WO2010090889A2

WO2010090889A2 - Polymer recovery and recycle

Info

Publication number: WO2010090889A2
Application number: PCT/US2010/021947
Authority: WO
Inventors: Subhash Chandra Ayirala; Robert Wing-Yu Chin; Michael Alvin Curole
Original assignee: Shell Oil Company; Shell Internationale Research Maatschappij B.V.
Priority date: 2009-02-05
Filing date: 2010-01-25
Publication date: 2010-08-12
Also published as: BRPI1008862A2; GB2478891B; WO2010090889A3; CN102307814B; GB2478891A; BRPI1008862B1; GB201112527D0; CN102307814A

Abstract

A system for recovering hydrocarbons from a formation, comprising a first well in the formation to produce a mixture comprising one or more hydrocarbons and an aqueous solution; a separator to divide the mixture into one or more hydrocarbon streams and an aqueous solution stream; a membrane to separate the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; a second well in the formation to inject an aqueous polymer solution, wherein the aqueous polymer solution comprises at least a portion of the first stream.

Description

POLYMER RECOVERYAND RECYCLE

Field of the Invention

Embodiments disclosed herein relate generally to apparatuses and methods used for enhanced oil recovery operations with a polymer. Background of the Invention

Chinese Patent number CN101164920 A 20080423 discloses the deep treatment of waste-water from an oil-field and the method for reutilization of the water as resource. The waste-water, after being pre-treated, is mixed with KMnO₄ for oxidation to remove its reductive substances, after that is subjected to an ultra- filtration to remove its precipitate and suspended impurities. The water after being treated can be used for preparing polymer solution with to increase the viscosity of the solution. The solution can be fed back into an oil-well for tertiary oil recovery, to increasing the yield and obtain an economic benefit. Chinese Patent number CN101 164920 is herein incorporated by reference in its entirety. Accordingly, there exists a need for reduced cost systems and methods for polymer flooding operations.

Accordingly, there exists a need for polymer flooding operations with lower polymer needs.

Summary of the Invention One aspect of the invention provides a system for recovering hydrocarbons from a formation, comprising a first well in the formation to produce a mixture comprising one or more hydrocarbons and an aqueous solution; a separator to divide the mixture into one or more hydrocarbon streams and an aqueous solution stream; a membrane to separate the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; a second well in the formation to inject an aqueous polymer solution, wherein the aqueous polymer solution comprises at least a portion of the first stream.

Another aspect of the invention provides a method comprising producing a mixture comprising one or more hydrocarbons and an aqueous solution from a formation; separating the mixture into one or more hydrocarbon streams and an aqueous solution stream; separating the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; injecting an aqueous polymer solution into the formation, wherein the aqueous polymer solution comprises at least a portion of the first stream

Brief Description of the Drawings

FIG. 1 shows a flowchart in accordance with one embodiment of the present invention.

Detailed Description of the Drawings In one aspect, embodiments disclosed herein relate generally to apparatuses and methods used for recovering polymer from oil field produced water. Specifically, embodiments disclosed herein relate to a system for filtering polymer additives from produced water using a membrane. As used herein, the terms 'feed' and 'produced water' refer to a stream of production fluid generated from a wellbore during production, containing any combination of oil, gas, water, brine, polymers, salts, sulfites, and other additives or components that comprise an aqueous injection fluid used to flood/sweep subterranean hydrocarbon-containing formations.

Hydrocarbons are extracted from subterranean hydrocarbon-containing formations that are located in various environments. Some reserves have been discovered around the globe where it is not possible to produce oil economically using conventional oil recovery processes such as primary pressure depletion and secondary water floods. Thus, alternative recovery processes for such formations have been developed. One such method is enhanced oil recovery ("EOR"), which uses an injection well to inject a treatment or injection fluid, such as a gas or an aqueous chemical solution, down-hole into an oil producing formation to force oil toward a production well. As used herein, 'polymer injection,' which falls under the umbrella of "chemical flooding", refers to a viscous aqueous polymer solution used to flood subterranean hydrocarbon-containing formations and enhance oil recovery from those formations. The mechanism responsible for enhanced oil recovery with polymer injection is the increased viscosity of the injected solution, which results in effective mobility control of fluids (oil and water) displaced in the reservoir. In EOR mechanisms, energy for hydrocarbon production from subterranean hydrocarbon-containing formations is supplied by injecting aqueous chemical fluids or gases through at least one injection well into the formation under pressure such that the chemical fluids and/or gases drive the hydrocarbons to at least one production well. The most commonly used chemical EOR technique is 'polymer flooding,' which, as used herein, refers to the injection of an aqueous fluid containing polymer into a formation under pressure such that it provides the required mobility to force hydrocarbons in a formation to at least one production well.

