Heavy Oil Recovery by Liquid CO2/Water Injection

Abstract

Abstract Alaska's North Slope reservoirs contain a massive heavy oil resource. There has been some success producing the less viscous crudes in the West Sak formation by waterflooding and water-alternating-gas injection. CO2 injection could also have potential applications as an enhanced oil recovery (EOR) process with the added benefit of providing a solution to the problem of produced CO2 present in the associated gas. CO2 is generally in supercritical state in normal reservoir conditions. However, permafrost causes an unusually low reservoir temperature and as a result CO2 will be in liquid state for these heavy oil fields. In this study we consider West Sak reservoir and investigate different injection strategies in which available water and CO2 can be utilized individually or combined for EOR and CO2 storage purposes. A three-phase, three-dimensional, black oil simulator was constructed accounting for the oil swelling and viscosity reduction due to dissolution of liquid CO2. The results indicate that a combination of water and CO2 injection could be an attractive recovery method from the West Sak with higher oil recovery obtained when CO2 and water injection carried out early in the production life of the reservoir. If depletion precedes CO2 injection, CO2 storage is at its maximum. The recovery under liquid CO2 injection was almost the same as that of water flood due to its reduced mobility compared to CO2 gas. Water-Alternating-CO2 injection and Simultaneous-Water-CO2 injection showed significant improvement compared to water or CO2 injection alone. At Water-Alternating-CO2 (volumetric) ratio less than one, lower CO2 is required and higher CO2 storage per standard barrel of produced oil is obtained if CO2 is injected at higher rate for shorter period. Whist at Water-Alternating-CO2 ratio greater than one, reducing duration of CO2 injection favoured oil recovery but lowered CO2 retention factor compared to lowering CO2 injection rate. Introduction Enhanced oil recovery by CO2 injection (CO2-EOR) is an established technique for recovering additional oil, mainly from onshore North American oilfields. 79 CO2-EOR operations were active in 2004 worldwide[1]. Nearly all of them, 70 miscible CO2-EOR projects and 1 immiscible were implemented in the USA. In addition, there are 2 active miscible displacement CO2-EOR projects in Canada, 5 immiscible displacement pilot fields in Trinidad and 1 commercial immiscible displacement operation in Turkey. CO2 can be injected either under miscible or immiscible conditions. Whilst increasing oil production, CO2-EOR can also facilitate the storage of carbon dioxide in the oil reservoir. CO2 storage is important considering that CO2 is recognized as the dominant anthropogenic gas that causes global warming, and that the energy production is responsible for more than 85% of its total emissions[1]. The use of CO2 for EOR (enhance oil recovery) and for geologic storage is generally focused on supercritical CO2 to achieve miscible conditions with crude oil and solubility of CO2 in brine aquifer water. Having a critical temperature of 31.1 °C (87.7 °F), CO2 behaves as a supercritical fluid under most reservoir conditions. Carbon dioxide has a relatively high density, approximately 50 percent greater than that of air at atmospheric conditions. Unlike density, where CO2 exhibits liquid-like characteristics, CO2 viscosity is similar to typical reservoir gas values and strongly depends on pressure and temperature. For usual reservoir pressure and temperature conditions and crude oil composition, supercritical CO2 often become miscible with oil, i.e. the crude oil and CO2 mix in all proportions forming a single-phase liquid. As a result of this interaction, the volume of oil swells, its viscosity is reduced, and surface tension effects diminish, improving the recovery of the oil from the reservoir.