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Publication numberUS3333637 A
Publication typeGrant
Publication dateAug 1, 1967
Filing dateDec 28, 1964
Priority dateDec 28, 1964
Publication numberUS 3333637 A, US 3333637A, US-A-3333637, US3333637 A, US3333637A
InventorsMichael Prats
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Petroleum recovery by gas-cock thermal backflow
US 3333637 A
Abstract  available in
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

A "a II. 2




MCHAEL PRATS I Q sm HIS ATTQRNEY United States Patent 3,333,637 PETROLEUNI RECOVERY BY GAS-COCK THERMAL BACKFLOW Michael Prats, Houston, Tex., assignor to Shell Oil Company, New York, N.Y., a corporation of Delaware Filed Dec. 28, 1964, Ser. No. 421,294 6 Claims. (Cl. 166-40) ABSTRACT OF THE DISCLOSURE An improved backflow method of recovering petroleum from subterranean reservoirs by injecting a slug of noncondensable gas into the reservoir rior to the injection of a heated fluid and thereafter thermal soaking the formation so as to facilitate petroleum recovery.

This invention relates broadly to the recovery of petroleum from subterranean reservoirs by backflow, and more particularly to a method combining a thermal soak with a gaseous drive mechanism.

In many petroleum-bearing reservoirs, only a small portion of the petroleum is recovered by primary recovery techniques which depend on natural gas or water pressure and/or gravity in the reservoir system to flow the petroleum into the borehole. When the pressure drops because of removal of some of the petroleum or the petroleum is too viscous to be removed by these natural pressures in the reservoir system, primary recovery (natural flow) is not possible. Since there are substantial quantities of petroleum remaining in the reservoir in both such situations, supplemental recovery techniques are often employed to recover additional petroleum from the reservoir.

These supplemental techniques are sometimes referred to as secondary recovery methods and a useful dichotomy of these secondary methods are those involving drives, such as waterfloods, and those involving backflow where the injection and recovery are accomplished from the same individual borehole. In the case of drives spaced wells are used and the petroleum is driven by injecting fluid into the reservoir through one well to create a pressure differential that causes fluid in the reservoir to move into a recovery well at a spaced location. In backflow techniques, after fluid has been injected into the reservoir, the injected fluid and the petroleum is backflowed into the same well which was used for the injection of the fluid.

Each of the backflow and drive techniques has certain advantages over the other. The drive techniques have been generally preferred since they are usually more efficient in that the fluid is continually moved in the direction of the gradient that is first established within the reservoir; whereas, in the backflow techniques, the injected fluid must first bypass the oil and then displace the oil back into the -well through which the fluid was injected. The principal disadvantage of drives are the expense of drilling of additional wells, and locating such wells so that they encounter the same reservoir and the space between the wells is free of discontinuities caused by impermeable streaks, faulting and the like which would render the drives inoperable. While the backflow techniques avoid the above-mentioned disadvantages of the drives, in many instances the conventional backflow techniques have not been effective enough to off-set the additional oil recovery obtained by drives. In general, the conventional backflow techniques are more eflicient when they employ heated fluids in reservoirs containing an oil having a viscosity such that the hot fluid tends to bypass much of the petroleum around the well, but in doing so heats it to a temperature at which it may be more easily displaced into the well during the backflowing of the well. This beneficial effect tends to be lost where the oil viscosity is initially low enough to allow a large proportion of the oil to be displaced away from the well as the hot fluid is injected'or where the hot fluid tends to flash-ofl? light hydrocarbons and leave a viscous petroleum residue in the formation. In the latter situation the viscous residue may tend to plug some of the pores of the reservoir adjacent to the borehole and make the backflow more diflicult.

It is a primary objective of the present invention to minimize or overcome many of the above problems associated with backflow techniques by injecting a slug of a non-condensable gas into the reservoir prior to the injection of a heated fluid. The displacement eflfectiveness of backflow techniques is measurably improved when this invention is used.

In its broadest aspect the present invention involves a backflow recovery method involving the steps of injecting a slug of non-condensable gas through a borehole into a petroleum-bearing reservoir, subsequently injecting a heated condensable fluid, then producing fluid from the reservoir by reducing the pressure in the borehole to less than the pressure in the reservoir and recovering the petroleum that flows into the borehole.

