WO2009105309A1 - Procédé et système de génération de vapeur dans l’industrie pétrolière - Google Patents

Procédé et système de génération de vapeur dans l’industrie pétrolière Download PDF

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Publication number
WO2009105309A1
WO2009105309A1 PCT/US2009/032019 US2009032019W WO2009105309A1 WO 2009105309 A1 WO2009105309 A1 WO 2009105309A1 US 2009032019 W US2009032019 W US 2009032019W WO 2009105309 A1 WO2009105309 A1 WO 2009105309A1
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Prior art keywords
steam
primary
liquid phase
bfw
wet
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PCT/US2009/032019
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English (en)
Inventor
Brian C. Speirs
James A. Dunn
Jody L. Calvert
Brian P. Head
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Exxonmobil Upstream Research Company
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Publication of WO2009105309A1 publication Critical patent/WO2009105309A1/fr

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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B33/00—Steam-generation plants, e.g. comprising steam boilers of different types in mutual association

Definitions

  • the present invention relates generally to steam generation. More particularly, the present invention relates to a new method and system for generating steam in the oil industry utilizing steam generators configured in series.
  • Oil sand deposits located in many regions of the world, comprise mixtures of sand, water, clay, minerals, and crude bitumen that can be extracted and processed for fuel.
  • the oil sands of Alberta, Canada contain some of the largest deposits of hydrocarbons in the world.
  • Bitumen is classified as an "extra heavy oil", with an API gravity of about 10° or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale.
  • “Heavy oil” has an API gravity in the range of about 22.3° to about 10°.
  • Heavy oil or bitumen extracted from oil sand may be processed or upgraded to produce light synthetic crude oil having an API gravity of about 31° to about 33°.
  • the terms heavy oil and bitumen are used interchangeably herein since they may be extracted using the same processes.
  • Bitumen can be recovered from oil sands by various methods, the most common of which include surface or strip mining and in- situ heavy oil recovery methods.
  • In- situ oil recovery methods including thermal in-situ oil recovery methods, are applied when the bitumen is buried deep within a reservoir and cannot be mined economically due to the depth of the overburden.
  • the focus of an in-situ recovery process is to reduce the viscosity of the bitumen or heavy oil in a formation to enable it to flow and be produced from a well.
  • Thermal in-situ recovery processes use heat, typically provided by injection of steam into a formation, to reduce the viscosity of the bitumen in a reservoir and thereby render it more flowable.
  • thermal in-situ recovery processes include but are not limited to steam- assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and various derivatives thereof, such as solvent-assisted SAGD (SA-SAGD), steam and gas push (SAGP), combined vapor and steam extraction (SAVEX), expanding solvent SAGD (ES-SAGD), constant steam drainage (CSD), and liquid addition to steam enhancing recovery (LASER), as well as water flooding and steam flooding processes.
  • SAGD steam- assisted gravity drainage
  • CSS cyclic steam stimulation
  • SAGP solvent-assisted SAGD
  • SAGP steam and gas push
  • SAVEX combined vapor and steam extraction
  • ES-SAGD expanding solvent SAGD
  • CSSD constant steam drainage
  • LASER liquid addition to steam enhancing recovery
  • the use of steam renders these processes highly water intensive.
  • a typical gravity-driven thermal in- situ oil recovery process such as SAGD
  • two substantially horizontal wells are drilled into a reservoir.
  • a lower horizontal well ideally located near the bottom of the reservoir, serves as a production well and a horizontal well located above the production well serves as an injection well.
  • Steam is injected into the injection well from the surface (with or without the addition of a hydrocarbon solvent) to heat the bitumen trapped in the reservoir and lower its viscosity. As the viscosity of the bitumen is lowered, it flows into the production well, along with condensed steam, and these production fluids are pumped to the surface.
  • dry steam is preferred. In the industry, dry steam is understood to be substantially free of water, or dry-saturated, a thermodynamic definition that defines the steam as having no free water, but at the same pressure and temperature as a wet steam.