Several factors may influence the efficiency of secondary water flooding processes, including the permeability of the formation and the viscosity of the hydrocarbons in the formation. Based on the viscosity of the hydrocarbons in the formation, polymer additives are typically mixed with injection water to increase the viscosity of the injected water to be comparable to or greater than the viscosity of the hydrocarbons to be displaced from the formation. By increasing the viscosity of the injection water to be comparable to or greater than the viscosity of the hydrocarbons in the formation, the polymer-containing injection water is able to effectively provide piston-like displacement of the oil ahead of it while minimizing fingering of water through the oil, resulting in more efficient hydrocarbon recovery.

Controlling the viscosity of the injection water is important because such fluids tend to follow the course of least resistance within a formation, e.g., flow through highly permeable zones in the formation and effectively bypass less permeable zones that may contain hydrocarbons. For example, such a process occurs in heavy oil reservoirs or formations containing high viscosity hydrocarbons, where the aqueous injection fluid has a viscosity less than that of the high viscosity hydrocarbons in the formation. As a result, large quantities of polymer additives are required to achieve the increased target viscosity based on the high viscosity hydrocarbons sought to be removed from the formation. In such cases, this makes the project economically unattractive due to the high cost of the polymer additives and/or the preparation of the injection fluid. Current EOR applications require the injection fluid to be prepared according to the properties of the target formation. In general, dry, solid polymers are first dissolved in an aqueous injection solution to form the highly concentrated mother solution (5,000-10,000 ppm). This process, however, is time consuming and requires special mixing equipment. In addition, other problems arise when solid organic polymers are used for mother solution preparation. These include insufficient hydration due to non-homogeneous mixing and undesirable cross- linking of some of the polymers with metal contaminants when oxygen is present . Cross-linking or insufficient hydration can result in the formation of microgels or fish-eyes in the polymer mother solution , which tend to cause the diluted injection fluid to plug the formation into which it is injected. To avoid these problems, readily available concentrated organic polymer solutions may be preferred at the drilling site or other site where the injection fluid is prepared. This eliminates the time and cost of disolving the dry polymers into solution at the drilling site.

Existing EOR mechanisms dispose of the expensive polymer additives after they have been used in the injection water, thus resulting in limited application of the polymer injection process in heavy oil environments. Advantageously, embodiments described herein may improve the project economics in heavy oil applications by allowing for recovery - rather than disposal - of the polymer from the oil field produced water. In one embodiment, at least a portion of polymer may be recovered from the oil field produced water using a membrane; the recovered polymer may then be reused in subsequent EOR mechanisms by adding the recovered polymer back into the injection water. Also, removal of polymer for reuse may enable overboard disposal of produced water into the ocean or another water disposal location where disposal of large quantities of polymer may be discouraged or illegal.

Specifically, existing polymer injection EOR applications indicate that 30- 50% of the injected polymer is present in the oil field produced water. Of this 30- 50%, up to about 95% of the injected polymer may be recovered using a membrane of the present disclosure. Polymers presently used for EOR applications cost about $1.00 to $3.00 per pound and the recovery of these significant amounts of injected polymer from the oil field produced water may result in considerable savings in the operating costs of EOR applications. Further, one of ordinary skill in the art will recognize that this process may also be applied to light oil reservoirs or those reservoirs having mixed hydrocarbon viscosities for reasonable savings in operating costs.

