US3120262A

US3120262A - Waterflood method

Info

Publication number: US3120262A
Application number: US237105A
Authority: US
Inventors: Duane L Archer
Original assignee: Pan American Petroleum Corp
Current assignee: Pan American Petroleum Corp
Priority date: 1962-11-13
Filing date: 1962-11-13
Publication date: 1964-02-04
Anticipated expiration: 1981-02-04

Description

Feb. 4, 1964 D. L. ARCHER 3,120,262

WATERFLOOD ME'IHOD Filed Nov. 13, 1962 ORIGINAL ORIGINAL OIL-lN-PLACE WELL 5 OIL-IN-PLAOE ELL 5 FIG.I FIG. 2

WATER BANK WATER WELL A CO2- ENRICHED OIL wELLA ORIGINAL BANK OIL-lN-PLACE co ENRICHED CO2 OIL PROOucEO OlL-lN-PLACE INJE TED OlL-lN-PLACE EL 8 FIG L 2 -ENRICHED OIL WELL A ORIGINAL OIL-lN-PLACE co INJECTED o|L..|N..p c

PRODUCED ORIGINAL OIL-IN-P AGE w LL 8 AREA OF ADDITIONAL L2 OIL RECOVERY BY PROPOSED METHOD AREA SWEPT BY WATER ORIvEN CO2 PROcEss ORIGINAL OlL-IN-PLACE WELL A DUANE L. ARCHER, INVENTOR.

BYM- by. $57

A T T'ORNE Y United States Patent can Petroleum Corporation, Tulsa, 01th., a corporation of Delaware Filed Nov. 13, 1962, Ser. No. 237,105 13 Claims. (Cl. 166-9) The present invention is concerned with an improved process for recovery of oil from an underground reservotr. More particularly, it relates to an improved secondary method of oil recovery based upon the general phenomenon of reducing the initial viscosity of the oil by dissolving therein an oil-soluble gas and following with a water or similar flood whereby the oil of reduced viscosity is recovered in increased amounts. Specifically, the process of my invention. although involving the idea of reducing the viscosity of the oil in place prior to recovery. concerns primarily a sequence of steps by which the aforesaid phenomenon is utilized to the fullest CK Cl'll.

While the following description is directed chiefly to the use of carbon dioxide as the oil-soluble gas employed m my invention. obviously other gases. such as methane. sulfur dioxide. hydrogen sulflde. carbon monoxide, and the like. or mixtures of one or more of said gases with or without carbon dioxide are contemplated.

The elilciency of oil production from underground reservoirs by any secondary recovery process is a funcllOll of the ultimate recovery per barrel of oil in place at the beginning of the process. Such efiicicncy depends upon three principal variables: the vertical sweep cfflciency. the horizontal sweep efllciency. and the displacement eflicicncy. This invention. however. is concerned primarily with the horizontal sweep efliciency and. to some extent, with improvement in the displacement cfliciency which relates to the volume of driven fluid actually recovered from a particular unit of a reservoir by displacement with a driving fluid.

l have found in comparing an ordinary water drive or flood with a process involving flrst injecting an oilsoluble gas. such as carbon dioxide. into the reservoir oil followed by water drive. the carbon dioxide injected improves the volumetric sweep efllcicncy as well as an improved displacement elilciency. This water-driven carbon dioxide method uses the injection of an optimum volume of carbon dioxide followed by water injection. As the carbon dioxide contacts the original oil in place. it dissolves in the oil. increases the volume of the latter. and reduces the viscosity of the oil. Thus, as the water bank advances. it displaces the carbon dioxideenriched oil bank (originally saturated with carbon dioxide). it also displaces the original oil in place. A number of variations of this principle have been described and atcnted. However. they all suffer from the fact that they still leave very substantial amounts of oil in the reservoir in either the ordinary water-flooding or the water-driven carbon dioxide processes. After water breakthrough. the water-oil ratio increases until the economic limit is reached. in viscous oil reservoirs in which the water-driven carbon dioxide process has been cmploycd, the area swept at water-breakthrough and at floodout is only a small portion of the reservoir. in such cases a large amount of oil is left unrecovered.

Accordingly. it is an object of my invention to provide a method involving the use of an oil-soluble gas or mixturcs of such gases whereby increased quantities of oil can be recovered from a reservoir through the introduction of such gas or gases into said reservoir via both an injection and a production well or wells. it is another object to provide an improved method of recovering oil from an underground reservoir by first injecting a suitable (iii 3,120,262 Patented Feb. 4, 1964 ice oil-soluble gas into the ultimate producing well and thereafter introducing said gas into said reservoir via an injection well until the gas-enriched oil thus formed constitutes at least a major portion of the recoverable oil. after which the system is subjected to a water-flooding operation. it is still another object of my invention to provide a secondary recovery process that can be applied clilcicntly to viscous oil reservoirs of the type that heretofore have not been considered suitable for conventional watcrflooding operations.

