Thermal Oil Recovery Technique

Abstract

A thermal method for recovering oil from a subterranean formation. Steam is injected by means of a well into the formation to heat the oil and to lower its viscosity. Following the steam injection, a noncondensing gas which is substantially free of oxidizing components is introduced into the steam injection system and is then injected into the formation at the same location at which the steam was injected. The temperature of the gas upon introduction into the steam injection system is no higher than substantially ambient temperature. After the gas has been injected into the formation, the heated oil is withdrawn from the formation by means of the well.

Parent Case Text

REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part of copending application Ser. No. 59,611, filed July 30, 1970, and now abandoned.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the recovery of petroleum from a subterranean formation utilizing a well for the injection of heated fluids and the withdrawal of petroleum. More specifically, this invention relates to a steam stimulation technique where the steam is displaced into the formation by a noncondensing and nonoxidizing gas. Subsequent to the injection of the steam and the gas, the well is placed on production and the heated fluids including oil are withdrawn from the formation.

2. Description of the Prior Art

Among the more promising methods that have been suggested or tried for the recovery of oil from viscous oil reservoirs are those which introduce thermal energy into the reservoirs. The thermal energy may be in a variety of forms such as hot water, in-situ combustion, steam, and the like. Each of these thermal energy agents may be useful under certain conditions. However, steam is generally the most efficient and economical and is clearly the most widely employed thermal energy agent.

There are two basic processes which use steam as a thermal energy agent for oil recovery. One of these is the steam-drive process in which steam is injected into the formation at one well and petroleum is driven through the reservoir by the steam to an offset producing well. The other is a steam stimulation technique, commonly referred to as the " huff-and-puff" process, in which steam is injected by means of a well into the formation and, subsequently, the heated oil is withdrawn from the formation by means of the same well. The "huff-and-puff" process is conducted in cycles; alternately, steam is injected into the well and oil is withdrawn through the same well. These cycles are repeated until oil can no longer be economically recovered.

The "huff-and-puff" process has particular applicability in reservoirs where it is difficult to establish fluid communication between two wells. This inability to establish communication may be a result of formation discontinuities such as impermeable streaks, faulting, and the like which would render steam drives inoperable. The "huff-and-puff" technique is also generally superior in formations having high viscosity crude which is not easily displaced by a steam drive and in virgin oil reservoirs having a high oil saturation and a relatively low water saturation.

One difficulty that has been observed with the "huff-and-puff" process is the decline in oil production and increase in water-oil ratio as the cycles of the process are repeated. Initially, the oil saturation in the formation is relatively high and the water saturation is relatively low. However, as the well is repeatedly produced by the "huff-and-puff" cycles, the area in the immediate vicinity of the wellbore will contain less and less oil. Moreover, since all of the water which is introduced into the formation as steam during the injection phase of the cycle is generally not recovered during the production phase, the water saturation around the well begins to rise as the cycles are repeated.

As a net result, less oil and more water is produced from the well during the depletion of the formation.

SUMMARY OF THE INVENTION

In the injection phase of a "huff-and-puff" steam stimulation process, steam is injected into the oil-bearing reservoir and followed by a noncondensing and nonoxidizing gas which has a temperature which is no higher than substantially ambient temperature upon introduction into the steam injection system. During the production phase, oil, gas, and other fluids are withdrawn from the formation. The noncondensing and nonoxidizing gas improves the oil production rates and reduces the water-oil ratio of the well.

This invention is suitable for use in any oil-bearing reservoir which is capable of being produced by conventional steam recovery techniques. However, this invention has particular applicability in "tar sand" oil reservoirs. These tar sands generally have a relatively low temperature, 50.degree. - 125.degree.F, and the oil contained within these sands has an extremely high viscosity, 100,000 centipoises or higher, at such temperatures. When the temperature of the oil is raised by several hundred degrees, however, the viscosity of the oil may be reduced to 10 centipoises or less. Quite naturally, such a reduction in viscosity will increase the ability of the oil to flow within and to be produced from such "tar sand" reservoirs.

The objects of this invention can be perhaps most easily seen with reference to the following drawings.

BRIEF DESCRIPTION OF THE DRAWING

The FIGURE is a schematic drawing of a section of the earth showing a well penetrating an oil-bearing formation.

DESCRIPTION OF THE PREFERRED EMBODIMENT

Referring to the drawing, an oil-bearing formation 10 is penetrated by a well shown generally at 11 which has been drilled from the surface of the earth 12. The well has been completed in a conventional manner with a string of casing 13 set within the borehole 14 and supported by a cement sheath 15.

The well contains a string of tubing 16, and a packer assembly 17 seals the upper portion of the tubing-casing annular space. Perforations 18 establish fluid communication between the formation and the well 11. It will be understood by those skilled in the art that the foregoing represents a conventional well completion which could be used in the practice of this invention. Other well-known well completion systems would be equally suitable for use in this invention.

