process could significantly increase the sweep efficiency.
The displacement efficiency Edo is the ratio of the amount of oil recovered to the oil initially present in the swept volume. It can be expressed in terms of saturation as the equation (1.3).
where Soi is the initial oil saturation,
Sor is the residual oil saturation after oil recovery process.
The displacement efficiency is a function of time, liquid viscosities, relative permeabilities, interfacial tensions, wettabilities and capillary pressures. Even if all the oil were contacted with injected water during waterflooding, some oil would still remain in the reservoir. This is due to the trapping of oil droplets by capillary forces due to the high interfacial tension (IFT) between water and oil. The capillary number Nvc is a dimensionless ratio of viscous to local capillary forces. The viscous force will help oil mobilization, while the capillary forces favor oil trapping (Lake, 1989).
Where: v is velocity, μ is viscosity, σ is interfacial tension.
Capillary Number Nvc
Figure 1.1 Capillary Desaturation Curves for Sandstone Cores (Delshad, 1986, Lake, 1989)
Figure 1.1 shows capillary desaturation curves (CDC) that plot residual saturation of oil versus a capillary number on a logarithmic x-axis (Delshad, 1986, Lake, 1989). From figure 2.2, increasing capillary number reduces the residual oil saturation. The residual oil saturations for both nonwetting and wetting cases are roughly constant at low capillary numbers. Above a certain capillary number, the residual saturation begins to decease. This phenomenon indicates that large capillary number is beneficial to high displacement efficiency because the residual oil fraction becomes smaller. Capillary number must be on the order of 10-3 in order to reduce the residual oil saturation to near zero. Since it is difficult to increase the fluid viscosity or flow rate by several magnitudes, the most logical way to increase the capillary number is to reduce the IFT. Injection flow rates into a reservoir are often on the order of 1 ft/day and water's viscosity is around 1 cp. Therefore, the IFT should be below 10-2 mN/m so that capillary number is around 10-3. The principal objective of the ASP process is to lower the interfacial tension so that the displacement efficiency will be improved. The capillary desaturation curve in figure 1.1 will be used in the simulation in this thesis
If the driving force is gravity force or centrifugal force, Bond number, is used (Hirasaki et al, 1990). Similar to capillary number, larger Bond number will be beneficial to high oil recovery.
where k is permeability
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g is the gravity acceleration or centrifuging acceleration
Δρ is the density difference between oleic and aqueous phases
Pope et al. (2000) proposed a trapping number, which essentially combines the effects of capillary number and Bond number. The definition of trapping number is shown in equation
where NT is the trapping number