Figure 1 :

Generally, embodiments of the present disclosure allow for polymer additives to be recovered from oil field produced water. Figure 1 shows a flow chart in accordance with one embodiment of the present disclosure. More specifically, Figure 1 shows a method for recovering a filtrate from the oil field produced water using a membrane. Initially, an injection fluid is prepared for injection into a formation (Step 100). As discussed above, injection fluids may be prepared depending on the properties of the formation into which they will be injected. Subterranean oil recovery operations may involve injection of an aqueous solution into the formation to help move oil through the formation and maintain pressure in the reservoir as fluids are removed. Generally, injection fluids may contain soluble salts such as sulfates and carbonates in addition to water. Additionally, injection fluids may contain various other components, such as, surfactants and/or polymer additives. In one embodiment of the present disclosure, at least one polymer additive may be used to prepare the injection fluid for injection into a formation. As discussed above, addition of polymer to the injection fluid may increase the viscosity of the injection fluid, which may aid in the displacement of high-viscosity oil from the formation.

Continuing with Figure 1 , once the initial injection fluid has been prepared for injection, the injection fluid may be injected into a formation (Step 102). In one embodiment of the present disclosure, the injection fluid may be injected into an injection well to push hydrocarbons in the formation toward a production well. The injection fluid may then be recovered from the formation in the form of produced water or fluid (Step 104). Step 104 may also include a separation step to separate produced aqueous fluids from other produced fluids such as crude oil and from produced gases, such as natural gas, carbon dioxide, and/or hydrogen sulfide.

As discussed above, the 'feed' or 'produced water' may contain, for example, any combination of water, brine, polymers, salts, sulfites, and any other additives or components contained in the initial injection fluid as well as additional components which may have combined with the fluid while in the reservoir or producing wellbore, including dissolved and dispersed crude oil components. In one embodiment of the present disclosure, the produced water may then be passed through a membrane (Step 106) to recover any of the above-mentioned components of the produced water or fluid in the form of a concentrate (Step 108).

Membranes of the present disclosure may include ultrafiltration (UF) and/or microfiltration (MF) membranes as well as other commercially available membranes suitable for concentrating filtrate from produced water or fluid. As used herein, 'microfiltration' means the filtration of particles suspended in solution, which are > 0.1 μm or 500,000 Daltons in size or weight. 'Ultrafiltration,' as used herein, means the filtration of particles suspended in solution, which are 0.01 to 0.1 μm or 1000 to 500,000 Daltons in size or weight. Selecting a membrane according to some embodiments of the present disclosure may include evaluating a variety of membranes on the sample material to determine the best membrane in terms of flux and/or permeate quality. As used herein, 'flux' is a measurement of the volume of fluid, which passes through the membrane during a certain time interval for a set area of membrane; 'average flux' is the time weighted average flux measured over a particular concentration range. Several membranes were chosen for study and are presented in Table 1 , below. Performance of the membranes from Table 1 is compared in Table 2, below. These membranes use vibratory shear enhanced process (VSEP), i.e., oscillating movement (at 50-60 Hz frequency) for shear enhanced separation. All these membranes are commercially available. Similar performance is expected even with conventional cross flow type micro- and ultra-filtration membranes without vibration.

Table 1. Membranes chosen for study.

^*GFD = Gallons of permeate produced per square foot of membrane per day.

Table 2. Relative performance of the membranes.

^*Flow rates are in ml_/min and are temperature corrected to 25^QC.

Once a suitable membrane has been selected, it may be necessary to determine what size and/or how many membranes are necessary for the desired filtration application. Using the actual average flux at the desired percent recovery, it may be possible to determine the amount of membrane area that will be necessary to process a desired flow rate. For example, the membrane area needed may be equal to the gallons per day divided by the actual average flux.

Given a Process Flow Rate of 2042 GPM, an Actual Average Flux of 34.1 GFD, and a Percent of Recovered Filtrate of 88.63%, the gallons per day may be determined using Equation 1 :

Gallons Per Day = Process Flow Rate ^* % Recovered Filtrate (Equation 1 )

The membrane area needed may then be determined by Equation 2:

Membrane Area = Gallons Per Day / Actual Average Flux

(Equation 2)

For the given examples, the Gallons per day = (2042 gal/min)^*(88.63%)^*(1440 min/day) = 2,606,147 GPD. The membrane area needed = (2,606,147 GPD)/(34.1 GFD)/(22/24 hr/day) = 83,375 square feet. Evaluating such data from actual laboratory testing and based on long term needs, it may be possible to determine the number of membrane units required as well as a safe degree of over-design. The exact amount of over-design may depend on the application; however, 20-40%, for example 30% may be used. Over-design may assist in extending the overall life of the equipment because the system will not be used at its maximum throughput limit. This may reduce the frequency of cleaning and replacement costs. Using the example data from above, the total membrane area needed for all units may be determined using Equation 3:

Total Membrane Area = Membrane Area + (Safety Factor ^* Membrane Area) (Equation 3)

The number of required membrane units may then be determined by Equation 4:

No. of Membrane Units = Total Membrane Area / Area per membrane unit (Equation 4)

For the given examples, the required total membrane area = 83,375 sq. ft. + (30% safety factor ^* 83,375 sq. ft.) = 109,500 square feet. Additionally, if each membrane unit has 1500 square feet, then the number of required membrane units = (109,500 sq. ft. / 1500 sq. ft. per unit) = 73 required membrane units.

In one embodiment, the membrane used to filter the produced water may include a microfiltration type membrane suitable for concentrating at least a portion of the polymer and separating it from at least a portion of the filtrate. In one embodiment, the microfiltration type membrane may have a pore size greater than or equal to about 0.1 μm or 500,000 Daltons. In one embodiment, the microfiltration type membrane may have a pore size of about 250,000 Daltons. In one embodiment, the membrane may be capable of concentrating polymer to about 11 volume percent of that present in the feed. In yet another embodiment, the membrane may be capable of concentrating polymer from about 1 ,800 ppm in the feed to about 11 ,500 ppm in the concentrate. In yet another embodiment, the membrane may be capable of concentrating polymer to an amount greater than about 11 ,000 ppm concentration. In another embodiment, the membrane may concentrate polymer to an amount greater than about 5,000 ppm concentration.

In another embodiment, the membrane may concentrate polymer in the concentrate to a level from about 3 to about 20 times greater than a level in the feed, for example from about 5 to about 15 times greater, or from about 8 to about 10 times greater.

Additionally, embodiments of the present disclosure may include subjecting the selected membrane to a vibratory shear process to induce shear and enhance separation while reducing fouling of the membrane which may occur when production water or fluid is passed through it. As used herein, 'fouling' means the accumulation of materials on the membrane surface or structure, which results in a decrease in flux.

Referring back to Figure 1 , once concentrate has been recovered from the membrane (Step 108), the concentrate may be tested (Step 110) to obtain information regarding, for example, its composition and/or concentration. Testing the recovered concentrate for such information is important, as the recovered concentrate may then be treated (Step 112), if necessary, for use in preparation of injection fluid for subsequent injections (Step 114). When necessary, treating the concentrate for re-use in injection fluid may include, for example, dilution or saturation of the concentrate, concentration and/or adjustment to the pH of the concentrate .

In one embodiment, the recovered concentrate may be at least one polymer additive initially added to the injection fluid prior to injection. Further, the polymer additive may have been used to increase the viscosity of the initial injection fluid such that upon injection the fluid may have viscosity comparable to or greater than the viscosity of the hydrocarbons to be displaced from the formation.

In another embodiment, dilution of the recovered concentrate may be necessary due to the concentrated nature of the recovered polymer. In yet another embodiment, the recovered concentrate may not require treatment prior to its collection and re-use in preparation of subsequent injection fluids.

Further, it may be desirable to clean the membrane before use and/or after filtration is complete in order to recover flux rates. In one embodiment of the present disclosure, the membrane may be flushed with warm water followed by at least one chemical cleaner. Such chemical cleaners may include, for example, an acidic cleaning solution with pH adjusted for optimal cleaning.

Generally, using polymer additives to increase the viscosity of the injection water allows for more efficient hydrocarbon recovery; however, due to its limited application in heavy oil environments, there exists a need for a more economically attractive mechanism to recover high viscosity hydrocarbons using polymer injection EOR techniques. Embodiments of the present disclosure may include one or more of the following advantages: a system that efficiently filters expensive polymer additives from production water, thus minimizing material and preparation costs; and allows for reuse of additives, thereby reducing environmental hazard associated with disposal of certain materials.