As used herein, the term non-condensable gas refers to a gaseous fluid comprising one or a mixture of gases or vapors that are gaseous under the conditions of temperature and pressure that exist within the reservoir. The term heated condensable fluid or simply heated fluid is used to refer to a hot (and preferably, substantially completely vaporized) liquid. Steam in the form of saturated or low quality steam (containing up to about 20 percent by weight liquid) comprises the preferred heated fluid, although superheated steam, vaporized hydrocarbons, heated water, heated liquid condensate, etc., can also be used.

In a preferred embodiment of this invention the composition of the non-condensable slug of gas is preferably selected to enhance two beneficial effects (1) the maintenance of a gas phase within the reservoir and (2) an advantageous chemical reaction with the oil and/ or dilution of the oil contained in the reservoir. The gaseous slug preferably comprises a mixture of gaseous materials that include at least one inert and substantially insoluble gas, preferably nitrogen, having a critical temperature Well below the reservoir temperature. This ensures that the gaseous slug will not condense in the reservoir at any pressure. Although the gaseous slug can comprise an essentially pure inert and insoluble gas it preferably comprises such a gas mixed with one or more other gases such as oxygen, carbon dioxide, ammonia, and/ or a lower hydrocarbon such as methane or ethane. Of this group, methane and ethane are especially desirable components of the gaseous slug since they are, to various extents, miscible with the various oils contained in such reservoirs. The dissolving of some light hydrocarbon in the reservoir oil helps to reduce the viscosity of the oil, thereby enhancing ultimate recovery of the oil.

The action of the gaseous slug in the reservoir is multifold and complex; one advantage, particularly in reservoirs having a low permeability, is that it provides a pressure mechanism that aids in the backflow of the petroleum after the soak period. It is able to accomplish this function as a result of its high mobility relative to that of the oil in the reservoir at the natural temperature of the reservoir. This high mobility allows much of the gaseous slug to finger through the oil in the reservoir and move radially outwardly into the reservoir and bypass much of the oil. When the hot fluids are subsequently injected they tend to follow the paths taken by the slug but have a greater displacement efliciency since they warm the oil and lower its viscosity. However, because the heated fluids can follow the paths taken by the more mobile (relatively speaking) gas slug, the heated fluids will tend to be distributed farther out into the reservoir than if the gaseous slug had not been injected prior thereto. This is enhanced by the tendency of the gaseous slug to leave gas channels through which vapors of a heated fluid can move at a rate exceeding the rate of movement of the liquid condensate or other liquid components of the heated fluid. Thus, due to the prior injection of a gas, the heated fluids will not build up such a large bank of I warmed petroleum as they move radially outwardly from the borehole as they would if no gas had been injected. Of course at some point the bank of warmed petroleum becomes pronounced and tends to isolate the gaseous slug, plus any of the heated fluids that have fingered through the bank, from the borehole, by trapping them on the side of the bank remote from the borehole.

After the injection of the heated fluids the well is preferably shut in for a soak period of various durations. It can be varied from a short time, such as a few days or weeks, to longer times, such as months or even longer. This soak allows the injected heated fluids to transfer an optimum amount of their thermal energy to the reservoir system. After the soak period has been completed, the residual pressures in the borehole are released and by this time the viscosity of the petroleum has been substantially reduced by the thermal energy added thereto. As the pressure within the borehole is reduced, the'pressure in the gaseous slug remote to the borehole becomes greater than the pressure in the borehole and the gaseous slug will tend to drive the warm petroleum bank toward the borehole. This eflect is enhanced by the improved mobility ratio, being much improved because of the higher reservoir temperature and the tendency of the gas to vaporize portions of the heated liquid (or heated liquid condensate) because of a reduction of vapor pressures. This occurs as the gas moves through the reservoir toward the reduced pressures in the borehole as the fluids are being backflowed into the borehole. This vaporizing of the heated liquid enhances the oil recovery since it increases the volume of the fluids which are flowing, and

thus displacing oil, toward the well.