  • drum boilers also referred to as packaged boilers
  • SAGD operations Each steam generation system has different advantages and attributes.
  • the water quality requirements for the OTSG are not as stringent as for drum boilers, the system is burdened with the extra cost of handling a high pressure, high temperature liquid stream produced from the OTSG (commonly referred to as the liquid phase or boiler blowdown).
  • the drum boiler generates dry steam but requires significantly higher water quality than an OTSG to prevent scaling.
  • Typical boiler feed water quality requirements for an OTSG and a drum boiler are shown in Table 1, adapted from U.S. Patent No. 7,077,201 to Heins.
  • a main disadvantage of the conventional water treatment and steam generation processes is the generation of a large volume high temperature waste stream, referred to in the industry as the liquid phase or boiler blowdown.
  • the blowdown stream accounts for about 15% v/v to about 40% v/v of the initial boiler feed water.
  • a typical blowdown stream based on 75% steam quality, contains 25% v/v of the initial feed water.
  • Current methodologies used to treat this waste stream include simple heat recovery and disposal, as well as combinations of heat recovery, partial recycling, and the implementation of zero liquid discharge (ZLD) systems.
  • ZLD zero liquid discharge
  • PCT Patent Publication WO 2005/054746 promotes the use of a conventional drum boiler operating in a closed cycle. Steam is generated from clean water, then used as a heat transfer medium to generate steam from the produced water at a high pressure. All of these schemes claim a 95% - 98% v/v recovery of produced water and can thus result in a boiler blowdown stream ranging between 2% and 5% by volume, where ZLD is not utilized in the process configuration.
  • the present invention provides a novel method and system for generating steam using steam generators configured in series to increase steam production per unit of water, compared to the conventional SAGD OTSG configuration, and to reduce liquid waste or boiler blowdown.
  • the present invention provides a process for generating steam. The process comprises feeding boiler feed water (BFW) of sufficient quality through one or more primary wet steam generators to generate primary wet steam therefrom; separating the primary wet steam into at least primary steam and a primary liquid phase; and feeding the primary liquid phase into one or more secondary steam generators to generate secondary steam therefrom.
  • BFW boiler feed water
  • the primary steam is preferably dry steam.
  • the one or more secondary steam generators comprise one or more secondary wet steam generators for generating secondary wet steam from the primary liquid phase.
  • the process may further comprise separating the secondary wet steam into secondary dry steam and a secondary liquid phase.
  • the present invention provides a system for generating steam.
  • the system comprises one or more primary wet steam generators for generating primary wet steam from boiler feed water (BFW) of sufficient quality; at least one primary steam separator in communication with the one or more primary wet steam generators for receiving the wet steam and separating it into primary steam and a primary liquid phase; and one or more secondary steam generators in communication with the at least one steam separator for receiving the primary liquid phase and generating secondary steam therefrom.
  • BFW boiler feed water
  • the primary steam is preferably dry steam.
  • the one or more secondary steam generators are secondary wet steam generators for generating secondary wet steam.
  • system further comprises at least one secondary steam separator in communication with the one or more secondary wet steam generators, the at least one secondary separator for receiving the secondary wet steam and separating it into secondary dry steam and a secondary liquid phase.
  • the wet steam generators are once-through steam generators (OTSGs), heat recovery steam generators (HRSGs), or a combination thereof.
  • OTSGs once-through steam generators
  • HRSGs heat recovery steam generators
  • the wet or dry steam generated may be used to support an oil recovery or mining operation.
  • the steam generated is used to support an in-situ heavy oil recovery operation.
  • the in-situ heavy oil recovery operation is a steam- assisted gravity drainage (SAGD) operation and the dry steam produced is utilized for reservoir injection.
  • SAGD steam- assisted gravity drainage
  • the invention provides a process for generating steam to support an in- situ heavy oil recovery operation.
