A comprehensive review on Enhanced Oil Recovery by Water Alternating Gas (WAG) injection

This paper reports on a comprehensive study of the CO2-EOR (Enhanced oil recovery) process, a detailed literature review and a numerical modelling study. According to past studies, CO2 injection can recover additional oil from reservoirs by reservoir pressure increment, oil swelling, the reduction of oil viscosity and density and the vaporization of oil hydrocarbons. Therefore, CO2-EOR can be used to enhance the two major oil recovery mechanisms in the field: miscible and immiscible oil recovery, which can be further increased by increasing the amount of CO2 injected, applying innovative flood design and well placement, improving the mobility ratio, extending miscibility, and controlling reservoir depth and temperature. A 3-D numerical model was developed using the CO2-Prophet simulator to examine the effective factors in the CO2-EOR process. According to that, in pure CO2 injection, oil production generally exhibits increasing trends with increasing CO2 injection rate and volume (in HCPV (Hydrocarbon pore volume)) and reservoir temperature. In the WAG (Water alternating gas) process, oil production generally increases with increasing CO2 and water injection rates, the total amount of flood injected in HCPV and the distance between the injection wells, and reduces with WAG flood ratio and initial reservoir pressure. Compared to other factors, the water injection rate creates the minimum influence on oil production, and the CO2 injection rate, flood volume and distance between the flood wells have almost equally important influence on oil production.

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A Review of CO2-Enhanced Oil Recovery with a Simulated Sensitivity Analysis

In this paper, two commercial polymers, poly(vinyl ethyl ether) (PVEE) and poly(1-decene) (P-1-D), are tested to thicken CO2 for CO2 enhanced oil recovery (EOR). First, a series of laboratory tests are conducted to measure the cloud-point pressures of either polymer at different polymer solubilities in supercritical CO2 and the equilibrium interfacial tensions (IFTs) of a light crude oil-pure or polymer-thickened CO2 system under different reservoir conditions. Second, a capillary viscometer is used to measure the viscosities of polymer-thickened CO2 at different test pressures. Third, a total of six high-pressure CO2 coreflood tests are performed to examine the effects of polymer-thickened CO2 on the total CO2 EOR. It is found that at the same and low polymer solubility in pure CO2, the measured cloud-point pressure of PVEE is much lower than that of P-1-D. The measured equilibrium IFT for polymer-thickened CO2 at a high pressure is much lower than that for pure CO2. The PVEE- or P-1-D-thickened CO2 visc...

Evaluation of Polymers as Direct Thickeners for CO2 Enhanced Oil Recovery

In this paper, optimization of miscible CO2 water-alternating-gas (CO2-WAG) injection in the Bakken formation is experimentally studied. First, tight sandstone reservoir rock samples from the Bakken formation are characterized. Second, the vanishing interfacial tension technique is applied to determine the minimum miscibility pressure of the Bakken light crude oil and CO2 at the actual reservoir temperature. Third, a total of nine coreflood tests are conducted through respective waterflooding, continuous miscible CO2 flooding, and miscible CO2-WAG injection. In the miscible CO2-WAG injection, different WAG slug sizes of 0.125, 0.250, and 0.500 pore volume and different WAG slug ratios of 2:1, 1:1, and 1:2 are used to study their specific effects on the oil recovery factor (RF) in the Bakken formation. In addition, miscible CO2 gas-alternating-water (CO2-GAW) injection is also tested as an opposite fluid injection sequence of the miscible CO2-WAG injection. It is found that, in general, the CO2 enhanced oi...

Optimization of Miscible CO2 Water-Alternating-Gas Injection in the Bakken Formation

A comprehensive review on chemically enhanced water alternating gas/CO2 (CEWAG) injection for enhanced oil recovery

Previous studies to determine the extent of oil trapping by water during CO/sub 2/ water-alternating-gas (WAG) flooding have shown that rock wettability strongly affects this trapping. A significant trapping occurs in water-wet rock, and less trapping occurs in oil-wet rock. This paper presents laboratory results of Devonian crude oil displacement from watered-out Berea and reservoir cores by use of continuous CO/sub 2/ injection, single-slug CO/sub 2/ injection (followed by water), and CO/sub 2/ WAG injection at miscible reservoir conditions of 120/sup 0/F and 2,500 psig (49/sup 0/C and 17.2 MPa). The reservoir cores used in this study were mixed-wet (Devonian and Muddy formations) and oil-wet (Tensleep formation). The Berea cores used had their wettability artificially altered to simulate these natural wettabilities. The X-ray photoelectron spectroscopic (XPS) method for measuring carbon content of rock surface was used to provide a qualitative measurement of wettability of the rock samples. The results of the study indicated that the experimental wettability-altering technique came close to duplicating reservoir rock wettability. The oil recovery data at the end of 1 PV fluid injection (continuous CO/sub 2/ or WAG CO/sub 2/) indicated that (1) in preferentially water-wet Berea cores, more than 45% of the waterflood residual oilmore » trapped by CO/sub 2/ WAG; (2) in mixed-wettability Berea cores, 15 to 20% of the waterflood residual oil was trapped; and (3) in oil-wet Berea cores, less than 5% residual oil was trapped.« less

L.W. Holm

Papers

Effect of WAG Injection and Rock Wettability on Oil Recovery During CO2 Flooding