Thermally Induced Wettability Alteration to Improve Oil Recovery in Fractured Reservoirs

Abstract

Abstract Many naturally fractured reservoirs are oil-wet and during water injection water will not imbibe into the matrix but will preferentially flow through the fractures resulting in very low oil recoveries. For instance, the Ghaba North field in Oman is an extensively fractured oil-wet carbonate which that has only achieved 2% recovery after over 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 is increased. The temperature could be increased in a reservoir setting through steam or hot water injection. The wettability change is due to desorption of asphaltenes from the rock surface. It is proposed to inject steam or hot water to heat the matrix sufficiently to induce a wett ability change, rendering it water-wet. Hot water in the fractures can spontaneously imbibe into the matrix displacing oil and resulting in favorable oil recoveries. A one-dimensional model of the saturation and temperature profiles during imbibition into a matrix block is developed and solved analytically. Example solutions and typical time scales for recovery are proposed. Using Ghaba North properties the imbibition rate is limited by thermal diffusion through the oil. The advancing water front is located where the rock temperature equals the transition temperature for wett ability change. It is estimated that around 30% oil recovery could be achieved in single matrix block after approximately 700 days. In less permeable media, the imbibition rate is limited by capillary forces, and the temperature front would move ahead of the water, resulting in slower recovery. Introduction In this paper we will investigate the use of steam or hot water injection for improved oil recovery in fractured reservoirs. To illustrate the potential of the method, we will discuss its application to the Ghaba North field in Oman. However, the analysis presented here is general and the recovery strategy proposed could be readily applied to other suitable fields. Ghaba North Shuaiba has relatively thin liquid column (64 m) compared with other nearby fields such as Natih and Fahud which have 260 m 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 over 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 water drive. 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 NE-SW tending anticline. Core and Formation Micro Scanner (FMS) studies have indicated fractures to be sub-vertical and extensional in nature. They form an open, interconnected network with a spacing of 5 to 10 m through the Shuaiba reservoir.1,2