CA1129634A - Polymer thickener in water-alternating gas process for oil recovery - Google Patents

Abstract

ABSTRACT OF THE DISCLOSURE
Water containing a polymer and, optionally, a surfactant is used as the water in a WAG process using CO2. The polymer functions as a water thickening agent. Slugs of CO2 and water containing polymer are injected into an underground formation to miscibly displace oil which could not economically be recovered by primary or secondary water flooding techniques.

Description

Case No. 5517 1.12 9 6 3 4 RDS/eob TERTIARY OIL RECOVERY PROCESS

BACKGROUND OF THE INVENTION

FIELD OF THE INVENTION

This invention relates to a tertiary oil recovery process using polymer flooding as an integral part of a W~G, water alternating with gas, CO2 flood.

DESCRIPTION OF THE PRIOR ART

Oil has been produced by either primary or secondary methods for many years. These methods can re-cover oil at relatively low costs and rapid rates. How-ever, large amounts of oil, usually more than 50 percent, will remain in the reservoir even aEter secondary re-covery, water flooding. This is because of the relative-ly high interfacial tension at the oil-water interface, which causes th~ entrapment of residual oil in the oil-bearing formations and poor sweep efficiency during wa~erfloods.
It is possible to reduce this interfacial tension between the oil and water phases by adding surface active agents to a waterflood. Petroleum sulfonates are good surface active agents.
Injection of CO2 at high pressures into a forma-tion has also been practiced. The CO2 vaporizes some components of the crude and carries them forward to con-tact additional oil, and a portion of the CO2 also dis-solves in the crude. When C02 dissolves in crude oil, the crude swells and the viscosity drops.

- -11~9~34 At a certain point in the reservoir, when the C02-hydro-carbon mixture reaches a certain compOSitiQn, miscibility occurs.
This is so-called multiple contact miscibility. ~esidual oil can be reduced to a very low level, five to ten percent of the porous space, during the miscible displacement process.
In the immiscible regionJ oil recovery also can be improved because it is easier to displace the less viscous crude, and the swelling action of the C02 minimizes the amount of crude left be-hind.
The basic miscible C02 flooding process patent is disclosed in United States Patent 2,623,596 ~United States Class 166-21).
Various improvements have been made in the C02 miscible flood pro-cesses.
Some problems occur in CO2 fLooding, one of the most signi-ficant being the tendency of the ;njected CO2 to by-pass signifi-cant portions of the formation. The C02 does this, to even a greater extent than does water in a water flood, because ~he CO2 and the CO2-hydrocarbon mixtures are much more mobile than the oil or water in a formation.
Use of a surfactant in conjunction with the C02 flood was disclosed in United States Patent 3,3~2,256 (United States Class 166/9).
The patentee taught adding a surfactant capable of forming a stable foam under formation conditions before or during the CO2 flood.
The foam would tend to block highly permeable strata, cracks and fissures. The foam also increases the ~iscosity of the carbon dio-xide making it a more efficient displacing fluid.

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Another solution to the by-pass problem is the WAG pro-cess, Water Alternating with Gas, preferably CO2. This reduces the mobility of the CO2 and promotes a better sweep of the forma-tion. Frequently WAG injection of CO2, or injection of a single large slug of CO2, is followed with a water flood to drive the C2 through the formation. This minimizes the amount of relatively expensive C02 which must be injected, and perhaps left, in a forma-tion.
One variation upon the water flooding theme is disclosed ~;
in United States Patent 3,817,331, ~nited States Class 166/275), Jones, Waterflooding Process. Jones recognized that prior re-searchers had tried to improve conventional water flooding tech-niques by creating a foam bank between the oil and the water flood to control the mobility of the water. The improvement disclosed by Jones consisted of injecting a non-foaming surfact-ant into a well, flooding with water, and then injecting gas through the water flood. The gas collected the surfactant and -carried it ahead of the water to contact the oil. Jones contem-plated using CO2, and recognized the advantages of contacting crude with CO2. The patentee taught that it was crucial that the gas phase have a relatively high mobility, and that conditions be provided which favored the free forward movement of gas through a water flood.
In the example of this patent, very little CO2 was used, only the amount which would dissolve in water at 13 psi, presum-ably at room temperature. This carbonated water is not even close to the amount of CO2 which would be required to achieve a CO2 miscible flood.

