Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

Abstract

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two 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 (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

Enhancement of CO2 trapping efficiency in heterogeneous reservoirs by water‐alternating gas injection

“…49 A WAG injection could indeed affect the CO 2 storage efficiency because of its well known role in improving both the microscopic and macroscopic sweep efficiencies in oil reservoirs. 50,51 Even though WAG technology has been widely used in various industrial applications, such as enhanced oil recovery (EOR), [52][53][54][55][56][57][58][59] its effect on CO 2 trapping efficiency has not been addressed. We therefore compare three different CO 2 injection scenarios, namely continuous CO 2 injection, intermittent CO 2 injection, and WAG injection, using numerical multiphase flow simulations in a highly heterogeneous, hectometer-sized storage formation.…”

“…Specifically, we compare the efficiency of a water‐alternating gas (WAG) injection with the continuous CO 2 injection traditionally used in most of the current CCS projects in the world such as the Sleipner project in Norway and the Quest project in Canada . A WAG injection could indeed affect the CO 2 storage efficiency because of its well known role in improving both the microscopic and macroscopic sweep efficiencies in oil reservoirs . Even though WAG technology has been widely used in various industrial applications, such as enhanced oil recovery (EOR), its effect on CO 2 trapping efficiency has not been addressed.…”

Analysis of the enhanced oil recovery process through a bilateral well using WAG-CO2 based on reservoir simulation. Part II – real reservoir model

“…Currently, WAG with the use of vertical, standard horizontal as well as bilateral wells is used all around the world [2,5,10,11,22], and the use of CO 2 in the WAG process allows for the improvement of the reservoir recovery coefficients [3,9,13,23,24].…”

Phase Behaviour and Viscosity Reduction of CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures

“…Although numerous laboratorial and field CO 2 immiscible displacement processes have been implemented to enhance heavy oil recovery (Sankur and Emanuel, 1983;Saner and Patton, 1986;Olenich et al, 1992;Zheng and Yang, 2012;Zheng et al, 2013), limited efforts have been made to examine the effect of CO 2 on saturation pressure, swelling factor and viscosity reduction of heavy oil at high pressures and elevated temperatures. In comparison to the hydrocarbon solvents (e.g., C 3 H 8 and n-C 4 H 10 ), CO 2 has a lower critical temperature of 304.14 K and a higher critical pressure of 7377.5 kPa, leading to a challenge to perform the PVT tests for supercritical CO 2 and heavy oil systems at high pressures and elevated temperatures.…”