Water treatment method for heavy oil production using calcium sulfate seed slurry evaporation Number:7,438,129 from the United States Patent and Trademark Office (PTO) owispatent

Title: Water treatment method for heavy oil production using calcium sulfate seed slurry evaporation

Abstract: A process for treating produced water to generate high pressure steam. Produced water from heavy oil recovery operations is treated by first removing oil and grease. Feedwater is then acidified and steam stripped to remove alkalinity and dissolved non-condensable gases. Pretreated produced water is then fed to an evaporator. Up to 95% or more of the pretreated produced water stream is evaporated to produce (1) a distillate having a trace amount of residual solutes therein, and (2) evaporator blowdown containing substantially all solutes from the produced water feed. The distillate may be directly used, or polished to remove the trace residual solutes before being fed to a steam generator. Steam generation in a packaged boiler, such as a water tube boiler having a steam drum and a mud drum with water cooled combustion chamber walls, produces 100% quality high pressure steam for down-hole use.

Patent Number: 7,438,129 Issued on 10/21/2008 to Heins

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Inventors:	Heins; William F. (Redmond, WA)
Assignee:	GE Ionics, Inc. (Watertown, MA)
Appl. No.:	11/149,072
Filed:	June 8, 2005

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Related U.S. Patent Documents

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	Application Number	Filing Date	Patent Number	Issue Date
	10868745	Jun., 2004	7150320
	10307250	Nov., 2002	7077201
	09566622	May., 2000	6733636
	60133172	May., 1999
	60578810	Jun., 2004

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Current U.S. Class:	166/266 ; 159/24.1; 159/45; 159/47.1; 159/901; 166/267; 166/272.3; 166/303; 203/10; 203/26; 203/48; 203/98; 203/DIG.16; 210/664; 210/669; 210/747; 210/805; 210/806; 405/129.35; 588/250
Current International Class:	E21B 43/24 (20060101); B01D 1/28 (20060101); E21B 43/40 (20060101); B01D 3/42 (20060101); C02F 1/04 (20060101); C02F 9/00 (20060101)
Field of Search:	166/75.15,266,267,272.3,272.6,272.7,302,303 159/24.1,45,47.1,901 203/10,26,48,98,DIG.16 210/664,669,747,805,806 405/129.35 588/250

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Primary Examiner: Suchfield; George
Attorney, Agent or Firm: Goodloe, Jr.; R. Reams

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Parent Case Text

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RELATED PATENT APPLICATIONS

This application is a Continuation-In-Part of prior U.S. patent application Ser. No. 10/868,745, filed Jun. 9, 2004, now U.S. Pat. No. 7,150,320 which was a Continuation-In-Part of prior U.S. patent application Ser. No. 10/307,250, filed Nov. 30, 2002, now U.S. Pat. No. 7,077,201 which was a Continuation-In-Part of prior U.S. patent application Ser. No. 09/566,622, filed May 8, 2000, now U.S. Pat. No. 6,733,636B1 issued May 11, 2004, entitled WATER TREATMENT METHOD FOR HEAVY OIL PRODUCTION, which claimed priority from prior U.S. Provisional Patent Application Ser. No. 60/133,172, filed on May 7, 1999. Also, this application claims priority from U.S. Provisional Patent Application Ser. No. 60/578,810, filed Jun. 9, 2004. The disclosures of each of the above identified patents or patent applications are incorporated herein in their entirety by this reference, including the specification, drawing, and claims of each patent or application.