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Another hybrid process has been proposed in United States Patent 3,882,940, ~United States Class 166/273), Carlin, Tertiary Oil Recovery Process Involving Multiple Cycles of Gas-Water Injection after Surfactant Flood. Carlin proposes conventional surfactant flooding followed by use of small, alternating gas and water slugs, followed by injection of a drive fluid, usually water.
Both the processes of Carlin and Jones require the addi-tion of substantial amounts of surfactants. Neither makes substant-ial use of the advantages of a miscible CO2 flocding process, relying~ on the surfactant flooding as the primary method of re-covering oil.
An improved CO2 process was disclosed in United States Patent 4,113,011 ~United States Class 166/273). The patentee used a surfactant comprising alkyl polyethylene oxide sulfates. This reference also discloses adding some low molecular weight alcohol to the surfactant solution. The patentee noted that at very high pressures, carbon dioxide behaved as a dense fluid, and there would be no significant volume increase as the carbon dioxide passed through permeable strata underground. This would result in no ~oam formation, though increased recovery was claimed. It is believed that the patentee saw the results of a combination of a combination of CO2 miscible displacement and conventional sur-factant miscible displacement.

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SUMMARY O~ THE INVENTION
In the process of the invention, a WAG, CO2 miscible flooding process is supplemented by the addition of polymer into the watar to improve sweep efficiency and oil recovery.
Accordingly, the present invention provides in a process for recovering petroleum from an underground formation, said form-ation having an injection well and a producing well, and oil is forced toward said producing well by-miscible displacement with C2 in a water-alternating-gas process, the improvement comprising adding to at least a portion of the water used in said WAG process, 50 to 500 wt. ppm of a polymer as a water thickening agent.
In another embodiment, the prese~nt invention provides in a process for recovering petroleum from an underground formation, said formation containing connate water which is hard and deleter-ious to conventional surfactant flooding process and having an injection well and a producing well and oil is forced toward said producing well by miscible displacement with CO~ in a water-alternating-gas process, the improvement comprising use of water in said WAG process which contains 50 to 500 ppm of a water thickening agent comprising a polymer selected from a group of polyacrylamides and Xanthan gums, and wherein the water-alternating-gas process consists of at least five separate injections of CO2 alternated with water injections, and wherein at least the first two water injections contain a water thickening agent and at least the last two water injections contain a surfactant.

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Case No. 5517 ~IL2~ RDS/eob The carbon dioxide which is used in the practice of the present invention is preferably at least 90 mole percent CO2 or higher. The mechanisms of CO2 injection are well known in the art and need not be discussed. An overview of this process was presented by Stalkup, F.I.
"Carbon Dioxide Miscible Flooding: Past, Present, and Outlook for -the Future", Paper SPE 7042, presented at SPE-AIME Improved Oil Recovery Symposium, Tulsa, April 16-19, 1978.

DETAILED DESCRIPTION

In conventional CO2 miscible flooding processes about 0.1 to 0.5 pore volumes of CO2 would be injected into a formation. In -the present invention, somewhat lesser amounts of CO2 injection are possible. Alter-natively, an amount of CO2 injection equivalent to prior art processes may be used with improved oil recovery being the result.
Polymers which may be added to the water may be broadly classed as either synthetic or biopolymers. Syn-thetic polymers are usually polyacrylamides. Riopolymers are usually derived from a fermentation process, e.g., Xanthan gums. The concentrations needed are relatively low, on the order of 50 to 500 wt. ppm, based on active ingredients.
Use of thickened water will improve sweep ef-fi-ciency, but by itself it will not significantly improve oil recovery in an area which would have been swept anyway by the CO2 flood. Improved sweep efficiency will result in more oil recovery because more of the formation will be contacted with the CO2 flooding agent.