In the practice of this invention, the "huff-and-puff" stimulation cycle is employed. In such a stimulation sequence, thermal energy is introduced into the formation by injecting steam down the tubing string 16 and into the formation 10 through perforations 18. After the steam has been injected into the formation, the well is generally shut in to permit the formation to "heat soak." During this heat-soaking period, thermal energy is transferred from the steam to the formation and formation fluids. The length of the heat-soak period will vary in duration depending primarily on the thermodynamics of the fluid and rock system. The period will normally be a rather short time of several days to weeks but may be as long as several months. After the heat-soak period has been completed, the pressure on the well is reduced, and the heated reservoir fluids flow through the formation 10 and up the tubing string 16 to suitable separation and storage facilities (not shown).

It has now been found that the oil recovery efficiency of such a "huff-and-puff" steam stimulation process can be radically improved by injecting a nonoxidizing and noncondensing gas into the formation subsequent to the steam injection and prior to production of the formation fluids. In this process, a volume of steam is first injected into the formation as previously described. The steam is then followed by a nonoxidizing and noncondensing gas such as methane or natural gas, which is injected into the formation through the perforations 18. The well is then shut in for a suitable heat-soak period. Subsequently, the well is placed on production, and the formation fluids including heated oil are withdrawn by means of the well.

Experience has shown that the conventional "huff-and-puff" process has declining efficiency during the production history. That is, as the cycles are repeated the oil production rate declines, the quantity of oil recovered per barrel of steam injected declines, and the quantity of water produced per barrel of oil recovered increases. This declining efficiency is clearly shown in the following Table I. This Table shows the results of three cycles of a "huff-and-puff" steam stimulation process in a well completed in a manner similar to that previously described. ##SPC1##

As can be seen from Table I as the "huff-and-puff" cycles are repeated, the oil production rate drops from an initial average of 84 to 59 barrels per day. The quantity of oil produced per barrel of steam injected decreases from 0.62 to 0.10 barrels of oil per barrel of steam (steam quantities herein are expressed as the volume occupied at 60.degree.F by a corresponding weight of water). Concurrently, the water-oil ratio rises from an initial rate of 1.0 to 4.65 barrels of water per barrel of oil.

Table II, Cycle 4, shows the results of the practice of this invention. Following the cycles shown in Table I, a bank of steam was injected into the well. The steam was immediately followed and displaced by a volume of natural gas. The well was shut in for a suitable heat-soak period and then placed on production. The results of this fourth cycle are shown in Table II, and for comparative purposes the results of the preceding Cycle 3 are repeated in this Table. ##SPC2##

As can be seen from Table II, the recovery efficiency is radically improved by the injection of the nonoxidizing and noncondensing natural gas during the fourth "huff-and-puff" stimulation cycle. The oil production rate increases from 59.0 to 73.0 barrels per day. The quantity of oil produced per barrel of steam injected increases more than ten-fold from 0.10 to 1.15. The water-oil ratio is reduced by almost one-half from 4.65 to 2.75.

A truly surprising aspect of this invention is the ability of this noncondensing gas to increase the oil recovery efficiency of the process. It is well known to those skilled in the art that the presence of a gas phase in a porous media will reduce the permeability of the porous media to liquids. In other words, it is generally conceded that the greater the quantity of undissolved gas in an oil-containing formation, the lower the oil producing rate from that formation will be. However, this invention shows precisely the opposite effect. The injection of the noncondensing natural gas actually increases the oil production. The oil producing rate increases by almost 25 percent; the total quantity of oil produced is more than doubled.

The gas employed in the practice of this invention should be non-oxidizing and noncondensing. Suitable gases which will meet these requirements are flue gas, nitrogen, carbon dioxide, methane, and natural gas containing predominant portions of methane. The gas should not be air or other gases containing substantial quantities of oxygen. Such combustion-sustaining gases are likely to initiate combustion within the formation, and the products of combustion tend to form emulsion-stabilizing substances. As a consequence, these combustion-sustaining gases tend to create emulsions of oil and water which are extremely difficult to treat and handle at the surface storage facilities. Moreover, the gas should be noncondensing. That is, it should remain in a substantially nonliquid or gaseous state during the process. Where a multi-component gas is employed such as natural gas, certain components of the gas, such as high molecular weight hydrocarbons, may have a tendency to condense as the formation cools following steam injection. Condensation of minor amounts of the gas will not interfere with the practice of this invention so long as the major proportion remains gaseous.

The gas should have a low concentration, if any, of intermediate molecular weight hydrocarbons--propane and heavier. Such intermediate weight hydrocarbons in significant quantities (more than 50 percent by weight in the injected gas stream) are disadvantageous in the practice of this invention. These higher molecular weight hydrocarbons have the tendency to precipitate asphaltic components from the crude with a resultant reduction in the permeability of the formation. Moreover, the higher molecular weight hydrocarbons such as natural gasolines have a high solubility or even miscibility with most crude oils. High concentrations of these materials in the injected gas would have the tendency to miscibly displace crude oil from the immediate vicinity of the wellbore. This would reduce the oil saturation at a location in the formation where high oil saturations are desired, and there would be a consequent reduction in permeability to oil at the well-bore. It should be understood that minor quantities of intermediate molecular weight hydrocarbons (propane, butane and higher) can be tolerated in the gas stream and are, in fact, naturally-occurring constituents of most natural gases. These substances can be tolerated so long as they do not form a predominant portion of the gas employed in the practice of this invention.

