WO2015034845A1

WO2015034845A1 - Prevention of petroleum reservoir souring by removal of phosphate from injected seawater

Info

Publication number: WO2015034845A1
Application number: PCT/US2014/053757
Authority: WO
Inventors: John MCELHINEY
Original assignee: Mcelhiney John
Priority date: 2013-09-03
Filing date: 2014-09-02
Publication date: 2015-03-12

Abstract

Disclosed herein are various embodiments for preventing reservoir souring caused by sulfate reducing bacteria. These bacteria reside in or are introduced into the reservoir during drilling or workover. The bacteria metabolize sulfates in seawater pumped into the reservoir to maintain pressure or waterflood the reservoir, generating hydrogen sulfide. This causes souring of the well, leading to corrosion of equipment and the need to treat the well to remove the hydrogen sulfide. Present methods of sulfate removal do not remedy the problem. The sulfate reducing bacteria require phosphorous as part of their life cycle. Removal of phosphorous, in the form of phosphates in the seawater, may be achieved using ferric iron nanoparticles as an absorbent, where the nanoparticles are encapsulated in a protein enzyme nanocage. Removal of the phosphorous from the injected water disrupts the life cycle of the sulfate reducing bacteria and thus prevents reservoir souring.

Description

Prevention of Petroleum Reservoir Souring by Removal of Phosphate from Injected Seawater

Cross Reference to Related Applications

[0001] This application claims the benefit under 35 USC § 1 19 (e) of U.S.

Provisional Patent Application No. 61 /873333 filed on September 3, 2013, the disclosure of which is incorporated herein by reference.

[0002]

Field

[0003] Various embodiments described herein relate to the field of treating water injection wells to reduce petroleum reservoir souring, and systems and methods associated therewith.

Background

[0004] It is common practice in the petroleum industry to inject a fluid into a

hydrocarbon reservoir in order to maintain the pressure within the reservoir or in "waterflood" secondary recovery methods. The fluid may be a liquid, such as water, or a gas such as carbon dioxide. For offshore operations, the obvious choice is seawater. It is readily available and requires no storage facilities. However, seawater contains various dissolved substances, some of which can have an impact on the reservoir or on the equipment used to produce the hydrocarbons from the reservoir.

[0005] One such problem is mineral scale formation. Where this has the potential to be a problem, one solution is desulfation of the seawater before it is injected into the well. For a description of this process, see K. Reyntjens, "Sulfate Removal - The Adoption of a Water Treatment Technology by the Oil and Gas Industry", Oil and Gas Facilities, October, 2012.

[0006] Another problem encountered when injecting seawater into wells is petroleum reservoir souring (hereinafter referred to simply as "souring"). See T.Y. Rizk, J.F. Stott, R.D. Eden, R.A. Davis, J.E. McElhiney, C. Di lorio, and J.A. Hardy, "The Effect of Desulphated Seawater Injection on Microbiological Hydrogen Sulfide Generation and Implication for Corrosion Control", NACE Paper 287, NACE International Meeting, San Diego, CA, 1998. In the following description the term "souring" is used to refer to biological reservoir souring, that is, souring caused by sulfate reducing bacteria (SRB) that reside in, or are inadvertently introduced into the reservoir by some type of contamination such as drilling or workover fluids. SRBs cause the souring process by metabolizing sulfate and lower molecular weight fatty acids (acetic, propionic, etc.,) in reservoir formation water to produce hydrogen sulfide. Therefore reducing sulfate in injected seawater will reduce, but not eliminate, the production of hydrogen sulfide.

[0007] Hydrogen sulfide is corrosive to metals, including many mechanical

components used in oil production such as wellbore tubulars, topsides separators, etc., and is fatal to human life. The prospect of souring usually occurs several years after seawater flooding begins, See Z. I. Khatib and J. R. Salinitro, "Reservoir Souring Analysis of Surveys and Experience in Sour Waterfloods", SPE 38795, SPE Annual Technical Conference and Exhibition, 5-8 October 1997, San Antonio, Texas. Often the mechanical components have already been installed with little, or no, protection against corrosion from hydrogen sulfide. Retrofitting is expensive, causing interruption of oil production. The cost of high chrome stainless steel materials that can withstand such corrosion are three to five times the cost of the original milder steels already installed. See B. Craig, "Materials for Deep Oil and Gas Well Construction", Advanced Materials and Processes, May 2008. Labor costs of offshore work are also high.