  • the process comprises the steps of feeding boiler feed water (BFW) of sufficient quality through 2 to 12 primary once-through steam generators (OTSGs) configured in parallel to generate primary wet steam having a steam quality of about 60% to about 85%; separating the primary wet steam in a primary steam separator to produce primary dry steam having a steam quality of greater than about 90% and a primary liquid phase; feeding the primary liquid phase to a secondary once-though steam generator configured in series to generate secondary wet steam having a steam quality of about 60% to about 85%; and separating the secondary wet steam in a secondary steam separator to produce secondary dry steam having a steam quality of greater than about 90% and a secondary liquid phase.
  • BFW boiler feed water
  • OTSGs primary once-through steam generators
  • Fig. 1 exemplifies a conventional SAGD water treatment process using OTSG to generate steam
  • Fig. 2 exemplifies a conventional prior art configuration for OTSG steam generation for a typical SAGD operation
  • Fig. 3a exemplifies a serial steam generator configuration in accordance with an aspect of the present invention, wherein wet steam (WS) from one or more primary wet steam generators is separated into dry steam and a liquid phase (LP), and the LP is then sent to one or more secondary steam generators for further steam generation;
  • WS wet steam
  • LP liquid phase
  • Fig. 3b exemplifies a serial steam generation configuration in accordance with an aspect of the present invention, wherein wet steam (WS) from one or more primary wet steam generators is separated into dry steam and a liquid phase (LP), and the LP is then sent to one or more secondary wet steam generators for further steam generation followed by steam separation to produce more dry steam;
  • WS wet steam
  • LP liquid phase
  • Fig. 4 exemplifies an OTSG configuration in accordance with a first embodiment of the invention
  • Fig. 5 exemplifies a second embodiment of the present invention wherein heat is exchanged from the primary liquid phase to the BFW;
  • Fig. 6 exemplifies a third embodiment of the present invention comprising a heat exchanger on the dry steam line from the primary steam separator;
  • Fig. 7 exemplifies a fourth embodiment of the present invention wherein the liquid from the primary separation vessel is flashed to a lower pressure to generate low pressure steam for utility purposes, concomitantly concentrating the TDS in the liquid and reducing blowdown volume;
  • Fig. 8 exemplifies a fifth embodiment of the present invention comprising a heat exchanger on the low pressure side of the HP pumps with an optional atmospheric flash of the liquid phase recovered from the secondary separation vessel for further disposal reduction;
  • Fig. 9 exemplifies a sixth embodiment of the present invention wherein wet steam produced from the secondary OTSG in series is sent to the primary steam separator and the liquid phase is commingled with the liquid phase from primary OTSGs 1 - 4 in a parallel configuration.
  • the present invention provides an improved method and system for generating steam in the oil industry. More particularly, the present invention provides a novel method and system for generating steam, preferably to support an oil recovery or mining operation, the process utilizing steam generators configured in series. This unique configuration results in increased steam production per unit of inlet boiler feed water, as well as an overall reduction of liquid waste or boiler blowdown, when compared to the conventional SAGD OTSG configuration for steam generation.
  • An oil recovery operation as contemplated herein, may include any oil or gas recovery operation where steam generation is required or desired and, in particular, includes heavy oil recovery operations.
  • the steam generated may be used for various purposes to support an oil recovery or mining operation, including but not limited to reservoir injection, feed for steam turbines, and any other utility purposes.
  • one or more primary steam generators are configured in series with one or more secondary steam generators.
  • the steam generators utilized for the primary steam generation step are preferably a wet steam generators.
  • wet steam generator includes any forced circulation once-through wet steam generation device, including but not limited once-through steam generators (OTSGs), for example, as described in API RP HT (American Institute of Petroleum, Recommended Practice for Installation and Operation of Wet Steam Generators, API Recommended Practice HT, Second Edition, November 1, 1994), and those configured as Heat Recovery Steam Generators (HRSGs).
  • the steam generator(s) utilized for the secondary steam generation step may be any steam generator(s) capable of handling the liquid phase from the one or more primary steam generators, including wet steam generators.
  • FIG. 1 exemplifies a conventional prior art SAGD water treatment and steam generation process utilizing OTSG to generate dry steam, also referred to in the industry as 100% quality steam, from produced water. Dry steam (12) and optionally solvent are injected into the injection well (14). The hot steam reduces the viscosity of bitumen trapped in the formation.