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Claims

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The invention claimed is:

1. A process for producing steam for downhole injection in the recovery of heavy oil, said process comprising: (a) providing an oil/water mixture gathered from an oil/water collection well; (b) separating oil from said oil/water mixture to provide an oil product and a produced water product containing oil therein; (c) de-oiling said oil containing produced water product to at least partially provide an evaporator feedwater stream, said evaporator feedwater stream comprising water, dissolved gases, and dissolved solutes, said dissolved solutes comprising calcium, sulfate, and silica; (d) providing an evaporator having a plurality of heat transfer elements, a liquid containing sump reservoir, and a recirculating pump to recycle a concentrated brine form said sump reservoir to said plurality of heat transfer elements; (e) acidifying said feedwater to convert alkalinity to carbon dioxide, and steam stripping said carbon dioxide and said dissolved gases from said evaporator feedwater stream; (f) injecting said evaporator feedwater stream into said evaporator and evaporating a portion of said feedwater stream to produce said concentrated brine; (g) recirculating said concentrated brine in said evaporator, said concentrated brine comprising a slurry comprising water, dissolved solutes, calcium sulfate, and silica crystals; (h) distributing said concentrated brine on a first surface of at least one of said plurality of heat transfer elements to generate a steam vapor; (i) compressing said steam vapor to produce a compressed steam vapor; (j) directing said compressed steam vapor to a second surface of at least one of said plurality of heat transfer elements to condense said compressed steam vapor and to form a distillate; (k) collecting said distillate; (l) discharging at least some of said concentrated brine as an evaporator blowdown stream; (m) introducing said distillate stream into a steam generator, to produce (i) high pressure steam, and (ii) a boiler blowdown stream, said boiler blowdown stream comprising water and residual dissolved solids; (n) injecting said high pressure steam in an injection wells to fluidize oil present in a selected geological formation, to produce an oil and water mixture; (o) gathering said oil/water mixture.

2. The process as set forth in claim 1, wherein said distillate comprises residual solutes, further comprising the step of removing residual solutes from said distillate stream to produce a substantially solute free distillate.

3. The process as set forth in claim 2, wherein said residual solutes in said distillate comprise non-volatile total organic carbon constituents.

4. The process as set forth in claim 2, wherein said residual solutes in said distillate comprise hardness.

5. The process as set forth in claim 2, further comprising cooling said distillate prior to removal of said residual solutes.

6. The process as set forth in claim 5, wherein said method further comprises heating said substantially solute free distillate before introducing said stream into said steam generator.

7. The process as set forth in claim 2, wherein said residual solutes in said distillate are removed via ion exchange treatment.

8. The process as set forth in claim 7, further comprising regenrating said ion exchange resin to generate an ion exchange regenerant stream, and still further comprising returning said ion exchange regenerant stream to said evaporator feedwater stream pior to injecting said evaporator feedwater stream into said evaporator.

9. The process as set forth in claim 2, wherein said residual solutes are removed via membrane separation, wherein a solute contaning membrane rejected stream is produced.

10. The process as set forth in claim 9, wherin said membrane separation method comprises reverse osmosis.

11. The process as set forth in claim 2, wherein said membrane separation method comprises electrodeionization.

12. The process as set forth in claim 11, wherein after adding said boiler blowdown stream, said evaporator feedwater stream is heated.

13. The process as set forth in claim 1, further comprising removing said residual solutes from said distillate in an electrodeionization treatment unit to produce (a) a substantially solute free boiler feedwater and (2) a solute containg electrodeionization reject stream.

14. The process as set forth in claim 13, further comprising, before injecting said evaporator feedwater stream into said evaporator, directing said electrodeionization reject stream to said evaporator feedwater stream.

15. The process as set forth in claim 1, wherein said process further comprises adding said boiler blowdown stream to said evaporator feedwater stream.

16. The process as set forth in claim 1, wherein said boiler blowdown is directly injected into said sump reservoir.

17. The process as set forth in claim 1, wherein said boiler blowdown stream is injected into said concentrated brine at a location upstream of said recirculation pump.

18. The process as set forth in claim 1, wherein said evaporator feedwater further comprises dissolved gases,and wherein said process further comprises heating said evaporator feedwater to remove at least some of said dissolved gases from said evaporator feedwater, prior to injection of said evaporator feedwater stream into said evaporator.

19. The process as set forth in claim 1, wherein the pH of the concentrated brine is maintained at a pH of at least 7.5 by adding a selected base to said sump reservoir.