Case No. 5517 Harry L. Chang RDS/eob ~ 6 3 ~ 1/22/80 Surfactants may also be added to the water in the present invention. Any surfactants used conventionally in surfactant flooding may be used, so long as the presence of C2 will not cause formation of precipitates. Swr-factants may be broadly classified an anionic, cationic or nonionic. Preferably anionic surfactants having an equivalent weight of 250-600 are used.
Typical anionic surfactants are:
(1) Alkyl-aryl sulfonates having the following structure:

R-phenyl -SO3 M

~here R is an alkyl radical, linear or branched, with 8-15 carbon atoms~ and M is a monovalent cation such as Na , K+ or NH4 .

(2) Alkyl sulfonates having the following struc- , ture:

R-S03-M~

Where R and M have the same meaning as in (1).

(3) Alkyl polyethoxylated sulfates having the following structure:

(R-(ocH2cH2)nso4) M

Where R and M have the same meaning as in (1), and n is an integer from 2 to 6.

(4) Alkyl aryl disulfonate e-thers having the following structures:

~L~ 3~ Harry L Chang RDS/eob R-phenyl-0-phenyl and R-phenyl-0-phenyl-R
S03 M S03 ~1 S03 M S03-M+

Where R and M having the same meaning as in (1) except the carbon atoms range from 6 to 16.
These surfactants preferably include a foaming agent, since foams will improve mobility control. Sur-factant concentrations of 0.01 to 10 wt. % are within the scope of the present invention, with a surfactant con-centration of 0.1 to 2 wt. % being preferred.
The presence of surfactant in the WAG water assists in oil recovery by improving the displacement of crude oil from a formation. It is typical of a C02 miscible flooding process that no oil bank is developed near the injection well because time and distance are needed for the C02 to vaporize light components from the crude, and also for the C02 to dissolve in the crude. It is known from laboratory tests using a C02 miscible process that a relative~y long core is necessary to develop an oil bank. Miscibility cannot be achieved near the point of C02 injection. The C02 miscible flood is preferably complimented by the action of the sur:Eactant - flood. What is left behind by the C02 flood may be picked up by the surfactanL flood. The C02 flood is re-latively ineffective near the injection well, while the surfactant ~lood is most effective at that point. The operation of the C02 flood improves with time and dis-tance through the formation, just as the efficiency of the surfactant flood drops off dwe to dilution with con-nate water and/or contac-t with high salinity reservoir brines.

Case No. 5517 Harry L. Chang ~ 1/22/80 The two different flooding mechanisms which are used simultaneously in the practice of my invention com-plement one another in that the simultaneous flooding im-proves sweep e:Eficiency which benefits both the CO2 flood and the surfactant flood. Another advantage of this pro-cess is that the CO2 flood tends to displace some of the connate water before it, resulting in less dilution and degradation of surfactant and/or polymer which is con-tained in the water portion of my WAG process.
The volume ra-tio of water and CO2 injected during the WAG portion of my process should range from about 5:1 to about 0.5:1, and preferably from about 3:1 to 1:1 volumes of water per volume of CO2 at reservoir con-ditions.

ILLUSTRATIVE EMBODIMENT

Although I have not tested my inven-tion in the field, the following is an illustration of the best way known to apply this invention commercially and the re-sults I expect to obtain.
29 I would inject five cycles of alternating CO2-thickened water plus surfactant. Each cycle consists of injecting 0.04 pore volumes CO2 followed by 0.04 pore volu~es water containing surfactant. The water will con-tain 1.0% petroleum sulfonate. The water will also contain about 200 ppm biopolymer, on average. A decreas-ing polymer content is preferred, with higher levels of biopolymer being added to the first slug, and less added to the final slug, e.g., 350, 300, 250, 200, 150 ppm of biopolymer would be added to the 1st through 5th slugs, respectively.