  • the production fluids (16) typically comprise about 70% produced water and about 30% bitumen and produced gases, although the exact proportions can vary.
  • the production fluids (16) are sent to a flow splitter (20), or Free Water Knock Out (FWKO), to separate the production fluids (16) into two or more separate streams.
  • FWKO Free Water Knock Out
  • the exemplified flow splitter separates the production fluids into a produced water steam (22), a wet bitumen stream (24) and a produced gas stream (26).
  • the bitumen and gas streams each undergo further processing to generate a bitumen product (28) and a gas product (30).
  • the produced water (PW) stream (22) also undergoes further treatment.
  • the PW stream (22) first undergoes PW Deoiling (32), generally via resident time in a skim tank, Induced Gas Floatation (IGF), Induced Static Floatation (ISF) or another suitable method, and optionally passage though oil removal filters.
  • the Oil Free Water stream (34) is then sent for hardness, iron and silica removal to produce boiler feed water of sufficient quality for steam generation.
  • oil free water (34) is sent to primary hardness removal vessels (36), such as Hot Lime Softeners (HLS), Warm Lime Softeners (WLS) or the like, for treatment.
  • primary hardness removal vessels such as Hot Lime Softeners (HLS), Warm Lime Softeners (WLS) or the like
  • the softened water stream (38) is directed through After Filters (40) to secondary hardness removal vessels (42), for example, vessels for Weak Acid Cation Exchange (WAC) or Strong Acid Cation Exchange (SAC), to produce boiler feed water (BFW) (44) of sufficient quality for steam generation.
  • the BFW (44) is fed into the once-through steam generators (OTSGs) (46) to generate saturated or wet steam (47).
  • Wet steam (47) exiting the OTSGs is then sent to a steam separator (48), such as a high pressure steam separator, to generate dry steam (12) for injection into the reservoir.
  • a steam separator such as a high pressure steam separator
  • the liquid phase (50), or boiler blowdown, from the steam separator (48) is a high pressure high temperature waste stream that contains all of the total dissolved solids (TDS) initially present in the BFW (44). Heat may be recovered from the blowdown stream prior to disposal (52).
  • FIG. 2 A conventional approach to steam generation utilizing OTSGs is exemplified in Figure 2, wherein OTSGs 1 - 5 are configured in parallel with one another wherein each OTSG receives about 20% of the BFW (54) stream.
  • the BFW (54) is pumped through the OTSGs by a high pressure BFW pump (55) and wet steam (56) is generated therefrom.
  • the wet steam (56) is discharged to a steam separator (58), such as a high pressure wet steam separator, which in this exemplary case, yields about 75% dry steam (60), suitable for injection into a reservoir, and about 25% liquid phase (62) or boiler blowdown.
  • the liquid phase (62) produced from the OTSGs contains about 4 times the concentration of hardness ions, silica, and overall TDS, as the initial BFW (54).
  • a conventional OTSG typically generates between about 60 - 85% steam quality.
  • FIG. 3 a A serial configuration, in accordance with a general embodiment of the present invention, is shown in Figure 3 a, where BFW of sufficient quality (64) is passed through one or more primary wet steam generators (66) to generate wet steam (68), typically of 60% to 85% steam quality.
  • the wet steam (68) is then separated in at least one primary steam separator (69) into primary steam (70) and a primary liquid phase (72).
  • the primary steam is preferably dry steam.
  • the liquid phase (72) is passed through one or more secondary steam generators (74) to generate additional steam (76) from the primary liquid phase (72).
  • the additional steam (76) generated from the primary liquid phase (72) may be wet steam or dry steam depending on the equipment and process selected.
  • Figure 3b shows an extension of this general embodiment, wherein the one or more secondary steam generators are wet steam generators (78) configured in series with the one ore more primary wet steam generators (66), to generate a stream of secondary wet steam (80) from the primary liquid phase (72), which is then separated in a secondary steam separator (82) to generate additional or secondary dry steam (84) and a concentrated secondary liquid phase (86) or boiler blowdown. All or a portion of the steam generated by this process may be used for reservoir injection or all or a portion of the steam may be utilized for other purposes.
