The present invention relates to an oil recovery process for a subterranean heavy oil-containing reservoir. More particularly, the invention relates to an improvement in an in situ oil recovery process wherein steam is injected to heat the reservoir and thus render the heavy oil more mobile for recovery.
Heavy oil-containing reservoirs are those which contain crude petroleum or bitumen of such high viscosity that it cannot be recovered by conventional petroleum recovery techniques. Exemplary of such formations are the Athabasca and Cold Lake oil sand deposits of Alberta, Canada, the Lloydminster heavy oil deposits present in Alberta, Canada, and the oil sand deposits in Venezuela.
An insitu process for the recovery of such heavy oil usually includes reducing the viscosity of the heavy oil to thereby make it more amenable to flow. This is often done by injecting steam into the formation. In some cases, a communication zone, that is a permeable pathway, is first established between at least two wells penetrating the heavy oil-containing stratum. A communication zone may exist as naturally occurring permeable strata or may be established by conventional methods of hydraulic fracturing and propping. The steam is then injected through one well at high temperature and pressure. The steam passes through the communication zone, transferring sufficient heat to the adjacent heavy oil to lower the viscosity of same and render it more mobile. A steam/steam condensate/heavy oil mixture is produced at the second well.
Alternatively, in accordance with the well established huff and puff technique, steam injection and oil production may both take place at a single well. Steam is injected through the well into the formation. The steam is injected at high temperature and pressure to create a steam zone or steam chest around the well bore. When the injection pressure reaches a pre-determined level, injection is stopped and a back flow of heated formation fluids and injected fluids flows into the well and is produced. The injection and production cycles are repeated.
In situ recovery methods using steam injection, whether by continuous steam drive or cyclic steam techniques, have the disadvantage of leaving behind substantial amounts of oil. To enhance these steam-flooding processes, steam additives, such as solvents and gases, are often used. The solvent is included to solubilize some of the heavy oil and thereby lower the oil viscosity. Gaseous additives, such as carbon dioxide, are believed to enhance oil recovery by coming out of solution during pressure drawdown to assist in the pressure drive during the production cycle, or by otherwise improving the flowability of the oil.
In U.S. Pat. No. 4,156,462 issued May 29, 1979, to J. C. Allen, a two-step process is described for recovering oil. More particularly, a subterranean reservoir is first heated by injecting steam at temperatures in the range of about 260.degree. C. to 800.degree. C. Steam injection is then terminated and a mixture of carbon monoxide and hydrogen is injected into the heated portion of the reservoir. The carbon monoxide is said to react with the steam to produce carbon dioxide and additional hydrogen in the reservoir. These gases should lower the oil viscosity in the reservoir making the oil more amenable to recovery by a subsequent fluid drive system.
The conversion of carbon monoxide and steam to carbon dioxide and hydrogen is termed the water gas reaction: EQU CO+H.sub.2 O.revreaction.CO.sub.2 +H.sub.2.
It is generally believed that the water gas reaction takes place at high temperatures, in excess of 400.degree. C. Unfortunately, if such high temperatures are used in an oil reservoir, significant gasification and polymerization of the oil takes place. This of course reduces the amount of liquid oil which can be recovered. Furthermore, in a heavy oil reservoir, extensive polymerization forms tars which plug the fluid communication path.
The inclusion of hydrogen with the carbon monoxide in the process of the above-mentioned patent, is believed to be disadvantageous. Since the water gas reaction is a reversible reaction, the inclusion of hydrogen in the injection stream, especially at the suggested high temperature and pressure conditions, should drive the reverse rather than the forward reaction. This would favour the reactant side (CO+H.sub.2 O) rather than the product side (CO.sub.2 +H.sub.2) of the process.