Illustrative Embodiments:

In one embodiment, there is disclosed a system for recovering hydrocarbons from a formation, comprising a first well in the formation to produce a mixture comprising one or more hydrocarbons and an aqueous solution; a separator to divide the mixture into one or more hydrocarbon streams and an aqueous solution stream; a membrane to separate the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; a second well in the formation to inject an aqueous polymer solution, wherein the aqueous polymer solution comprises at least a portion of the first stream. In some embodiments, the system also includes a storage vessel adapted to store the first stream prior to being injected. In some embodiments, the first well comprises a first group of 5 to 100 wells in the formation. In some embodiments, the second well comprises a second group of 5 to 100 wells in the formation. In some embodiments, the first well is adapted to produce the mixture for a first time period, and then inject the aqueous polymer solution for a second time period. In some embodiments, the second well is adapted to inject the aqueous polymer solution for a first time period, and then produce the mixture for a second time period. In some embodiments, the membrane comprises a polymer selected from the group consisting of polyethersulfone, polyvinylidene fluoride, and polyacrylonitrile. In some embodiments, the membrane comprises an average pore size from 20 to 800 nanometers. In some embodiments, the membrane comprises an average pore size from 50 to 600 nanometers. In some embodiments, the membrane comprises an average pore size from 200 to 500 nanometers.

In one embodiment, there is disclosed a method comprising producing a mixture comprising one or more hydrocarbons and an aqueous solution from a formation; separating the mixture into one or more hydrocarbon streams and an aqueous solution stream; separating the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; injecting an aqueous polymer solution into the formation, wherein the aqueous polymer solution comprises at least a portion of the first stream. In some embodiments, the separating the aqueous solution comprises filtering the aqueous solution. In some embodiments, the separating the aqueous solution comprises filtering the aqueous solution with a membrane. In some embodiments, the polymer increases a viscosity measurement of the aqueous polymer solution. In some embodiments, the polymer comprises a material selected from the group consisting of polyacrylamides, polyacrylate copolymers, xanthan gums, cellulosics, and mixtures thereof. In some embodiments, the polymer comprises a polyacrylamide.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

C L A I M S

1. A system for recovering hydrocarbons from a formation, comprising: a first well in the formation to produce a mixture comprising one or more hydrocarbons and an aqueous solution; a separator to divide the mixture into one or more hydrocarbon streams and an aqueous solution stream; a membrane to separate the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; a second well in the formation to inject an aqueous polymer solution, wherein the aqueous polymer solution comprises at least a portion of the first stream.

2. The system of claim 1 , further comprising a storage vessel adapted to store the first stream prior to being injected.

3. The system of one or more of claims 1 -2, wherein the first well comprises a first group of 5 to 100 wells in the formation.

4. The system of one or more of claims 1 -3, wherein the second well comprises a second group of 5 to 100 wells in the formation.

5. The system of one or more of claims 1-4, wherein the first well is adapted to produce the mixture for a first time period, and then inject the aqueous polymer solution for a second time period.

6. The system of one or more of claims 1 -5, wherein the second well is adapted to inject the aqueous polymer solution for a first time period, and then produce the mixture for a second time period.

7. The system of one or more of claims 1-6, wherein the membrane comprises a polymer selected from the group consisting of polyethersulfone, polyvinylidene fluoride, and polyacrylonitrile.

8. The system of one or more of claims 1-7, wherein the membrane comprises an average pore size from 20 to 800 nanometers.

9. The system of one or more of claims 1-8, wherein the membrane comprises an average pore size from 50 to 600 nanometers.

10. The system of one or more of claims 1 -9, wherein the membrane comprises an average pore size from 200 to 500 nanometers.

11. A method comprising: producing a mixture comprising one or more hydrocarbons and an aqueous solution from a formation; separating the mixture into one or more hydrocarbon streams and an aqueous solution stream; separating the aqueous solution into a first stream comprising a high concentration of polymer and a second stream comprising a low concentration of polymer; injecting an aqueous polymer solution into the formation, wherein the aqueous polymer solution comprises at least a portion of the first stream.

12. The method of claim 11 , wherein the separating the aqueous solution comprises filtering the aqueous solution.

13. The method of one or more of claims 11 -12 wherein the separating the aqueous solution comprises filtering the aqueous solution with a membrane.

14. The method of one or more of claims 11 -13 wherein the polymer increases a viscosity measurement of the aqueous polymer solution.

15. The method of one or more of claims 11 -14 wherein the polymer comprises a material selected from the group consisting of polyacrylamides, polyacrylate copolymers, xanthan gums, cellulosics, and mixtures thereof.

16. The method of one or more of claims 11 -15 wherein the polymer comprises a polyacrylamide.