The mechanism by which the noncondensing and nonoxidizing gas improves the steam stimulation technique is not completely understood. It is clear, however, that it is not the function of the gas to heat the formation. The gas is at substantially ambient temperature or less when it enters the steam injection system. The term ambient temperature is used herein in its ordinary sense and refers to the average temperature of the ground or air surrounding the gas flow line prior to its interconnection with the steam injection system. The steam injection system in this context refers to any portion of the flow line and well system which is heated to a significant degree by the steam during the steam injection phase. The steam injection system would include, for example, the well itself, any surface flow line which might lead from an injection header to the well and the injection header if both the gas and the steampass through such a header.

It is recognized that some minor and incidental heating of the gas might occur where the gas flow line is exposed to sunlight or through compression of the gas. However, such heating would be insignificant and the gas would enter the steam injection system at substantially (no more than 40.degree.F higher than) ambient temperature or less. Even where flue gas is employed, it is at substantially ambient temperature or less when it enters the steam injection system. Flue gas is the combustion product from compressors and steam generators which must be treated to remove water and corrosive components prior to injection. This treating of the flue gas, of course, reduces its temperature. More importantly, however, the temperature of the flue gas must be radically reduced prior to compression. The horsepower required to compress a gas is related to its absolute temperature. Thus, it is generally desirable, if not essential, to cool the flue gas prior to compression, and in the practice of this invention the flue gas enters the steam injection system at substantially ambient temperature.

The steam employed in the practice of this invention may be saturated or superheated. Gnerally speaking, however, in most field applications the steam will be saturated with a quality of approximately 65 to 90 percent and a temperature of 300.degree.-650.degree.F. The quantity of steam injected per cycle will vary depending on the conditions existing at a given application. Among the factors which will control the volume of steam injected will be the thickness of the oil-bearing formation, the viscosity of the oil, and porosity of the formation, the saturation of oil and water in the formation, and the state of depletion of oil from the formation. Generally speaking, however, the steam volume will vary between 5,000 and 250,000 barrels per cycle. The quantity of gas employed per cycle in the practice of this invention is also variable and will depend upon the cost of the gas as well as the formation and fluid properties previously described. In most applications, the gas quantity will vary between 25 to 500 scf of gas per barrel of steam. Generally, a gas-steam ratio of approximately 100 scf per barrel will be satisfactory.

In the preferred embodiment of this invention, single slugs of steam and the noncondensing and nonoxidizing gas are introduced into the formation during the injection phase of the "huff-and-puff" cycle. It should be understood, however, that it is contemplated that the steam and gas may be introduced in multiple, alternate small volume slugs. In such an embodiment, the total volume of steam and gas employed per cycle will lie within the limits previously stated and, as in the preferred embodiment, the first fluid injected will be steam.

The principle of the invention and the best mode in which it is contemplated to apply that principle have been described. It is to be understood that the foregoing is illustrative only and that other means and techniques can be employed without departing from the true scope of the invention defined in the following claims.

Claims

What is claimed is:

1. A method for recovering oil from a subterranean oil-bearing formation which comprises injecting steam through a steam injection system, including a well, and into the formation to heat the oil within the formation and lower its viscosity, then introducing into the steam injection system a noncondensing gas which is substantially free of oxidizing components and which has a temperature which is no higher than substantially ambient temperature upon said introduction, then injecting the noncondensing and nonoxidizing gas into the formation at the location of steam injection, and subsequently withdrawing oil from the formation by means of the well.

2. A method as defined by claim 1 wherein the noncondensing and nonoxidizing gas is natural gas containing a predominant amount of methane.

3. A method as defined by claim 1 wherein the noncondensing and nonoxidizing gas consists essentially of methane.

4. A method as defined by claim 1 wherein the noncondensing and nonoxidizing gas is flue gas.

5. A method as defined by claim 1 wherein the noncondensing and nonoxidizing gas is carbon dioxide.

6. A method as defined by claim 1 wherein the noncondensing and nonoxidizing gas consists essentially of nitrogen.

7. A method as defined by claim 1 wherein the volume of steam injected is from 5,000 to 250,000 barrels.

8. A method as defined by claim 7 wherein the volume of noncondensing and nonoxidizing gas injected into the formation is from 25 to 500 scf of gas per barrel of steam.

9. A method as defined by claim 1 wherein the steps of steam injection and subsequent gas injection are conducted a plurality of times prior to the withdrawal of oil from the formation.

10. A method as defined by claim 1 wherein the cycle of injecting the steam, then injecting the gas and subsequently withdrawing oil from the formation is conducted a plurality of times.