[0008] For many years desulfation of seawater injected into petroleum reservoirs to prevent mineral scale formation has been performed on a commercial scale. During that time it has not been widely appreciated that reduction of sulfate in injected seawater would also stoichiometrically reduce the potential for petroleum reservoir souring. What is desired are improved methods for the treatment of injected seawater in order to reduce the degree of souring, or preferably, totally prevent the souring.

Summary

[0009] In one embodiment there is provided a method for preventing souring of a hydrocarbon reservoir comprising lowering the concentration of phosphate in seawater injected into the reservoir.

[0010] Further embodiments are disclosed herein or will become apparent to those skilled in the art after having read and understood the specification and drawings hereof.

Brief Description of the Drawings

[0011] Different aspects of the various embodiments of the invention will become apparent from the following specification, drawings and claims in which :

[0012] Fig. 1 shows an example of a seawater desulfation process;

[0013] Fig. 2 shows a conceptual embodiment of a phosphate removal process before nanofiltration;

[0014] Fig. 3 shows a conceptual embodiment of a phosphate removal process after nanofiltration and

[0015] Fig. 4 shows a conceptual embodiment of a phosphate removal without nanofiltration.

[0016] The drawings are not to scale. Like numbers refer to like parts or steps throughout the drawings.

Definitions

[0017] In the following description, the words "absorber" and "absorbent" are used. It should be understood that these terms as used herein refer to the removal of a chemical or compound from a medium by a process of binding that chemical or compound to some substance or substances by one of several processes. These processes include absorption, adsorption, chemisorption, sorption, or any process which binds the chemical or compound and removes it from the medium. For the purposes of this description, no distinction is to be drawn between the chemical or compound being removed from the medium by being bound to the surface of the substance, entering into the bulk of the substance, chemically combining with the substance, or any combination of these. The use here of "absorber" and "absorbent" simply means that the chemical or compound is removed from the medium and retained within a module containing the chosen substance. The process involved may be described by the general term is sorption, which covers absorption, adsorption, and ion exchange.

Detailed Descriptions of Some Embodiments

[0019] Before proceeding with the detailed description, it is to be appreciated that the present teaching is by way of example only, not by limitation.

[0020] In the following description, specific details are provided to impart a thorough understanding of the various embodiments of the invention. Upon having read and understood the specification, claims and drawings hereof, however, those skilled in the art will understand that some embodiments of the invention may be practiced without hewing to some of the specific details set forth herein. Moreover, to avoid obscuring the invention, some well-known methods, processes and devices and systems finding application in the various embodiments described herein are not disclosed in detail.

[0021] Referring now to the drawings, embodiments of the present invention will be described. Several embodiments of the present invention are discussed below. The appended drawings illustrate only typical embodiments of the present invention and therefore are not to be considered limiting of its scope and breadth. In the drawings, some, but not all, possible embodiments are illustrated, and further may not be shown to scale.

[0022] One approach to the reduction or total prevention of biological reservoir souring was described in U.S. Patent No. 7,464,760 to McElhiney, entitled "Inhibiting Reservoir Souring Using Treated Injection Water", hereinafter "the 760 Patent", the disclosure of which is incorporated herein in its entirety. This patent describes the reduction of phosphate from seawater injected into the petroleum reservoir. It shows that bacteria require phosphate for their metabolism in their life cycle, and specifically in what is referred to as the adenosine triphosphate cycle. For a discussion of this cycle, see N. Birkeland, "Sulfate-Reducing Bacteria and Archaea", Chapter 3, Petroleum

Microbiology, pp. 35 - 54, B. Ollivier and M. Magot editors. The implementation of the processes described in the 760 Patent requires an efficient and cost-effective method for removal of the phosphate from seawater. In particular, the sulfate reducing bacteria use orthophosphate, and therefore removing this component from seawater would interrupt the life cycle of these bacteria, thus preventing the formation of the hydrogen sulfide which causes the souring.

[0023] In 2010 several publications suggested that there might be commercially available a material that could efficiently remove phosphates from seawater. That is, the materials described had the potential to reduce phosphates quickly, and to very low concentration levels, down to a few parts per billion (ppb) levels. For an example of these publications, see J. S. Vrouwenvelder, F. Beyer, K. Dahmani, N. Hasan, G.