  • the concentrated secondary liquid phase (86), or blowdown stream may be treated by any suitable means, including heat recovery, or simply sent to disposal.
  • Dry steam typically refers to steam having a steam quality greater than about 90%, preferably greater than about 95%, more preferably greater than about 99%.
  • dry steam is often referred to as “quality steam” or “100% quality steam” .
  • dry steam refers to the steam discharged from the steam separator, which has a steam quality higher than the wet steam exiting the wet steam generator. Dry steam is typically preferred for reservoir injection.
  • FIG. 4 depicts four primary OTSGs (OTSG 1-4) operating in parallel and configured in series with a fifth OTSG (OTSG 5) positioned downstream from the primary OTSGs.
  • BFW of sufficient quality (87) is pumped into the primary OTSGs using a high pressure BFW pump (89).
  • the primary dry steam (92) may be sent to the reservoir for injection downhole.
  • the primary liquid phase (94) produced by steam separation is further processed in a secondary OTSG (OTSG 5), configured in series and downstream from the primary OTSGs 1-4, to generate additional or secondary wet steam (96).
  • OTSG 5 secondary OTSG
  • the operating pressure of the high pressure boiler feed water pump (89) is sufficient to move the liquid phase from the primary OTSGs 1-4 through the secondary OTSG 5 without an additional pressure boost.
  • the secondary wet steam (96) from secondary OTSG 5 may then be separated in a secondary steam separator (98) to produce secondary dry steam (100) and a concentrated secondary liquid phase (102) or boiler blowdown.
  • the secondary dry steam (100) from OTSG 5 may be combined with the primary dry steam (92) to form a stream of common dry steam (103) if conditions are suitable and the dry steam can be directed to the reservoir.
  • the primary and secondary dry steam (92, 100) may remain in separate streams.
  • all or a portion of the dry steam produced may be utilized for purposes other than reservoir injection, including utility purposes.
  • all of the dry steam generated is utilized for reservoir injection. It is recognized that some of the primary or secondary wet steam produced could be slipstreamed and used for alternative purposes but preferably these streams are entirely directed to the steam separators to generate dry steam.
  • this embodiment utilizes OTSGs in parallel (OTSG 1-4) and in series (OTSG 5), in contrast to the conventional configuration with only a parallel configuration.
  • the overall process uses the same number of steam generators as the conventional approach of Figure 2 but in a unique configuration that results in an increased yield of dry steam per unit of inlet BFW (93.75% compared to 75%) about 25% v/v higher than the volume of steam generated in the conventional prior art approach shown in Figure 2.
  • This process also significantly reduces the boiler blowdown fraction (6.25% compared to 25%) by about 75% - 80% compared to the prior art approach, to volumes similar to recently proposed evaporative technologies, such as MVC systems.
  • This embodiment of the invention also provides for a significant reduction in capital and operating expense, compared to other known processes, and results in improved environmental performance.
  • the concentrated liquid phase (102) from the secondary steam separator (98) may be sent to disposal or to any other treatment scheme known in the art, including but not limited to heat recovery, evaporation, crystallization, or membrane filtration.
  • a third steam generator could be configured in the series, and so on, if the concentrated liquid phase (102) from the secondary separator (98) meets tolerable boiler feed water specifications for a steam generator.
  • a water treatment process is preferably utilized to provide BFW of sufficient quality to the inlet of the primary OTSGs for the generation of primary wet steam. After steam separation, it is desirable that the primary liquid phase be discharged directly to secondary OTSG without further treatment, thus it is preferable that the water treatment process utilized deliver a boiler feed water stream to the inlet of the primary OTSGs that is of sufficient quality that the primary liquid phase produced can be discharged to the secondary OTSG 5 without resulting in significant damage to the process or to the secondary steam generation equipment.