20. The process as set forth in claim 19, wherein said selected base comprises sodium hydroxide.

21. The process as set forth in claim 1, wherein said evaporator further comprises a feed tank, and wherein the pH of the concentrated brine is raised to a pH of at least 8.5 by adding a selected base to said sump reservoir.

22. The process as set forth in claim 1, wherein the pH of the concentratde brine is raised to a pH of at least 7.5 by injection of a selected base into said recirculating brine.

23. The process as set forth in claim 1, wherein the pH of the concentrated brine is raised to a ph of at least 8.5 by injection of a selected base into said concentrated brine.

24. The process as set forth in claim 23, wherein said selected base is injected into said concentrated brine prior to said recirculating pump.

25. The process as set forth in claim 1, wherein said evaporator comprises a falling-film type evaporator.

26. The process as set forth in claim 25, wherein said heat transfer elements comprise tubular heat transfer elements having an interior surface and an exterior surface.

27. The process as set forth in claim 25, wherein said evaporator comprises a mechanical vapor recompression evaporator.

28. The process as set forth in claim 1, wherein said evaporator comprises a forcedcirculation type evaporator.

29. The process as set forth in claim 28, wherein said heat transfer elements comprise tubular elements having an interior surface and an exterior surface.

30. The process as set forth in claim 29, wherein said evaporator feedwater stream is concentrated at the interior surface of said tubular heat transfer elements.

31. The process as set forth in claim 28, wherein said evaporator comprises a mechanical vapor recompression evaporator.

32. The process as set forth in claim 1, further comprising treating said evaporator blowdown stream in a crystallizer.

33. The process as set forth in claim 1, further comprising treating said evaporator blowdown stream in a dryer.

34. The process as se torth in claim 1, further comprising removing oil from said evaporator feedwater stream to a selected oil concentration before injecting said evaporator feedwater stream into said evaporator.

35. The process as set forth in claim 34, wherein the selected concentration of oil in said evaporator feedwater stream comprises less than about twenty parts per million.

36. The process as set forth in claim 1, wherein said steam generator comprises a packaged boiler.

37. The process as set forth in claim 36, wherein said packaged boiler cimprises a water tube boiler.

38. The process as set forth in claim 1, wherein said steam generator comprises a once-through steam generator, said once-through steam generator producing said high pressure steam stream and said boiler blowdown stream.

39. The process as set forth in claim 38, further comprising separating said high pressure steam stream and said boiler blowdown stream to produce a steam stream having substantially 100% steam quality.

40. The process as set forth in claim 39, wherein said substantially 100% steam quality steam is injected into said injection wells.

41. The process as set forth in claim 39, wherein said boiler blowdown stream is flashed at least once to produce a still further concentrated boiler blowdown stream comprising water and residual dissolved solutes.

42. The process as set forth in claim 41, further comprising adding said residual liquid stream containing dissolved solutes to said evaporator feedwater stream.

43. A process for producing steam for downhole injection in the recovery of heavy oil, said process comprising: (a) providing an oil/water mixture gathered from an oil/water collection well; (b) separating oil from said oil/water mixture to provide an oil product and a produced water product containing oil therein; (c) pretreating said produced water product, said pretreating comprising de-oiling said oil containing produced water product to at least partially provide a feedwater stream, said feedwater stream comprising water, dissolved gases, said dissolved gases comprising alkalinity, and dissolved solutes, said dissolved solutes comprising silica; (d) providing an evaporator having a plurality of heat transfer elements, a liquid containing sump reservoir, and a recirculating pump to recycle a concentrated brine from said sump reservoir to said plurality of heat transfer elements; (e) acidifying said feedwater stream to convert said alkalinity to carbon dioxide and then steam stripping said carbon dioxide from said feedwater stream; (f) recirculating said concentrated brine; (g) adding said feedwater stream to said concentrated brine before directing said concentrated brine to which said feedwater stream has been added to said plurality of heat transfer elements; (h) distributing said concentrated brine on a first surface of at least one of said plurality of heat transfer elements to generate a steam vapor; (i) compressing said steam vapor to produce a compressed steam vapor; (j) directing said compressed steam vapor to a second surface of at least one of said plurality of heat transfer elements to condense said compressed steam vapor and to form a distillate; (k) collecting said distillate; (l) discharging at least some of said concentrated brine as an evaporator blowdown stream; (m) introducing said distillate into a steam generator, to produce (i) high pressure steam, (ii) a boiler blowdown stream, said boiler blowdown stream comprising water and residual dissolved solids; (n) injecting said high pressure steam in injection wells to fluidize oil present in a selected geological formation, to produce an oil and water mixture; (o) gathering said oil/water mixture.