Galjaard, J.C. Kruithof, and M.C.M. Van Loosdrecht, "Phosphate Limitation to Control Biofouling", Water Research 44 (2010), p. 3454-3466. This publication describes testing of phosphate limitation to control biofouling of spiral wound reverse osmosis membranes used to produce drinking water from seawater. In this publication, the discussion of the "proof of principle" of phosphate limitation describes findings similar to the literature cited in the 760 Patent. In particular, this publication discusses the use of thermostable ferritin. Ferritin is a ferric iron nanoparticle which is an absorbent for phosphate and other divalent cations and anions. The ferritin nanoparticle is

encapsulated in a protein enzyme nanocage. This publication and its references describe economics that are practical on a commercial scale. If the process is

affordable for large scale water treatment such as desalination, then it should also be commercially feasible in the petroleum industry.

[0024] The process of producing and regenerating ferritin is described in the

publication by J.F. Jacobs, M.N. Hasan, K. H. Paik, W.R. Hagan, M.C.M. Van

Loosdrecht, "Development of a Bionanotechnological Phosphate Removal System with Thermostable Ferritin", Biotechnology and Bioengineering, Vol. 105, No.5, April 1 , 2010, hereinafter the "Jacobs publication". This publication also describes the kinetics of the process and its dependency on temperature and phosphate concentrations. This publication discusses the use of ferritin as an absorbent, but other similar compounds may be used, as will be apparent to one of skill in the art after studying this description and the accompanying drawings. Ferritin is used here as an example of an absorbent which may be used in some embodiments in order to illustrate the process. [0025] For a description of processes used in removing ions from liquids, see European Patent No. 1 ,764,348 to M.N. Hasan et al., entitled "A Method for Removing Oxo-Anions and Metal Cations from a Liquid". This patent describes the process of removing contaminant concentrations of metal cations and oxo-anions so that the purified water contains contaminant concentrations less than that required by the World Health Organization, the United Nations and others. The technology is in use for preventing biofilms on the surfaces of reverse osmosis membranes utilized for the purification of seawater (desalination) to produce drinking water.

[0026] The embodiments described herein show a new use of the ferritin type of technology to remove phosphate from seawater to prevent petroleum reservoir souring by sulfate reducing bacteria. The embodiments are further contemplated as being used in conjunction with nanofiltration membranes and/or standalone. Nanofiltration

membranes referred to here are commonly used for desulfation of seawater to prevent/mitigate mineral scale (barium sulfate, strontium sulfate and calcium sulfate). The permeate (treated) water produced with nanofiltration membranes targets removal of divalent ions (sulfate, etc.) and is not fit for human consumption as it is too briny (approximately 30,700 TDS). See R.A. Davis and J.E. McElhiney, "The Advancement of Sulfate Removal from Seawater in Offshore Waterflood Operations", NACE Paper 2314, Corrosion 2002 Conference, San Diego, CA, March 2002.

[0027] The desulfation process is discussed in detail in publication, V.K. Vu, D.

Latapie, and R.A. Davis, "Barite Scale Prevention for Elf Angola's Girassol Field Using Sulfate Removal Technology", Eleventh Annual Deep Offshore Technology International Conference and Exhibition, Stavanger, NorwayCentre, 19-21 October 1999; therefore only a brief description is included herein. The related equipment is shown in Figure 1 . Seawater 100 is brought in to the process by lift pump 1 10 which has intake manifold 1 12 positioned deep enough below the surface of the water to avoid algae bloom.

Seawater 100 passes through back washable coarse filter 1 14 to remove debris.

Seawater 100 then passes through a prefiltration module comprising media filter 120. Media filter 120 was originally a sand or media filter, but modern practice employs a micro or ultra-filtration membrane module and associated pressurizing pump. For a detailed discussion of micro and ultra-filtration, see J.M. Walsh, "Micro- and Ultrafiltration Technologies Offer New Options for Offshore Waterflooding", Oil and Gas Facilities, April, 2013, p. 9-1 1 .

[0028] Seawater 100 is then processed through de-aeration module 130 driven by vacuum pumps 132, 134, to remove air from the water to reduce corrosion on downhole tubulars, etc. Prefiltration is performed on any seawater injection system, whether or not the embodiment incorporates nanofiltration membranes.

[0029] Following pre-filtration, which in some manner will accompany any seawater injection system with or without nanofiltration membranes, the pre-filtered, de-aerated seawater 100 enters reverse osmosis pressurizing pump 140, and thence into dual stage nanofiltration membrane system 160 and 162, via cartridge filter 150 which protects the membranes of nanofiltration membrane system 160, 162. The first stage 160 of dual stage nanofiltration membrane system 160, 162 produces a flow of treated water 164 of about 50% of the input volume. The remaining water passes through second stage 162 which again produces a flow of treated water 166 of about 50% of the input volume it receives, that is, 25% of the total seawater input. These two treated water streams 164, 166 therefore represent about 75% of the input seawater 100. The sulfate concentration is reduced from approximately 2800 mg/l to 40 mg/l in two stage array 160, 162. The nanofiltration membranes are spiral wound cartridges about four inches in diameter and forty inches long. Each cartridge has approximately 400 - 500 square feet of surface area depending upon the manufacturer.