FIGURE 1 is a diagrammatic representation of the mechanism involved in recovering oil from a reservoir by means of the water-driven carbon dioxide method.

FIGURE 2 shows the condition of the reservoir at the time of water-breakthrough at the producing well, (shown as well B). using the water-driven carbon dioxide method.

FlGURE 3 illustrates the state of a hydrocarbon reservoir after something less than percent of the hydrocarbon pore volume between wells A and B has been filled with carbon dioxide.

FIGURE 4 is a representation of the reservoir after suliicicnt carbon dioxide has been introduced via an injection well. (in this case well A). to form a carbon dioxidc'curiched bank of oil extending from the producing well to the injection well.

FIGURE 5 shows the swept area after the system illustrated in FIGURE 4 has been waterfloodcd.

in a preferred embodiment of my invention. referring to the diagram of FIGURE 3. carbon dioxide is injected into well I) (the ultimate producing well), discontinuing injection at some point prior to breakthrough into well A. The quantity of injected carbon dioxide required for this step corresponds to an amount not exceeding 50 percent of the hydrocarbon pore volume. When the volume of carbon dioxide exceeds about 50 percent of the reservoir hydrocarbon pore volume. breakthrough of carbon dioxide into well A. (the injection well). occurs. Accordingly. while the ultimate object of my invention can be secured with such quantities of carbon dioxide being injected via the producing well, volumes of carbon dioxide incxccss of 50 percent in this initial injection step of my process are not only unnecessary. but are wasted and hence are uncconomical. During injection of carbon dioxide into well ll, produccd oil is withdrawn from well A. When the desired amount of gas has been introduced via well it. injection thereof is halted and introduction of gas is begun in well A. if approximately 50 percent of the hydrocarbon pore volume is introduced into each of wells A and B, a pattern of gassaturated oil is formed similar in shape to the shaded area C, shown in FlGURE 4. While injection of carbon dioxide is taking place in well A. the fluid produced from well I) is carbon dioxide-enriched oil. Carbon dioxide or other equivalent gas can easily be separated from such oil and re-injcctcd into well A or into another well for the purpose of producing additional gas-saturated oil.

it should also be pointed out that at the stage of operations where carbon dioxide or equivalent gas is being injected into the reservoir via well A. the quantity of gas added at this time need not be enough to form a pattern of the type shown in FIGURE 4. it will be apparent from the foregoing description, and that which follows, that an improved result can be obtained even if the amount of gas added through well A is not enough to touch the bank of carbon dioxide-enriched oil already formed in the vicinity of well 8. The amount of gas first injected, i.e. well B. may vary from about 5 percent to about 50 percent of the hydrocarbon pore volume while the volume of gas injected during the second step. i.e., through well A, may range from a minimum of about 20 percent to a maximum of about 50 percent of the hydrocarbon pore volume. In cases where a minimum gas volume of 20 percent is injected during the second step, larger amounts, i.e., 40 to 50 percent, of gas should be employed for the initial injection step. Stated otherwise, the total volume of gas supplied during both injection steps prior to waterflooding should correspond to from about 60 to about 100 percent of the hydrocarbon pore volume in that portion of the reservoir lying between the producing and injection wells, with the volume of gas injected into any one well amounting to not more than 50 percent of said hydrocarbon porevolume.

After the desired amount of gas has been llljCOlCd into the reservoir via wells A and B, water is then introduced into the formation via either of wells A or B and gasenriehed oil recovered from the other of these wells until the economic limit is reached. The gain in oil recovery obtained by this process is represented by the shaded area D of FIGURE 5. By a comparison of the diagrams shown in FIGURES 2 and 5 it is apparent that the quantity of oil recovered by my process (FIGURE 5) is from A to A greater than that obtainable by use of the waterdrivcn carbon dioxide method (FIGURE 2).

it should be pointed out that the manner in which the process of my invention is applied to a given reservoir may vary widely. For example, if desired. a conventional S-spot pattern can be used, with the ultimate water injection well being in the center-or an inverted S-spot arrangement can be used, i.c., having the producing well in the center.