44. The process as set forth in claim 43, wherein said distillate comprises residual solutes, further comprising removing residual solutes from said distillate to produce a substantially solute free distillate.

45. The processas set forth in claim 44, further comprising cooling said distillate prior to removal of said residual solutes.

46. The process as set forth in claim 45, wherein said method further comprises heating said substantially solute free distillate before introducing said substantially solute free distillate into said steam generator.

47. The process as set forth in claim 43, wherein said process further comprises adding said boiler blowdown stream to said feedwater stream.

48. The process as set forth in claim 47, wherein, after adding said boiler blowdown stream, said evaporator feedwater stream is heated.

49. The process as set forth in claim 43, wherein said boiler blowdown stream is directly injected into said sump reservoir.

50. The process as set forth in claim 43, wherein said boiler blowdown stream is injected into said concentrated brine at a location upstream of said recirculation pump.

51. The process as set forth in claim 43, wherein the pH of the concentrated brine is maintained at a pH of at least 8.5.

52. The process as set forth in claim 51, wherein the pH of she concentrated brine is maintained at a pH of at least 8.5 by injection of hydroxide ions to said concentrated brine.

53. The process as set forth in claim 52, wherein said hydroxide ions are injected into said concentrated brine before said recirculating pump.

54. The process as set forth in claim 43, wherein the pH of thee concentrated brine is maintained as a pH of ac least 8.5 by injection of said hydroxide ions to said sump reservoir.

55. The process as set forth in claim 43, wherein said evaporator comprises a falling-film type evaporator.

56. The process as set forth in claim 43, wherein said evaporator comprises a forced-circulation type evaporator.

57. The process as set forth in claim 43, further comprising treating said evaporator blowdown stream in a crystallizer.

58. The process as set forch in claim 43, further comprising treating said evaporator blowdown stream in a dryer.

59. The process as set forth in claim 43, wherein said steam generator comprises a packaged boiler.

60. The process as set forth in claim 43, wherein said steam generator comprises a once-through steam generator, said once-through steam generator producing said high pressure steam stream arid said boiler blowdown stream.

61. The process as set forth in claim 60, further comprising separating said high pressure steam stream and said boiler blowdown stream to produce a high pressure steam stream having substantially 100% steam quality.

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Description

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COPYRIGHT RIGHTS IN THE DRAWING

A portion of the disclosure of this patent document contains material that is subject to copyright protection. The applicant no objection to the facsimile reproduction by anyone of the patent document or the patent disclosure, as it appears in the Patent and Trademark Office patent file or records, but otherwise reserves all copyright rights whatsoever.

TECHNICAL FIELD

The invention disclosed and claimed herein relates to treatment of water to be used for steam generation in operations which utilize steam to recover oil from geological formations. More specifically, this invention relates to novel, improved techniques for efficiently and reliably generating from oil field produced waters, in high pressure steam generators, the necessary steam for down-hole use in heavy oil recovery operations.