  • a suitable BFW for the primary OTSGs 1 - 4 would have about 25% or less of the normal total hardness, iron, silica and TDS specifications for a conventional OTSG, based on a typical steam quality of 75%. Where 80% quality steam is generated, the BFW would preferably have about 20% or less of the normal total hardness, iron, silica and TDS content compared to conventional BFW specifications.
  • the enhanced BFW water quality supplied to the primary OTSGs 1-4 results in a primary liquid phase that still meets conventional BFW specifications for OTSGs. This permits direct discharge of the primary liquid phase to a secondary conventional OTSG configured in series.
  • the primary liquid phase could be treated or partially treated by any suitable technology, including conventional water softening or reverse osmosis, or subjected to trim treatment, prior to discharge to the secondary steam generator, if desired. It is also recognized that BFW, or water from any other suitable source, could be blended with the primary liquid phase and optionally treated prior to entering the secondary OTSG, if desired. If the primary liquid phase is treated and/or blended prior to discharge to the secondary OTSG, the need for increased BFW quality at the inlet of the primary OTSGs is minimized or eliminated. The quality of the primary liquid phase will, in large part, determine the type of generator that may be used in the secondary steam generation step.
  • the resultant quality water would be suitable for steam generation in a drum boiler.
  • a skilled operator can weigh the benefits and disadvantages of treating the initial BFW to sufficient quality such that the primary liquid phase can be discharged to the secondary steam generator without treatment, against treating or blending the primary liquid phase prior to discharge to the secondary steam generator. A combination of the two approaches may also be utilized.
  • the water treatment scheme used to achieve boiler feed water specifications for the primary OTSGs may be any process known in the art.
  • make up water from any suitable water source including but not limited to fresh, brackish, surface, subterranean, or process affected water, or combinations thereof, may optionally be combined with the produced water, before or after treatment, to produce the BFW.
  • the BFW may be generated entirely from water sources other than produced water, with produced water going to other uses
  • Suitable or tolerable BFW specifications can be determined by a person of skill in the art, for example, to accommodate for higher or lower steam quality or modifications to the OTSGs. Where 75% steam quality is generated, for example, the BFW specifications could be about 25% of the API specifications or lower. Where 80% steam quality is generated, for example, the BFW specifications could be about 20% of the API specifications or lower.
  • Boiler feed water specifications typically target an upper limit only. Once this upper limit is reached or exceeded in a conventional SAGD treatment process, regeneration of secondary softening equipment (ex. WAC, SAC or the like) is required.
  • the lower permissible limit of the ranges for BFW specifications will typically be about or equal to zero (0). Values near the lower limits of the specifications may not be detectable by standard analysis methods.
  • API RP-I lT standards indicate that TDS concentrations of up to about 20% of saturation (i.e. 60,000 ppm for NaCl), and silica levels up to 150 ppm, can be tolerated for operation of an OTSG.
  • the lower limit of such ranges is zero (0 ppm).
  • a pH operating range of 7 - 12 will generally be tolerated by the robust OTSGs.
  • Bowman et. al describe operational experience with high TDS water and silica levels up to 300 ppm (SPE Ther. Oper. & Heavy Oil Int. Symp., Bakersfield, CA, 2/10-12/97, Proc. pp.143-154, 1997. (SPE-37528)).
  • Non-limiting exemplary BFW specifications for conventional primary OTSGs are presented in Table 2 below.
  • the table exemplifies the effect of increasing initial BFW quality, such that the primary liquid phase produced after steam separation is suitable for processing in the secondary OTSG.
  • These figures are based on the current OTSG water specifications presented in Table 1.
  • a suitable BFW for inlet to the primary OTSGs in this embodiment could have any of the following specifications: hardness less than 0.25 ppm as CaCO 3 , total Fe less than 0.05 ppm, TDS less that 12,000 pm.
  • a TDS of approximately 15,000 ppm could be used when producing 75% quality steam.
  • silica is less than 25 ppm, although higher silica could be tolerated.