[0030] Approximately twenty five percent of feed seawater 100, referred to as reject water 170, is dumped back into the sea. This water has a sulfate concentration approximately 1 1 ,000 mg/l in at its maximum concentration within the membrane system. The remaining 75% percent of feed seawater 100, referred to as permeate water 190, passes through downhole injection pump 180 that moves desulfated permeate water 190 downhole to the injection well sandface and thence into the oil reservoir itself.

[0031] In most embodiments hypochlorite from hypochlorite generator 105 is injected into the raw seawater 100 at lift pump 1 10 to kill seawater-borne bacteria. Excess hypochlorite is neutralized with sodium meta-bisulfite in de-aerator 130 in order to protect downstream nanofiltration membranes 162. Scale inhibitors are also introduced into the process in de-aeration module 130 to keep the high concentrations of sulfate in reject water 170 from precipitating while in nanofiltration membranes 162.

[0032] This technology for removing sulfates from seawater was first used in the early1990s in the North Sea on the Brae Alpha platform operated by Marathon Oil Company U. K. There are now over 50 such systems in operation worldwide. The principal objective of removal of sulfate from seawater has largely supplanted the previous technique of using mineral scale inhibitors. Reducing sulfate in seawater does mitigate reservoir souring by sulfate reducing bacteria, but it has not eliminated the problem. Embodiments of the present method described below discuss new technology which will eliminate reservoir souring altogether when used either with sulfate reduction membranes or in the alternative, as a standalone technology.

[0033] There are several possible methods for phosphate removal by ferritin or related compounds. One embodiment, used in conjunction with nanofiltration membranes is shown in Fig. 2. This is referred to as the Upstream Phosphate Removal method, because the phosphate removal is performed before the nanofiltration process to remove sulfates. In Fig. 2, seawater 100 is introduced into the system by lift pump 1 10 and passed through back washable coarse filter 1 14 to remove debris. Seawater 100 is then pumped through media filter or ultra-filtration membrane 120 by pressurizing pump 222. The filtered seawater then passes into de-aeration module 130, from whence it flows to phosphate removal module 240. Phosphate removal module 240 comprises a packed bed or column of ferritin or similar compound. The treated seawater then is pumped by reverse osmosis pressurizing pump 140 into dual stage nanofiltration membrane system 160 and 162, via cartridge filter 1 50 which protects the membranes of nanofiltration membrane system 160, 162. As previously described, the sulfate-laden reject water 170 is pumped back into the sea and the treated permeate water 290, with very low levels of phosphates and sulfates, is pumped into the well by injection pump 180. [0034] Referring now to Fig. 3, in an alternative embodiment, the phosphate removal step follows the desulfation. This embodiment is referred to as the Downstream

Phosphate removal method. In Fig. 3, seawater 100 is introduced into the system by lift pump 1 10 and passed through back washable coarse filter 1 14 to remove debris.

Seawater 100 is then pumped through media filter or ultra-filtration membrane 120 by pressurizing pump 222. The filtered seawater then passes into de-aeration module 130. It then is pumped by reverse osmosis pressurizing pump 140 into nanofiltration membrane system 160 via cartridge filter 150 which protects the membranes of nanofiltration membrane system 160, 162. Sulfate-laden reject water 170 is pumped back into the sea. Desulfated permeate water 368 then flows to phosphate removal module 340. Phosphate removal module 340 comprises a packed bed or column of ferritin or similar compound. The treated permeate water 390, with very low levels of phosphates and sulfates, is pumped into the well by injection pump 180.