BACKGROUND

Steam generation is necessary in heavy oil recovery operations. This is because in order to recover heavy oil from certain geologic formations, steam is required to increase the mobility of the sought after oil within the formation. In prior art systems, oil producers have often utilized once-through type steam generators ("OTSG's). As generally utilized in the industry, once through steam generators --OTSG's --usually have high blowdown rates, often in the range of from about 20% to about 30% or thereabouts. Such a blowdown rate leads to significant thermal and chemical treatment inefficiencies. Also, once through steam generators are most commonly provided in a configuration and with process parameters so that steam is generated from a feedwater in a single-pass operation through boiler tubes that are heated by gas or oil burners. Typically, such once through steam generators operate at from about 1000 pounds per square inch gauge (psig) to about 1600 psig or so. In some cases, once through steam generators are operated at up to as much as about 1800 psig. Such OTSG's often operate with a feedwater that has from about 2000 mg/L to about 8000 mg/L of total dissolved solids. As noted in FIG. 1, which depicts the process flow sheet of a typical prior art water treatment system 10, such a once through steam generator 12 provides a low quality or wet steam, wherein about eighty percent (80%) quality steam is produced. In other words, the 80% quality steam 14 is about 80% vapor, and about 20% liquid, by weight percent. The steam portion, or high pressure steam produced in the steam generators is injected via steam injection wells 16 to fluidize as indicated by reference arrows 18, along or in combination with other injectants, the heavy oil formation 20, such as oils in tar sands formations. The injected steam 14 eventually condenses and an oil/water mixture 22 results, and which mixture migrates through the formation 20 as indicated by reference arrows 24. The oil/water mixture 22 is gathered as indicated by reference arrows 26 by oil/water gathering wells 30, through which the oil/water mixture is pumped to the surface. Then, the sought-after oil is sent to an oil/water separator 32 in which the oil product 34 separated from the water 35 and recovered for sale. The produced water stream 36, after separation from the oil, is further de-oiled in a de-oiling process step 40, normally by addition of a de-oiling polymer 42 or by other appropriate processes. Such a de-oiling process usually results in generation of an undesirable waste oil/solids sludge 44. However, the de-oiled produced water stream 46 is then further treated for reuse.

The design and operation of the water treatment plant which treats the de-oiled produced water stream 46, i.e., downstream of the de-oiling unit 40 and upstream of injection well 16 inlet 48, is the key to the improvement(s) described herein.

Most commonly in prior art plants such as plant 10, the water is sent to the "once-through" steam generators 12 for creation of more steam 14 for oil recovery operations. The treated produced water stream 12F which is the feed stream for the once through steam generator, at time of feed to the steam generator 12, is typically required to have less than about 8000 parts per million ("PPM") of total dissolved solids ("TDS"). Less frequently, the treated produced water stream 12F may have up to about 12000 parts per million (as CaCO3 equivalent) of total dissolved solids, as noted in FIG. 8. Further, it is often necessary to meet other specific water treatment parameters before the water can be reused in such once-through steam generators 12 for the generation of high pressure steam.

In most prior art water treatment schemes, the de-olled recovered water 46 must be treated in a costly water treatment plant sub-system 10 before it can be sent to the steam generators 12. Treatment of water before feed to the once-through steam generators 12 is often initially accomplished by using a warm lime softener 50, which removes hardness, and which also removes some silica from the de-oiled produced water feedstream 46. Various softening chemicals 52 are usually necessary, such as lime, flocculating polymer, and perhaps soda ash. Underflow 56 produces a waste sludge 58 which must be further handled and disposed. Then, an "after-filter" 60 is often utilized on the clarate stream 59 to prevent carry-over of any precipitate or other suspended solids, which substances are thus accumulated in a filtrate waste stream 62. For polishing, an ion exchange step 64, normally including a hardness removal step such as a weak acid cation (WAC) ion-exchange system that can be utilized to simultaneously remove hardness and the alkalinity associated with the hardness, is utilized. The ion exchange systems 64 require regeneration chemicals 66 as is well understood by those of ordinary skill in the art and to which this disclosure is directed. As an example, however, a WAG ion exchange system is usually regenerated with hydrochloric acid and caustic, resulting in the creation of a regeneration waste stream 68. Overall, such prior art water treatment plants are relatively simple, but, result in a multitude of liquid waste streams or solid waste sludges that must be further handled, with significant additional expense.