  • the pH is in the range of 7.0 to 12.0. In one embodiment, the pH is in the range of 7.5 to 9.5. In one embodiment, O 2 content is less than 2 ppb, and oil and grease content less than 0.1 ppm.
  • the OTSGs are quite robust however, and can tolerate a range of BFW qualities. Appropriate BFW specifications for OTSGs may determined by a person of skill in the art.
  • the primary liquid phase (94) produced from primary OTSGs 1-4 contains approximately 4 times the concentration of hardness ions, silica, TDS, etc. as the BFW (87) at the inlet of the primary OTSGs.
  • the quality of the primary liquid phase (94) recovered from the primary steam separator (88) is still of sufficient quality to meet current OTSG BFW specifications for OTSG 5.
  • the modified specifications for the primary OTSGs, while more stringent than the conventional OTSG requirements, is still significantly lower quality than that required by drum boilers.
  • Table 2 Exemplary water specifications for primary and secondary OTSGs, in accordance with an embodiment of the invention.
  • a 1 : 1 configuration of primary wet steam generator to secondary wet steam generator is utilized, wherein a primary HRSG discharges to a secondary OTSG.
  • two to or more primary OTSGs will be configured in parallel with each other and in series with one or more secondary OTSGs.
  • the exact configuration can be modified and optimized by the skilled person based on, for example, BFW quality, steam quality generated, design and capacity of the steam generators, or design and capacity of the steam separators utilized.
  • primary wet steam generators are configured in parallel with each other and in series with one secondary steam generator.
  • 2 to 12 primary wet steam generators are configured in parallel.
  • 2 to 8 primary wet steam generators are configured in parallel.
  • 3 to 6 primary wet steam generators are configured in parallel.
  • the term parallel is used loosely to indicate that two or more primary wet steam generators feed into a common steam separator to produce a common liquid phase that is directed to one or more secondary steam generators for further processing.
  • various networks can be configured wherein the primary wet steam generators feed into multiple primary steam separators, which then feed, in whole or in part, into one or more secondary steam generators.
  • multiple primary steam separators may feed into a common secondary steam generator, or a common steam separator could be used to separate the primary liquid phase and the secondary liquid phase.
  • the primary and secondary steam generators may individually vary in design, capacity, or operation, including operating temperatures and pressures. That is, the primary wet steam generators may vary with respect to one another, and may also vary in respect to the secondary steam generators, which may also vary with respect to one another and with respect to the primary wet steam generators. As an example, the liquid phase from a primary HRSG could feed a secondary OTSG. Moreover, the primary and secondary steam generators need not be positioned adjacent one another in a steam plant. The steam generators may be separated by some distance from one another in the configuration and may even be separated by geographic location. The maximum permissible distance is limited only by practicality and cost, not technology.
  • two (or more) in-situ thermal oil recovery plants such as a SAGD and CSS plant, could be integrated with one water treatment facility, wherein the liquid blowdown from one could feed remote steam generation.
  • a SAGD and CSS plant could be integrated with one water treatment facility, wherein the liquid blowdown from one could feed remote steam generation.
  • the operation of the secondary OTSG may be varied to achieve different steam quality than the primary OTSGs, with the target steam quality dependent, in large part, on concentration of ionic species in the inlet boiler feed water.
  • the upper steam quality limit for both the primary and the secondary OTSGs is determined by a combination of water chemistry, tube temperature, flame shape control (i.e. flame impingement), tube metallurgy, and risk tolerance, among other factors known to those skilled in the art.
  • a heat exchange unit (104) is used to transfer a portion of heat from the primary liquid phase (94), exiting the primary high pressure steam separator (88), to the BFW (87).
  • the primary liquid phase (94) is cooled before entering OTSG 5.
  • all 5 OTSGs could operate with similar water inlet and stack gas temperatures, assuming substantially identical operation, and hence could be of substantially identical design.
  • the OTSG inlet and discharge piping may advantageously be arranged such that any OTSG could be operated as a primary or secondary unit, such that the series operation could continue even if the normally designated secondary OTSG was out of service.