Case No. 5517 Harry L. Chang ~`~Z ~3~ R S/eob It is believed that the practice of the present invention will increase oil recovery, while reducing consumption of surfactant and polymer. To be an economic success, the practice of the present invention requires an economical source of relatively pure CO2, but such CO2 sources are available both from subterranean sources and exhaust streams from fertili~er plants, power plants, etc.
Other variations of the present inven-tion which may be useful in particular formations include tapered injection of surfactants and/or polymer. It may be de-sirable to load most of the surfactant injection into the first one or two surfactant s:lugs. Alternatively, sur-factant concentration in the water may be kept relatively constant, with the size of the water slug tapering while holding size of the CO2 slug constant. Polymer may be added to all or some of the water slugs, in a constant or varying composition.
Polymer and surfactant may be used in the follow-ing manner:
(l) Slug Volume Slug Type:;

0.04 Surfactant 0.04 Surfactant 0.04 Surfactant 0.04 Surfactant Case No: 5517 3 ~ RDS/eob 0.04 Surfactant 0.10 Polymer ~350 wt. ppm) 0.20 Polymer (250 wt. ppm) 0.20 Polymer (150 wt. ppm) (2) 0 04 C2 0.04 Surfactant 0'04 C2 0.04 Polymer (250 wt. ppm) 0.04 Polymer ~250 wt. ppm) 0 04 Polymer (250 wt. ppm) 0.04 Polymer (250 wt. ppm) 0.04 Polymer (250 wt. ppm) 0.50 Polymer, tapered concentration In its simplest embodiment, the present invention - calls for use of a CO2 miscible flood process used in conjunction with thickened water. My process will give superior oil recovery, as compared to the prior art processes using CO2 miscible flooding in conjunction with surfactant additions. This is because my process does not depend upon the formation of a foam to act as the water thickening agent. In the practice of the preferred embodiment of my invention, CO2 miscible flooding, thick-ened water, and surfactant flooding are used together. In this mode of operation, thickened water improves the efficiency of the CO2 flood, while the surfactant flood compliments the action of the CO2 flood. The CO2-polymer flood can also be used to sweep from the formation un-desirable connate water which would o-therwise adversely Case No. 5517 Harry L. Chang :~12~3~ Rl~2S/~C80b affect the surfactant materials used in the surfactant flood. Thus, results could be achieved with the practice of my invention which coulcl not be achieved with prior art processes, wherein -the efficiency of the surfactant flood would ~e harmed by the presence of hard water or other problem minerals in the formation. Similarly, my process is not dependent on the presence of pressure drops across any part of the formation to generate foam.

Claims

Case No. 5517 Harry L. Chang RDS/eob CLAIM 1: In a process for recovering petroleum from an underground formation, said formation having an injection well and a producing well, and oil is forced toward said producing well by miscible displacement with CO2 in a water-alternating-gas process, the improvement comprising adding to at least a portion of the water used in said WAG process, 50 to 500 wt. ppm of a polymer as a water thickening agent.

CLAIM 2: Process of Claim 1 wherein the water thickening agent is a polyacrylamide.

CLAIM 3: Process of Claim 1 wherein the water thickening agent is a biopolymer.

CLAIM 4: Process of Claim 1 wherein at least a portion of the water used contains a surfactant.

CLAIM 5: Process of Claim 4 wherein the surfactant has an equivalent weight of 250 to 600.

CLAIM 6: Process of Claim 5 wherein the surfactant is a petroleum sulfonate.

CLAIM 7: In a process for recovering petroleum from an underground formation, said formation having an injection well and a producing well, and oil is forced toward said producing well by miscible displacement with CO2 in a Case No. 5517 Harry L. Chang RDS/eob water-alternating-gas process, the improvement comprising use of water in said WAG process which contains 50 to 500 ppm of a water thickening agent comprising a polymer se-lected from a group of polyacrylamides and Xanthan gums wherein the water-alternating-gas process consists of at least five separate injections of CO2 alternated with water injections, and wherein at least the first two water injections contain a water thickening agent and at least the last two water injections contain a surfactant.

CLAIM 8: In a process for recovering petroleum from an underground formation, said formation containing connate water which is hard and deleterious to conventional sur-factant flooding process and having an injection well and a producing well and oil is forced toward said producing well by miscible displacement with CO2 in a water-alter-nating-gas process, the improvement comprising use of water in said WAG process which contains 50 to 500 ppm of a water thickening agent comprising a polymer selected from a group of polyacrylamides and Xanthan gums, and wherein the water-alternating-gas process consists of at least five separate injections of CO2 alternated with water injections, and wherein at least the first two water injections contain a water thickening agent and at least the last two water injections contain a surfactant.