[0035] In the Upstream Phosphate Removal embodiment, the ferritin absorber will be exposed to the full concentration of phosphate in seawater, whereas in the Downstream Phosphate Removal embodiment the ferritin absorber will have the benefit from whatever amount of phosphate removal is provided by the nanofiltration membranes. As described above, dual stage nanofiltration membranes have a yield of about 75% so in the Upstream Phosphate Removal embodiment, approximately one-third more volume of seawater will require treatment than in the Downstream Phosphate Removal embodiment. In either embodiment, the ferritin absorbent will eventually become fully saturated with phosphate and have to be regenerated or disposed of. In both

embodiments, nanoparticles of ferritin will be fixed in the bed or column by an adhesive to sand or to some other suitable packing, such as a resin. The use of packed beds or columns in the oil, gas and chemical industries is well known. Normal practice, such as avoidance of high space velocities, that will lift the bed or column and create channels, must be followed in order to prevent short circuiting of seawater through the bed or column; otherwise uniform treatment will not occur.

[0036] In both the Upstream and Downstream embodiments there may be an active ferritin absorber and an absorber undergoing regeneration; these will be alternated to make sure that each active bed or column has remaining absorbent capacity. Analytical measurement of phosphate in the effluent, coupled with operating experience, will indicate when the beds or columns must be switched. Phosphate analyzer tools are readily commercially available. In alternative embodiments, the switching may be made automatic with sensors and valves. Waste from the regenerator may be disposed of into the sea as all constituents are environmentally harmless. In the Upstream

Phosphate Removal embodiment a hypochlorite generator is likely not needed, but a hypochlorite generator will likely be required in the Downstream Phosphate Removal embodiment, along with an associated reducing agent to neutralize the excess hypochlorite.

[0037] In other embodiments, one bed or column of absorbent may be taken off-line, and the ferritin, fully loaded with phosphate, can be discarded and the bed or column reloaded with fresh ferritin and packing. In this case, a regenerator is not required. A discussion of economics from various industry sources suggests that there may not be much economic incentive in regeneration.

[0038] Yet another alternative embodiment is possible, as shown in Fig. 4. Ferritin nanoparticles are fed to an injection module via an eductor or similar mechanical module 410 that will wet, solubilize, and inject the nanoparticles into microfiltered and de-aerated seawater 400, and the entire solution 420 is injected into the reservoir by injection pump 180. Wetting chemicals may be required, and the ferritin may be attached to micrograins of sand or other transport media. In this case, no nanofiltration membranes will be necessary at all. Seawater pre-treatment will be required simply to prefilter the seawater and rid it of debris, algae bloom, etc., using back washable coarse filter 1 14, media filter or ultrafiltration filter 120 and de-aeration module 130.

[0039] Many studies of nanoparticle transport in porous media have been reported in the petroleum literature. See for example J. Yu, C. An, D. Mo, N. Liu, and R. Lee, "Study of adsorption and Transportation Behavior of Nanoparticles in Three Different Porous Media", Document ID 153337-MS, SPE Improved Oil Recovery Symposium, April 14-18, 2012, Tulsa, Oklahoma. See also F. Caldelas, M.J. Murphy, C. Huh, and S. L. Bryant, "Factors Governing Distance of Nanoparticle Propagation in Porous Media", Document ID 142305-MS, SPE Production and Operations Symposium, March 27-29, 201 1 , Oklahoma City, OK. Typically nanoparticles will flow long distances through permeability channels in the reservoir rock with small losses due to adsorption in some cases. In these embodiments described above the seawater with the nanoparticles will be treated while being injected into the petroleum reservoir. Since sulfate reducing bacteria often migrate towards the injection wells for their nourishment, the biofilm formed on the rock matrix in the near vicinity of the injection wellbore will be deprived of phosphate by the injected nanoparticles and thus rendered inactive. See E. Sunde and T. Torvik, "Microbial Control of Hydrogen Sulfide Production in Oil Reservoirs", Chapter 10, Petroleum Microbiology, pp. 201 - 214, B. Ollivier and M. Magot, editors.

[0040] Ortho-phosphate (simply referred to herein as phosphate) concentrations in seawater vary but are in the range of 100 - 200 ppb in seawater depending on depth, location and temperature. See H.E. Garcia, R.A. Locarnini, T. P. Boyer, J.I. Antonov, M.M. Zweng, O.K. Baranova, and D.R. Johnson, 2010. World Ocean Atlas Volume 2009, Volume 4: Nutrients (phosphate, nitrate, and silicate). S. Levitus, Ed., NOAA Atlas NESDIS 71 , U.S. Government Printing Office, Washington, D.C., 398 pp. Some authors refer to soluble reactive phosphorous (SRP) instead which is primarily orthophosphate. See for example C. R. Benitez-Nelson, "The Biogeochemical Cycling of Phosphorous in Marine Waters", Earth-Science Reviews 51 (2000) p 109-135.

