1. Field of the Invention
This invention relates to the recovery of oil from petroleum reservoirs, and relates particularly to the use of hydrogen peroxide and its aqueous solutions to recover viscous oil from geological reservoirs.
2. Brief Description of the Existing Art
In excess of 4 trillion barrels of viscous oil are estimated to exist in Canada, Venezuela, Calif. and various other worldwide locations. Viscous oil may be defined as oil having a viscosity greater than about 100 centipoises at reservoir conditions. The known reserves of viscous oil are estimated to be at least three times the known worldwide reserves of easily recovered low viscosity oil. With present technology, most of the world's viscous oil reserves cannot be produced economically. The incentive to recover these vast reserves, however, is enormous and many methods have been tried to do so. The existing art for recovery of viscous oil includes the following methods.
Most of the present recovery methods rely on thermal techniques to reduce the viscosity of the oil and increase its ability to flow. One method uses mining techniques to dig up the oil-containing sand and liberate the viscous oil from the sand by washing with hot water. Another method uses hot solvent to dissolve the tarry hydrocarbon from the mined solids.
The most commonly used non-mining thermal methods are hot water injection, steam injection, and in situ combustion.
(a) Hot Water Injection
The simplest thermal method to reduce oil viscosity in situ is by injection of hot water. The water is heated at the surface, and then pumped down a metal pipe and into a subterranean oil-bearing formation. The hot water warms the oil and thereby reduces its viscosity, and the less viscous oil is able to move more easily toward a production well. This method, however, is limited to shallow reservoirs, and heat loss to the nonproductive overburden limits the maximum temperature at which one can inject hot water.
(b) Steam Injection
Steam injection is generally preferred over hot water injection because, pound for pound, steam will typically have 3 to 4 times more heat available for reducing oil viscosity than will hot water. Typically, steam is generated at the surface and injected in much the same manner as hot water. Steam also loses heat to the nonproductive overburden (typically 10 to 30% of its heat content) but because of steam's higher initial heat content it can be used at greater depths to generate higher downhole temperatures than can hot water.
The problems associated with steam injection are many and are well known to those skilled in the art. For instance, water treatment costs are high, and insulated injection tubing is required for deep reservoirs. Expensive and non-conventional completion methods must be used in steam injection, such as special cementing techniques, special expansion joints, special casing and couplings, etc. In addition, steam tends to "finger" through the reservoir to the production well, leaving large quantities of oil in place in the reservoir.
A common method for well stimulation and more rapid production of viscous oil involves injection of steam into a well for a short period of time (2 to 4 weeks) followed by a soak period of a few days. The soak period is followed by production from that same well for a period of 8 to 12 weeks. This method of well stimulation is commonly called Huff and Puff. In this method, the reservoir sand around the well bore is heated by injecting steam and allowing time for the steam to condense. This allows the oil bearing zone to extract the considerable latent heat of vaporization of the steam. The flow is then reversed by converting the former injection well to a production well. The hot oil near the injection well flows relatively easily into the well bore. Cooler oil from farther out in the reservoir moves radially into the heated zone where the oil extracts heat from the hot reservoir sand. Production is continued until the formation sand is too cool to lower the oil viscosity appreciably. The process can sometimes be repeated as many as five times before the operation becomes uneconomic.
(c) In Situ Combustion
In order to reduce excessive heat losses to the nonproductive overburden during hot water or steam floods, techniques have been devised to generate the desired heat in the oil bearing zone itself. In situ combustion is one such method. Typically, air is compressed to some pressure higher than reservoir pressure and injected into the formation. Spontaneous ignition of the hydrocarbon with air can sometimes take place, but ways to initiate the combustion have also been suggested. For instance, L.S. Melik-Aslanov et al (Russian Patent Certificate No. 570700, Aug. 30, 1977) suggests use of chromic acid solution to catalyze the rapid decomposition of hydrogen peroxide at the bottom zone of a well bore. The rapid decomposition is theorized to cause a high temperature near the well bore which enhances recovery by initiating combustion of the resident oil during subsequent injection and ignition of air-water foam. Another method for causing a high temperature at the bottom of a well bore is suggested by J. C. McKimmell (U.S. Pat. No. 3,561,533). He proposed to mix foams of two highly reactive compounds in the well bore--hydrogen peroxide and hydrazine, a common rocket propellant mixture--to effect chemical heating in a well.
Oxygen in air can react with hydrocarbons to produce heat, water, and carbon dioxide. Only about 20% of air, however, is oxygen. The remaining 80% is substantially all nitrogen, and nitrogen is inert, has low solubility in oil or reservoir fluids, and causes fingers of gas to move rapidly toward the production well. The nitrogen fingers provide an easy path for the steam and combustion front to follow, leaving a large amount of the resident oil in place. Premature arrival of the combustion front at a production well frequently signals the termination of the fire-flood. To help alleviate this condition, water is sometimes injected with the air. Water tends to occupy part of the nitrogen fingers and slows down the passage of air toward the fingers. Water also tends to prevent overriding of the air because water-air mixtures are much more dense than air alone.
Other techniques to minimize the adverse effects of inert gas fingering have been used, such as injection of pure oxygen, or mixtures of oxygen with water, flue gas, or carbon dioxide. See, for example, W. R. Shu, U.S. Pat. Nos. 4,454,916 and 4,474,237, and G. Savard, U.S. Pat. No. 4,557,329. Manufacture and compression of pure oxygen in the oil field, however, is expensive and hazardous.
More complete descriptions of the existing art may be found in Development of Heavy Oil Reservoirs, Briggs et al, J. of Petroleum Technology, Feb. 1988, p. 206; and in the books Enhanced Oil Recovery of Residual and Heavy Oils, M. M. Schumacher, Second Ed., Noyes Data Corp., Park Ridge, N.J., ISBN 0-8155-0816-6, and Fundamentals of Enhanced Oil Recovery, H.K. van Poollen and Associates, PennWell Publishing, Tulsa 1980.