Particularly in a retreatment of the reservoir according to this method, it is sometimes advantageous to use air or an oxygen rich gaseous slug as the slug that is first injected into the heated reservoir. The exothermic reaction between the oxygen and the oil generates heat in situ and tends to reduce the amount of heat that must be applied to the subsequently injected heated fluid.

When, in a reservoir containing a heavy crude such as a tar, methane and ethane or a mixture thereof, are used as a component of the gaseous slug; this slug is partially miscible with the petroleum. The resulting dilution of the oil reduces its viscosity and further improves the mobility ratio, thus improving the petroleum displacement efiiciency by the slug moving (back-flowing) toward the borehole.

In some cases, when the gaseous slug breaks into the borehole, it will be desirable to stop recovery and reinject the reservoir with the heated fluids, followed by a subsequent soak and then a further recovery step. Also it may be desirable, in some cases, to inject an addition slug of non-condensable gas at this time.

More specifically the invention will be better understood by reference to FIGURES 1A and 1B which are vertical sections through the same earthen formation showing a borehole traversing multiple strata and a reservoir and illustrates intermediate conditions in the reservoir at two different times during the practice of the invention.

Referring to the drawings, a borehole 11 penetrates from the surface through various strata including impermeable stratum 12 and a petroleum producing reservoir 13. Reservoir 13 is illustrated as a generally horizontally extensive permeable reservoir sandwiched between vertically spaced layers of impermeable strata 12 4 and 14. The reservoir, though shown as a horizontal one, could have a reasonable degree of dip without effecting the practice of this invention.

A well casing 15 is shown secured in the borehole 11 with a sealant 16, such as cement, and in the area of the vertical traverse of the reservoir 13 the casing string 15 and the seal-ant 16 are perforated with ports 17 to provide fluid communication from the inside of the casing string 15 and the reservoir 13.

At the top of easing string 15 a gland 18 secures the outer pipe string 19, of two concentric pipe strings, 19

and 20respectively, which extend downwardly inside the casing string. The inner pipe string 20 preferably extends to the bottom of the casing string 15, extending below the end of the outer string 19. The annulus between the casing string 15 and the inner pipe string 20 is sealed with packer 23 in the lower portion of the reservoir 13 so that there is a lower compartment 21 through which only the inner pipe string 20 has fluid communication with the reservoir 13. The annulus between the outer pipe string 19 and the casing string 15 is sealed with packer 22 near the top of reservoir 13 and provides an upper compartment 21a through which the outer pipe string 19 has fluid communication with the reservoir 13.

The reason for this arrangement is so that the lower compartment 21 communicating with the lower reservoir can serve as a sump during backflow of petroleum to the borehole and either or both of the compartments can be used for injection. Such an arrangement is desirable in a reservoir in which there will be a significant gravity segregation of the fluids in the reservoir and/ or Where there is a difference in the permeabilities of the upper and lower portions of the reservoir, etc. This sump utilization is illustrated in FIGURE 1B showing the petroleum bank B having a sloping tail portion trailing out from the major portion of the sloping bank which banked against the borehole 11, and prevents portions of the gaseous slug moving back toward the borehole near the top of the reservoir from venting prematurely into the casing string 15 by closing ofl? pipe string 19 and recovering only through pipe string 20.

. In general, the arrangement of the well conduits for injecting fluids into and producing fluids from the reservoir formation should be designed for the optimum recovery from the particular formation being treated.

For a better understanding of the invention reservoir 13, shown in FIGURES 1A and 1B, is divided into three zones, A, B and C to show intermediate conditions in the reservoir during the practice of this invention.

FIGURE 1A shows conditions after the gaseous slug has been injected and while hot fluids are being injected.

In general, the volume of the gaseous slug should be equal to the volume of heated fluid that is to be injected. The use of increasingly large excesses becomes increasingly inefficient in respect to the value of the increased production relative to the increased costs of the injection. The amount of heated fluid to be injected will vary according to the particular reservoir being treated and will vary relative to porosity, permeability and the like. Usually about a volume of fluid which is equal to 30% or more of the pore space in the zone treated is acceptable. As shown in FIGURE 1A, because its high relative mobility in the reservoir, the gaseous slug has moved radially out into the reservoir, accumulating largely in zone C remote from the borehole. The heated fluid, preferably steam, is being injected in FIGURE 1A, as indicated by the arrows, and has displaced some of the petroleum from zone A in the form of a bank B of warmed petroleum. This bank tends to trap the gaseous slug remote of the borehole 11 and allows the slug to pressurize the remote side of the bank B to encourage the backflow of fluids which is shown occurring in FIGURE 1B.