[0041] The broad claims of the 760 Patent state that removal of phosphorous to within the range of 0-30 ppb is required to prevent reservoir souring. Data for phosphate reduction from nanofiltration membranes is not published to date but anecdotal evidence from laboratory testing has shown that the concentration of phosphate in permeate water is not low enough to prevent reservoir souring. Reservoir souring after several years of injecting seawater which has been desulfated by using nanofiltration membranes is reported in publication, K. Robinson, W. Ginty, E. Samuelson, T.

Lundgaard and T.L. Skovhus, "Reservoir Souring in a Field with Sulphate Removal: A Case Study", SPE 132697, SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September, 2010. Published data show that limitation of phosphorous concentrations below 3 ppb (the equivalent of approximately 10 ppb of phosphate) clearly limit bacterial growth. See for example the Jacobs publication, and see also A. Sathasivan and S. Ohghaki, "Application of New Bacterial Regrowth Potential Method for Water Distribution System - A Clear Evidence of Phosphorous Limitation", Water Research, Vol. 33, No. 1 , pp 137-144, 1999.

[0042] The above embodiments refer to the use of ferritin to remove phosphate from seawater. Ferritin is used as example to illustrate some possible embodiments. It will be apparent to one of ordinary skill in the art after reading this description and studying the drawings that other compounds having similar physical and chemical properties may be used in place of ferritin. The use of ferritin as an example should not be construed to imply that ferritin is the only compound which may be used to implement the methods described herein.

[0043] It is noted that many of the structures, materials, and acts recited herein can be recited as means for performing a function or step for performing a function. Therefore, it should be understood that such language is entitled to cover all such structures, materials, or acts disclosed within this specification and their equivalents, including any matter incorporated by reference.

[0044] It is thought that the apparatuses and methods of embodiments described herein will be understood from this specification. While the above description is a complete description of specific embodiments, the above description should not be taken as limiting the scope of the patent as defined by the claims.

[0045] Other aspects, advantages, and modifications will be apparent to those of ordinary skill in the art to which the claims pertain. The elements and use of the above- described embodiments can be rearranged and combined in manners other than specifically described above, with any and all permutations within the scope of the disclosure.

[0046] Although the above description includes many specific examples, they should not be construed as limiting the scope of the method, but rather as merely providing illustrations of some of the many possible embodiments of this method. The scope of the method should be determined by the appended claims and their legal equivalents, and not by the examples given.

Claims

Claims WHAT IS CLAIMED IS:

1 . A method for preventing souring of a hydrocarbon reservoir comprising lowering the concentration of phosphate in seawater injected into the reservoir.

2. The method of claim 1 further comprising the removal of phosphate by treating the seawater injected into the reservoir with an absorbent.

3. The method of claim 2 wherein the absorbent is a ferric iron nanoparticle.

4. The method of claim 2 wherein the absorbent is encapsulated in a protein enzyme nanocage.

5. The method of claim 2 wherein the absorbent is ferritin.

6. The method of claim 2 wherein the absorbent is in the form of a packed bed or column in which absorbent nanoparticles are attached to a packing material with an adhesive.

7. The method of claim 6 wherein the packing material is sand grains.

8. The method of claim 6 wherein the packing material is a resin

9. The method of claim 2 wherein the absorbent is used with pre-filtration and de- aeration modules and a nanofiltration membrane module for removal of sulfate ions to prevent mineral scale.

10. The method of claim 9 wherein the absorbent is positioned after the pre-filtration and de-aeration modules and ahead of the nanofiltration membrane module.

1 1 . The method of claim 9 wherein the absorbent is positioned after the pre-filtration and de-aeration modules and ahead of the nanofiltration membrane module.

12. The method of claim 2 wherein the absorbent is used with pre-filtration and de- aeration modules and without an associated nanofiltration membrane module for removal of sulfate ions.

13. The method of claim 2 wherein the absorbent is contained within an absorbent module housing.

14. The method of claim 13 wherein the absorbent contained within an absorbent module housing is regenerated when the absorbent is close to saturation with absorbed phosphate ions.

15. The method of claim 13 wherein the absorbent contained within an absorbent module housing is replaced when the absorbent is close to saturation with absorbed phosphate ions.

16. The method of claim 2 wherein the seawater is treated by absorbent injected directly into the seawater after pre-filtration and de-aeration, and the treated seawater is injected into the reservoir.

17. The method of claim 2 wherein the seawater is treated by absorbent injected directly into the seawater after pre-filtration, de-aeration and nanofiltration, and the treated seawater is injected into the reservoir.