In one relatively new heavy oil recovery process, known as the steam assisted gravity drainage heavy oil recovery process (the "SAGD" process), it is preferred that one hundred percent (100%) quality steam be provided for injection into wells (i.e., no liquid water is to be provided with the steam to be injected into the formation). Such a typical prior art system 11 is depicted in FIG. 2. However, given conventional prior art water treatment techniques as just discussed in connection with FIG. 1, the 100% steam quality requirement presents a problem for the use of once through steam generators 12 in such a process. That is because in order to produce 100% quality steam 70 using a once-through type steam generator 12, a vapor-liquid separator 72 is required to separate the liquid water from the steam. Then, the liquid blowdown 73 recovered from the separator is typically flashed several times in a series of flash tanks F.sub.1, F.sub.2, etc. through F.sub.N (where N is a positive integer equal to the number of flash tanks) to successively recover as series of lower pressure steam flows S.sub.1, S.sub.2, etc. which may sometimes be utilized for other plant heating purposes. After the last flashing stage F.sub.N, a residual hot water final blowdown stream 74 must then be handled, by recycle and/or disposal. The 100% quality steam is then sent down the injection well 16 and injected into the desired formation 20. Fundamentally, though, conventional treatment processes for produced water used to generate steam in a once-through steam generator produces a boiler blowdown which is roughly twenty percent (20%) of the feedwater volume. This results in a waste brine stream that is about fivefold the concentration of the steam generator feedwater. Such waste brine stream must be disposed of by deep well injection, or if there is limited or no deep well capacity, by further concentrating the waste brine in a crystallizer or similar system which produces a dry solid for disposal.

As depicted in FIG. 3, another method which has been proposed for generating the required 100% quality steam for use in the steam assisted gravity drainage process involves the use of boilers 80, which may be packaged, factory built boilers of various types or field assembled boilers with mud and steam drums and water wall piping. Various methods can be used for producing water of a sufficient quality to be utilized as feedwater 80F to a boiler 80. One method which has been developed for use in heavy oil recovery operations involves de-oiling 40 of the produced water 36, followed by a series of physical-chemical treatment steps. Such treatment steps normally include a series of unit operations as warm lime softening 54, followed by filtration 60 for removal of residual particulates, then an organic trap 84 (normally non-ionic ion exchange resin) for removal of residual organics. The organic trap 84 may require a regenerant chemical supply 85, and, in any case, produces a waste 86, such as a regenerant waste. Then, a pre-coat filter 88 can be used, which has a precoat filtrate waste 89. In one alternate embodiment, an ultrafiltration ("UF") unit 90 can be utilized, which unit produces a reject waste stream 91. Then, effluent from the UF unit 90 or precoat filter 88 can be sent to a reverse osmosis ("RO") system 92, which in addition to the desired permeate 94, produces a reject liquid stream 96 that must be appropriately handled. Permeate 94 from the RO system 92, can be sent to an ion exchange unit 100, typically but not necessarily a mixed bed demineralization unit, which of course requires regeneration chemicals 102 and which consequently produces a regeneration waste 104. And finally, the boiler 80 produces a blowdown 110 which must be accommodated for reuse or disposal.

The prior art process designs, such as depicted in FIG. 3, for utilizing packaged boilers in heavy oil recovery operations, have a high initial capital cost. Also, such a series of unit process steps involves significant ongoing chemical costs. Moreover, there are many waste streams to discharge, involving a high and ongoing sludge disposal cost. Further, where membrane systems such as ultrafiltration 90 or reverse osmosis 92 are utilized, relatively frequent replacement of membranes 106 or 108, respectively, may be expected, with accompanying on-going periodic replacement costs. Also, such a process scheme can be labor intensive to operate and to maintain.