To enhance the solubility of the gas employed in the petroleum to be recovered, a mixture of said gas and one or more of the lower molecular weight hydrocarbons may be used. Natural gas containing typically 85 to 90 percent methane snd from to percent C, to C and higher hydrocarbons constitutes a good medium with which to mix the drive gas of my invention. in fact, a natural gas of the above indicated composition is suitable for use by itself as the gaseous component in my process. Also, the drive gas may be dissolved in a normally liquid low molecular weight hydrocarbon, such as-for example-naphthenes, aromatics, or paratiins, boiling below about 350' F. For best results, it is generally recommended that such solutions be saturated with respect to the drive gas. However, beneficial effects can be secured with the use of solutions containing lesser amounts of gas than the saturation concentration. These solutions, of course, are to be used under conditions such that they remain predominantly in the liquid phase while in the reservoir. Prevailing reservoir conditions determine the initial gas saturation that will be in accord with this requirement. While carbon dioxide is an example of a suitable gas that can be dissolved in hydrocarbons for use in the manner indicated above, other oil-soluble gases, either by themselves or in mixtures, can be dissolved into such hydrocarbon and employed in accordance with the process of my invention.

Tire pressure employed in conducting the process described and claimed herein preferably should be the highest the particular reservoir involved can withstand without causing uncontrolled bypassing and/or fracturing of the formation. in the majority of instances pressures of from about 1000 to about l0,000 p.s.i. are satisfactory. Higher pressures, of course, render the gas more dense, which in turn means that more gas is present to dissolve in a given volume of oil. 7

My invention is adapted particularly to heavy oil reservolrs having a viscosity of at least about 100 ccntipoises. it will be recognized that by my invention it has now been made possible to water-flood reservoirs which have been hitherto incapable of responding satisfacorily to conventional waterflooding or water-driven carbon dioxide processes since the latter procedures generally are applicable only to reservoirs in which the oil has a lower viscosity. Thus, I found that with crude oils having a viscosity, for example of about 400 centipoises, when saturated with carbon dioxide at room temperature, the viscosity decreases to about 22 ccntipoises. Oils having an initial viscosity of 100 cenlipoises, when saturated with carbon dioxide under these conditions, have a viscosity of 8 to 10 ccntipoises. it is apparent that by such drastic reductio njn viscosity this change will be accompanied by a very substantial increase in the reservoir pore vol ume filled with hydrocarbons. in essence this amounts to an appreciable increase in both the horizontal sweep eiiiciency and the displacement ciliciency experienced in the subsequent ilooding step.

i claim:

l. in a process for recovering normally liquid hydrocarbons from an underground reservoir thereof, having an injection well and a producing well spaced apart from one another and extending into said reservoir,

the improvement which comprises injecting into said reservoir via one of said wells an oil-soluble gas under pressure in an amount corresponding to not more than about percent of the hydrocarbon pore volume of that portion of the reservoir between said wells,

discontinuing injection of said gas into said one of said wells and introducing said gas into said reservoir via the other of said wells until the quantity of said gas so introduced amounts to at least about 20 percent but not more than about 50 percent of said hydrocarbon pore volume,

next injecting water into one of said wells, and

recovering gas-enriched hydrocarbons from the other of said wells.

2. The process of claim 1 in which the water injecting step is continued until the water-liquid hydrocarbon ratio of the produced fluids becomes uneconomical.

3. The process of claim 1 in which the oil-soluble gas employed is carbon dioxide.

4. The process of claim 1 in which the oil-soluble gas is dissolved in a hydrocarbon boiling below about 350' F.

5. The process of claim 4 in which the oil-soluble gas is carbon dioxide.

6. The process of claim 1 in which the water-injection step is carried out in the injection well.

7. The process of claim l in which the initial gas injection step is carried out in said producing well.

8. The process of claim l in which the waterflooding step is carried out by injection of water into said reservoir via the well into which said gas was first introduced.

9. The process of claim 1 wherein the total quantity of said gas injected into said reservoir amounts to from about percent to about l00 percent of said hydrocarbon pore volume.

10. The process of claim I in which a mixture of oilsoluble gases is employed.

soluble gases is employed.

12. The process of claim 1 in which the gas present in said recovered gas-enriched hydrocarbons is separated therefrom and injected again into said portion of said reservoir.

13. The process of claim 1 wherein the viscosity of said liquid hydrocarbon is at least about ccntipoises.

ii. The process of claim 4 in which a mixture of oil-- References Cited in the tile of this patent UNITED STATES PATENTS

Claims

1. IN A PROCESS FOR RECOVERIN GNORMALLY LIQUID HYDROCARBONS FROM AN UNDERGROUND RESERVOIR THEREOF, HAVING AN INJECTION WELL AND A PRODUCING WELL SPACED APART FROM ONE ANOTHER AND EXTENDING INTO SAID INTEROIR. THE IMPROVEMENT WHICH COMPRISES INJECTING INTO SAID RESERVOIR VIA ONE OF SAID WELLS AN OIL-SOLUBLE GAS UNDER PRESSURE IN AN AMOUNT CORRESPONDING TO NOT MORE THAN ABOUT 50 PERCENT OF THE HYDROCARBON PORE VOLUME OF THAT PORTION OF THE RESERVOIR BETWEEN SAID WELLS,