Enhanced Oil Recovery
Enhanced Oil Recovery (EOR) is a term used to cover various technique employed for increasing the amount of crude oil that can be extracted from an oil field. Traditional recovery rates for conventional fields vary from 20 to 40%, and for heavy oil fields average around 10%. So developing new methods to help enhance recovery and push rates higher are a main goal of research and development in the oil and gas industry.
EOR as it relates to carbon capture and storage is usually tied to the use of CO2 as a solvent. CO2 is miscible – that is to say it dissolves into oil – and as such it helps reduce viscosity in reservoirs and helps the oil to expand out of the porous rock in which it is often found. Since these oil reservoirs are also ideal trapping mechanisms for the storage of gases, moving from CO2-EOR to CO2 long-term storage is a logical step. The Cenovus-Weyburn and Apache-Midale CO2-EOR operations in southeast Saskatchewan - the largest in the world - are good examples of this type of storage.
CO2-EOR usually occurs in co-ordination with a water-flooding of the reservoir. The injection of water helps increase pressure in the reservoir, while the CO2 helps release more of the oil from the porous rock because it allows the oil to expand and flow. Much of that CO2 ends up trapped in the pores of the reservoir, and is thus stored underground permanently.
There are variable and various kinds of EOR methods and technologies. Not all of these technologies employ the use of CO2; some of these include:
Enhanced Waterflooding/Chemical Flooding: after initial attempts are made to water flood a reservoir, surfactants and chemicals can be added to alter the water’s interaction and miscibility with the oil.
Solvent Vapour Extraction: One environmentally advantage EOR process is to inject solvents into the reservoir rather than water, to dilute the oil and drive it to production wells. Solvents include propane, butane, methane and, of course, CO2.
Gas Flooding: CO2 or other gases can be injected into a reservoir to dissolve into the oil and make it flow more freely
Thermal Recovery Methods: These include any enhanced recovery that involves heating the reservoir, either through steam injection (Steam Assisted Gravity Drainage, or SAGD, is one example) or methods that involve the injection of oxygen to create a combustion front underground to create heat and improve oil flow (such as Toe-to-Heel Air Injection, or THAI technology).
Acid Gas Injection: H2S produced through sour gas desulphurisation cannot be released into the atmosphere. Currently, there are limited markets for sulphur, and the processing of H2S using the Clauss process is uneconomic. Consequently, more and more gas producers in the Alberta Basin in Western Canada are turning to acid gas (H2S & CO2) injection in geological media as a means to deal with the produced H2S from sour gas.
The first acid gas injection operation in Alberta started in 1989 and in 1995 there were 5 operations; in 1998 there were 21, and currently there are 29.
The composition of the injected acid gas varies between 7 to 95 % CO2 and 4 to 83% H2S, with minor amounts of methane. The licensed daily injection rate for CO2 in Alberta is ~900 t/d ( ~ 0.33 Mt/yr). Acid gas is injected in 11 depleted hydrocarbon reservoirs and 23 deep saline aquifers at 29 different locations. Of these, 9 are in sandstone and 25 in carbonate rocks.
For more information on CO2-EOR, or EOR generally, click on the two links below to the Petroleum Technology Research Centre.