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.