Utilization of co2 for pressure maintenance and improving oil recovery in heavy oil reservoirs.

Abstract

Tremendous resources of heavy oil are located in Western Canada, i.e., Alberta and Saskatchewan, most of which are contained in thin payzones. Thermal-based techniques have conventionally been utilized to enhance heavy oil recovery. However, characteristics of these thin reservoirs result in excessive heat losses to adjacent formations, leading to thermal-based techniques ineffective and uneconomical in such heavy oil formation. Although pressure maintenance via gas injection has been applied in light and medium oil reservoirs, few attempts have been made to evaluate performance of CO2 injection for such purpose in a heavy oil reservoir. It is of practical and fundamental importance to evaluate suitability of pressure maintenance and improving heavy oil recovery with CO2 injection in thin payzones where other enhanced oil recovery (EOR) techniques are not applicable. In this thesis study, techniques have been developed to experimentally and numerically evaluate performance of CO2 injection in heavy oil reservoirs for the purpose of pressure maintenance and improving oil recovery. Experimentally, a three-dimensional (3D) displacement model consisting of five vertical wells and three horizontal wells is used to evaluate the performance of waterflooding-CO2 injection, waterflooding and CO2-alternating-water (CO2 WAG), and continuous CO2 injection processes, respectively. Three well configurations have been designed to examine their effects on heavy oil recovery. The corresponding initial oil saturation, oil production rate, water cut, oil recovery and residual oil saturation distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters. It is found that utilization of CO2 for pressure maintenance is beneficial for heavy oil recovery and that well configuration plays a crucial role in enhancing oil recovery. The well configurations with horizontal well(s) are found to control a larger reservoir area and initiate a better sweep efficiency, leading to higher oil recovery. There exists an excellent agreement between the numerically simulated and experimentally measured oil recovery, demonstrating that numerical simulation has captured the overall mechanisms of both the waterflooding-CO2 injection process and waterflooding-CO2 WAG process. The optimum WAG ratio is determined to be 0.75 and 1.00 for two CO2 WAG processes, respectively. To facilitate screening a right candidate for pressure maintenance with CO2 injection in heavy oil reservoirs, screening criteria associated with reservoir temperature, pressure, API gravity, oil saturation, net pay thickness and permeability have been developed. The central composite design (CCD) technique is successfully used to design reservoir simulation strategies. Three response surface models with good statistics have been developed based on the simulation results. Pressure and API gravity are found to be the most influential reservoir properties on the performance of CO2 injection in heavy oil reservoirs. It is convenient and efficient to screen and rank the candidate reservoirs on the basis of oil recoveries that are evaluated through the newly proposed response surface models.