In summary, the currently known and utilized methods for treating heavy oil field produced waters in order to generate high quality steam for down-hole use are not entirely satisfactory because: such physical-chemical treatment process schemes are usually quite extensive, are relatively difficult to maintain, and require significant operator attention; such physical-chemical treatment processes require many chemical additives which must be obtained at considerable expense, and many of which require special attention for safe handling; such physical-chemical treatment processes produce substantial quantities of undesirable sludges and other waste streams, the disposal of which is increasingly difficult, due to stringent environmental and regulatory requirements.

It is clear that the development of a simpler, more cost effective approach to produced water treatment would be desirable in the process of producing steam in heavy oil production operations. Thus, it can be appreciated that it would be advantageous to provide a new produced water treatment process which minimizes the production of undesirable waste streams, while minimizing the overall costs of owning and operating a heavy oil recovery plant.

SOME OBJECTS, ADVANTAGES, AND NOVEL FEATURES

The new water treatment process(es) disclosed herein, and various embodiments thereof, can be applied to heavy oil production operations. Such embodiments are particularly advantageous in that they minimize the generation of waste products, and are otherwise superior to water treatment processes heretofore used or proposed in the recovery of bitumen from tar sands or other heavy oil recovery operations.

From the foregoing, it will be apparent to the reader that one of the important and primary objectives resides in the provision of a novel process, including several variations thereof, for the treatment of produced waters, so that such waters can be re-used in producing steam for use in heavy oil recovery operations.

Another important objective is to simplify process plant flow sheets, i.e., minimize the number of unit processes required in a water treatment train, which importantly simplifies operations and improves quality control in the manufacture of high purity water for down-hole applications.

Other important but more specific objectives reside in the provision of various embodiments for an improved water treatment process for production of high purity water for down-hole use in heavy oil recovery, which embodiments may: in one embodiment, eliminate the requirement for flash separation of the high pressure steam to be utilized downhole from residual hot pressurized liquids; eliminate the generation of softener sludges; minimize the production of undesirable liquid or solid waste streams; minimize operation and maintenance labor requirements; minimize maintenance materiel requirements; minimize chemical additives and associated handling requirements; increase reliability of the OTSG's, when used in the process; decouple the de-oiling operations from steam production operations; and reduce the initial capital cost of water treatment equipment.

Other important objectives, features, and additional advantages of the various embodiments of the novel process disclosed herein will become apparent to the reader from the foregoing and from the appended claims and the ensuing detailed description, as the discussion below proceeds in conjunction with examination of the accompanying drawing.

BRIEF DESCRIPTION OF THE DRAWING

In order to enable the reader to attain a more complete appreciation of the novel water treatment process disclosed and claimed herein, and the various embodiments thereof, and of the novel features and the advantages thereof over prior art processes, attention is directed to the following detailed description when considered in connection with the accompanying figures of the drawing, wherein:

FIG. 1 shows one typical prior art process, namely a generalized process flow diagram for a physical-chemical water treatment process configured for use in heavy oil recovery operations.

FIG. 2 shows another prior art process, namely a generalized process flow diagram for a physical-chemical water treatment process as used in a steam assisted gravity drainage (SAGD) type heavy oil operation.

FIG. 3 shows yet another prior art physical-chemical treatment process scheme, also as it might be applied for use in steam assisted gravity drainage (SAGD) type heavy oil recovery operations.

FIG. 4 shows one embodiment of an evaporation based water treatment process, illustrating the use of a seeded slurry evaporation based process in combination with the use of packaged boilers for steam production, as applied to heavy oil recovery operations.

FIG. 5 shows another embodiment for an evaporation based water treatment process for heavy oil production, illustrating the use of a seeded slurry evaporation process in combination with the use of once-through steam generators for steam production, as applied to heavy oil recovery operations, which process is characterized by feed of evaporator distillate to once-through steam generators without the necessity of further pretreatment.

FIG. 6 shows a common variation for the orientation of injection and