During backflow the gaseous slug pushes the petroleum bank B back through zone A toward the casing string 15 and into ports 17, as shown in FIGURE 13, from which recovery can be accomplished. Since the petroleum has been warmed the mobility ratio between the petroleum and the gaseous slug is more favorable for the displacement during backfiow than when the slug was injected. Therefore, the slug will be more efiicient in displacing the petroleum bank B toward the borehole 11, especially when the pressures are lowered in the casing string 15, below those during the initial injection. Further, the petroleum in bank B is heated more as it moves into the areas adjacent to the borehole where temperatures are higher which improves the mobility ratio still further.

Also, it may be desirable to reduce the pressure in borehole 11 after the residual pressures have been released by placing a partial vacuum thereon.

The method of the invention is especially eflective when the petroleum does not originally contain high proportions of dissolved gas. Further, it should be appreciated that some steam will finger through the petroleum bank and aid the gaseous slug as a drive mechanism during backflow. As the pressure drops in the casing 15, the gaseous slug sweeps toward the casing string 15 and the partial pressure of steam will be reduced and some of the water condensate will be flashed into steam to aid the drive mechanism in forcing the petroleum bank toward the borehole 11.

I claim as my invention:

1. A method of recovering petroleum from subterranean reservoirs which comprises the steps of:

(a) penetrating a permeable petroleum producing reservoir with a borehole;

(b) injecting through said borehole into said reservoir a slug of a non-condensable gas;

(c) subsequently injecting through said borehole into said reservoir a heated fluid having a temperature sufficient to increase the mobility of the reservoir petroleum;

(d) terminating said injection of heated fluid;

(e) reducing the pressure within the borehole to less than the pressure within the reservoir and allowing fluid to flow into said borehole as the result of the pressure gradient established within the reservoir by said fluid injections and pressure reduction; and

(f) recovering petroleum from said borehole.

2. A method as defined in claim 1 in which said slug of non-condensable gas is nitrogen mixed with a gas selected from the group consisting of carbon monoxide, carbon dioxide, methane, ethane and oxygen.

3. A method as defined in claim 1 in which the slug Volume of the non-condensable gas is at least as large as the volume of the heated fluid that is injected into the reservoir.

4. A method of claim 1 in which the heated fluid is selected from the group consisting of steam, vaporizable hydrocarbons, heated water, heated liquid condensate and mixtures thereof.

5. A method of claim 1 in which the volume of the heated fluid is at least about 30% of the pore space in the heated zone.

6. A method of recovering petroleum from subterranean reservoirs which comprises the steps of:

(a) penetrating a permeable petroleum producing reservoir with a borehole which traverses at least a portion of the reservoir;

(b) casing said borehole at least to the extent of its traverse of said reservoir and sealing said casing string in said borehole at least to the extent of its traverse of said reservoir;

(c) perforating said casing string and sealant to provide fluid communication between said reservoir and the inside of said casing string;

(d) injection through said casing string and into said formation a slug of non-condensable gas;

(e) subsequently injecting through said casing string and into said formation a volume of steam that is not substantially greater than the volume of said slug of non-condensable gas;

(f) thereafter shutting in said casing string at the in jection pressure for a soak period;

(g) subsequently releasing the pressure in said casing string and permitting fluid to drain into said casing string; and

(h) recovering said petroleum from said casing string.


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Referenced by
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US3394759 *Nov 17, 1965Jul 30, 1968Exxon Production Research CoShort-term multicycle combustion stimulation of oil wells
US3399722 *May 24, 1967Sep 3, 1968Pan American Petroleum CorpRecovery of petroleum by a cyclic thermal method
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U.S. Classification166/285, 166/306, 166/303, 166/297
International ClassificationE21B43/16, E21B43/24
Cooperative ClassificationE21B43/24, E21B43/164, E21B43/16
European ClassificationE21B43/16E, E21B43/16, E21B43/24