Surface Chemistry of Oil Recovery From Fractured, Oil-Wet, Carbonate Formations
- George Hirasaki (Rice U.) | Danhua Leslie Zhang (Rice U.)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 151 - 162
- 2004. Society of Petroleum Engineers
- 4.3.3 Aspaltenes, 5.4.1 Waterflooding, 5.8.7 Carbonate Reservoir, 5.3.4 Reduction of Residual Oil Saturation, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.2.3 Materials and Corrosion, 5.2 Reservoir Fluid Dynamics, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.4 Enhanced Recovery, 4.1.2 Separation and Treating, 5.1 Reservoir Characterisation, 4.3.1 Hydrates, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 6.5.2 Water use, produced water discharge and disposal, 4.3.4 Scale, 1.6.9 Coring, Fishing
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Oil recovery by waterflooding in fractured formations is often dependent on spontaneous imbibition. However, spontaneous imbibition is often insignificant in oil-wet, carbonate rocks. Sodium carbonate and anionic surfactant solutions are evaluated for enhancing oil recovery by spontaneous imbibition from oil-wet carbonate rocks. Crude-oil samples must be free of surface-active contaminants to be representative of the reservoir. Calcite, which is normally positively charged, can be made negative with sodium carbonate. The ease of wettability alteration is a function of the aging time and temperature and the surfactant formulation.
Much oil remains in fractured, carbonate oil reservoirs after waterflooding and in some cases in paleotransition zones, which result from the oil/water contact moving upward before discovery. The high remaining oil saturation is caused by a combination of poor sweep in fractured reservoirs and the formation being preferentially oil-wet during imbibition.1,2 ("Imbibition" is defined as the process of water displacing oil. "Spontaneous imbibition" is defined as imbibition that takes place by action of capillary pressure and/or buoyancy when a core sample or matrix block is surrounded by brine.) Poor sweep is not an issue in paleotransition zones, but the remaining oil saturation may still be significant.
There are several reasons for high remaining oil saturation in fractured, oil-wet, carbonate formations. If the formation is preferentially oil-wet, the matrix will retain oil by capillarity, and high oil saturation transition zones will exist where the upward oil film flow path is interrupted by fractures. This is illustrated in Fig. 1, which shows the oil retained by oil-wet capillaries of different radii. The height of the capillary retained oil column is proportional to the product of IFT and cosine of the contact angle and is inversely proportional to the capillary radius. In oil-wet systems, oil is the phase contacting the rock surfaces, and surface trapping is likely to be particularly important in rocks with highly irregular surfaces and large surface areas (Fig. 2).1
The objective of this investigation is to develop a process to overcome the mechanisms for oil retention illustrated by Figs. 1 and 2. Oil is retained by wettability and capillarity. Thus, by altering the wettability to preferentially water-wet conditions and reducing the IFT to ultralow values, the forces that retain oil can be overcome. Introducing an injected fluid into the matrix of a fractured formation is challenging because the injected fluid will flow preferentially in the fractures rather than through the matrix. Therefore, the process must be designed to cause spontaneous imbibition of the injected fluid from the fracture system into the matrix, as illustrated in Fig. 3. Spontaneous imbibition by capillarity may no longer be significant because of low IFT. However, if wettability is altered to preferentially water-wet conditions and/or capillarity is diminished through ultralow IFTs, buoyancy will still tend to force oil to flow upward and out of the matrix into the fracture system. The injected fluid in the fractures will replace the displaced oil in the matrix, and therefore the invasion of the injected fluid into the matrix will continue as long as oil flows out of the matrix.
Spontaneous imbibition by capillarity is an important mechanism in oil recovery from fractured reservoirs. A recent survey by Morrow and Mason reviews the state-of-the-art.3 They state that spontaneous imbibition rates with different wettability can be several orders of magnitude slower, and displacement efficiencies range from barely measurable to better than very strongly water-wet. The primary driving force for spontaneous imbibition in strongly water-wet conditions is usually the capillary pressure. Reduction of IFT reduces the contribution of capillary imbibition. Buoyancy, as measured by the product of density difference and the acceleration of gravity, then becomes the dominant parameter governing the displacement, even if oil is the wetting phase.4
Application of surfactants to alter wettability and thus enhance spontaneous imbibition has been investigated by Austad et al.5-9 with chalk and dolomite cores. Chen et al.10 investigated enhanced spontaneous imbibition with nonionic surfactants. Spinler et al.11 evaluated 46 surfactants for enhanced spontaneous imbibition in chalk formations. Standnes et al.9 and Chen et al.10 used either nonionic or cationic surfactant with a strategy to alter wettability but avoided ultralow tensions. The work presented here differs from the previous work in that sodium carbonate and anionic surfactants are used to both alter wettability and reduce IFT to ultralow values. The primary recovery mechanism in this work is buoyancy or gravity drainage. Wettability alteration and ultralow IFTs are designed to minimize the oil-retention mechanisms.
It is important to have a representative crude-oil sample when designing an EOR process. Because the process is based on surface phenomena, it is important that the crude oil is free of surface-active materials such as emulsion breaker, scale inhibitor, or rust inhibitor. A simple test for contamination is to measure the interfacial tension (IFT) of the crude-oil sample with synthetic brine. Fig. 4 is a plot of the oil/brine IFT of several crude-oil samples from the same field. These measurements were made with a pendant drop apparatus with automatic video data acquisition and fit to the Young-Laplace equation. Samples MY1 and MY2 have low initial IFT that further decreases with time. This is an indication that these samples contain a small amount of surface-active material, which slowly diffuses to the interface and reduces the IFT. Samples MY3 through MY6 have a much larger initial IFT. Even though there is some decrease in IFT with time, the IFT remains in the range of 20 to 30 mN/m. Some early experiments were made with MY1 before we were aware of the contamination, but the later experiments were made with MY3.
The properties of the crude-oil samples are listed in Table 1. The higher acid number and viscosity for MY1 compared with the other samples suggest that it may be an outlier. The wettability of the oil samples were compared by pressing an oil drop in brine against a calcite (marble) or glass plate for 5 to 10 minutes, withdrawing the drop, and measuring the water-advancing contact angle after motion has ceased. The water-advancing contact angles of MY1 and MY3 against calcite or glass after aging time of 5 to 10 minutes are compared in Fig. 5. Clearly, MY1 and MY3 crude oils have different wettability properties.
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