Thermally Induced Wettability Alteration To Improve Oil Recovery in Fractured Reservoirs
- Hamed S. Al-Hadhrami (Petroleum Development Oman) | Martin J. Blunt (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- June 2001
- Document Type
- Journal Paper
- 179 - 186
- 2001. Society of Petroleum Engineers
- 5.5 Reservoir Simulation, 4.6 Natural Gas, 4.3.4 Scale, 1.6.9 Coring, Fishing, 5.5.3 Scaling Methods, 2.4.3 Sand/Solids Control, 5.1.2 Faults and Fracture Characterisation, 5.5.2 Core Analysis, 1.2.3 Rock properties, 6.5.2 Water use, produced water discharge and disposal, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.3.3 Aspaltenes, 5.1.1 Exploration, Development, Structural Geology, 5.8.7 Carbonate Reservoir, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 2.2.2 Perforating, 5.4.6 Thermal Methods, 5.4.2 Gas Injection Methods, 5.1.5 Geologic Modeling, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.8.6 Naturally Fractured Reservoir, 5.2 Reservoir Fluid Dynamics
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Many naturally fractured reservoirs are oil-wet; during water injection, water will not imbibe into the matrix but will flow preferentially through the fractures, resulting in very low oil recoveries. For instance, the Ghaba North field in Oman is an extensively fractured, oil-wet carbonate that has achieved only 2% recovery after more than 20 years of production.
Experiments on core from fields in Oman and elsewhere have indicated that the rock will undergo a transition from oil-wet to water-wet as the temperature increases. The temperature could be increased in a reservoir setting through steam or hot-water injection. It is proposed to inject steam or hot water to heat the matrix sufficiently, inducing a wettability change and rendering the matrix water-wet. Hot water in the fractures can spontaneously imbibe into the matrix, displacing oil and resulting in favorable oil recoveries.
A 1D model of the saturation and temperature profiles during imbibition into a matrix block is developed and solved analytically. Using Ghaba North properties, it is shown that the imbibition rate is limited by the diffusion of heat through the oil. The advancing water front is located where the rock temperature equals the transition temperature for wettability change. It is estimated that approximately 30% oil recovery could be achieved in a single matrix block after approximately 700 days. In less permeable media, the imbibition rate is limited by capillary forces, and the temperature front moves ahead of the water, resulting in slower recovery.
In this paper, we investigate the use of steam or hot-water injection for improved oil recovery in fractured reservoirs. To illustrate the potential of the method, we discuss its application to the Ghaba North field in Oman. However, the analysis presented here is general, and the recovery strategy proposed could be applied readily to other suitable fields.
Ghaba North Shuaiba has a relatively thin liquid column (64 m) compared with other nearby fields such as Natih and Fahud, which have 260- and 460-m reliefs, respectively. The Shuaiba reservoir originally contained some 119 million m3 of 890 kg/m3 (27°API) oil. The formation has an average porosity of 30%. Average reservoir permeability varies with fracture development, from 10 md in the unfractured matrix blocks (as derived from core measurements) to more than 100 md in fractured samples.1,2
Ghaba North Shuaiba is a salt-induced faulted anticline structure. The reservoir is a fractured, chalky limestone that produces under the influence of a strong natural waterdrive. The oil is produced from the fractured carbonate reservoir and the upper, middle, and lower sand shale units of the Gharif formation. The Ghaba North structure is a 15×8 km northeast/southwest-tending anticline. Core and Formation Micro Scanner (FMS) studies have indicated fractures to be subvertical and extensional in nature. They form an open, interconnected network with a spacing of 5 to 10 m through the Shuaiba reservoir.1,2
The field was discovered in 1972 and brought into production in 1975, but it was shut down in 1979 because of unfavorable performance. In 1984, matrix oil displacement by gas/oil gravity drainage (GOGD) was proposed to improve production. The production mechanism involves drainage of oil by gravity from an oil-filled reservoir matrix, which is surrounded by a gas-filled fracture system. The drained oil forms an oil rim in the fracture system, below the fracture gas-cap, and wells are perforated in the oil rim. The gross production rate was increased to reduce reservoir pressure in an attempt to establish a secondary gas cap. Production performance has since demonstrated that the aquifer is too strong to allow the reservoir pressure to fall significantly. Between 1990 and 1995, a second attempt was made to create a gas cap by gas injection into two wells. However, these projects have proved unsuccessful to date, and only 2% recovery has been achieved overall.
The use of steam injection in Qarn Alam, a neighboring field in Oman, has been tested recently in a pilot study.3,4 Steam injection started in 1996 but was stopped in 1997 because of problems with the steam-injection plant. Injection resumed in September 1998 and continues today. Oil production has increased from around 300 m3/D to 1400 m3/D; this increase is attributed to steam injection. An elegant analysis of the process showed that gravity drainage resulted in good recoveries, even if the reservoir remained oil-wet.5 However, there are three significant differences between Ghaba North and Qarn Alam. First, the depth of the oil column in Qarn Alam is 165 m, compared with 64 m in Ghaba North. This increased relief has allowed the creation and expansion of a gas cap in Qarn Alam, while an attempt to create an artificial gas cap in Ghaba North has failed. Second, Ghaba North oil has a viscosity of only 7 mPa·s, compared with 200 mPa·s in Qarn Alam. Steam injection in Qarn Alam reduces the oil viscosity to an estimated 2 mPa·s,5 allowing rapid drainage of oil. In Ghaba North, such a reduction in viscosity may not be necessary to achieve recoveries in an economic time scale. Third, the spacing of fracture channels in Qarn Alam is 1.5 to 4 m;3 in Ghaba North, the fractures are more widely spaced. This means that for Qarn Alam, it might be reasonable to assume instantaneous thermal equilibrium between fracture and matrix in a field setting,5 but in Ghaba North, the time scale for heat transport into the matrix may be significant. This combination of a low relief, a moderately light oil, and a wide fracture spacing implies that Ghaba North is a poor candidate for steam injection. However, as we discuss later, the use of steam injection to induce a wettability change in the reservoir may lead to good recoveries.
Because a number of strategies to improve production in Ghaba North have failed, we now consider different possible recovery mechanisms. Reviews of reservoir wettability have concluded that carbonate reservoirs in the Middle East and elsewhere are usually oil-wet.6,7 If the rock is oil-wet, water must overcome a capillary barrier to invade the rock matrix and displace the oil. Water invasion is a secondary-drainage type process. The capillary pressure necessary to enter the matrix can be estimated with the Leverett J function.8,9
where J*=a dimensionless entry pressure, with a value typically around 0.25.8 If the oil/water interfacial tension s=50 mN/m, permeability k=10 mD (=10-14 m2) and porosity f=0.3 - values representative of Ghaba North - we estimate a capillary barrier of approximately 70 kPa.
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