  • a pressure regulating device (106) such as a control valve, is added on the line carrying the primary dry steam (92) from the high pressure primary steam separator (88), and a heat exchange element (108) is added on the steam line downstream of the pressure regulating device (106).
  • a pressure regulating device such as a control valve
  • the pressure of primary dry steam (92) should be lowered. If the pressure drop is large, a consequence of lowering the pressure is to cause the dry steam to become a lower temperature and pressure steam (110) and to become wet.
  • the pressure of the liquid phase from the primary separator can be boosted by the required amount prior to entering the secondary OTSG so that no pressure drop of the dry steam is required to combine the two streams, thereby removing the drop in quality which would otherwise occur.
  • This can be accomplished by any method known in the art, such as pumps, pressure exchangers, ejectors or the like.
  • a liquid-liquid ejector could be advantageously used if dilution of the liquid phase with primary BFW was desired.
  • a pressure regulating device such as a control valve, is added downstream of the high pressure primary steam separator (88).
  • the primary liquid phase (94) is flashed to a lower pressure in a flash vessel (112) to generate low pressure steam (114) for utility purposes.
  • the saturated primary liquid phase (94) is at 12 MPa and is subsequently flashed to 1 MPa, approximately 36% of the liquid phase would vapourize at 180 0 C. This steam would be available for utility purposes or heat and water recovery.
  • the desired pressure drop and thus the amount of generated steam would ideally be chosen to match the internal utility steam consumption requirements of the operating facility.
  • the 9 units of utility steam shown in Figure 7 could be used to provide energy to a crystallizer.
  • the concentrated liquid emanating from the secondary separation vessel (98) is at high temperature.
  • a subsequent flash to atmospheric pressure using a second pressure regulating device (119) and a second flash vessel (120) would increase the concentration of solids in the final blowdown stream (124) and reduce the volume of the final blowdown stream (124) to about 2% of inlet BFW (2 units).
  • a low liquid waste system is achieved without the use of costly evaporators.
  • the heat in the vapour (122) could be used for any process purpose, such as, combustion air preheat, HVAC purposes, with the condensate returned as boiler feed water.
  • any waste feeds generated by the water treatment process i.e. HLS/ WLS waste etc.
  • HLS/ WLS waste etc. could be fed into a crystallizer to eliminate the requirement for temporary disposal sludge ponds.
  • Combinations and extensions of the embodiments described herein can also be used, for instance, the heat exchanger (104) of the embodiment of Figure 5 could be used in with conjunction with the embodiment of Figure 7. The cooler temperature of the liquid would enhance the reliability of the BFW pump positioned upstream of OTSG 5.
  • a heat exchange unit (104) could be positioned on the low pressure side of the HP BFW pump (89), the location being facilitated by the lower temperature of the water.
  • a sixth embodiment of the present invention exemplified in Figure 9, requires only one high pressure steam separator.
  • Primary wet steam (90) from the primary OTSGs 1-4 and secondary wet steam (128) from the secondary OTSG 5 is sent to a common steam separator (124) to produce dry steam (130) and a common liquid phase (132), which is a blend of liquid separated from the primary wet steam (90) and the secondary wet steam (128).
  • TDS will increase in the common liquid phase (132), however the TDS concentration can be controlled by utilizing a purge or slipstream (134).
  • a slipstream (134) could optimally be created to prevent TDS levels in the common liquid phase (132) fed to OTSG 5 from exceeding about 20% of saturation, roughly 50,000 ppm. In this fashion, the volume of disposal via the slipstream (134) is about 2% original BFW volume.
  • the steam generators utilized in accordance with the present invention need not be of the same design, capacity or operation. They may vary and may be customized to a particular operation.
  • the exemplary embodiments disclosed herein illustrate 4 primary OTSGs configured in parallel with one another and in series with one secondary OTSG, the invention is in no way limited by the exemplary embodiments. The exact configuration and equipment utilized can be optimized by the skilled person depending on the particular operation.
  • the scope of the invention is in not limited to typical operations or conventional steam generators. Networks of steam generators configured in parallel and in series with one another may be designed without departing from the scope of the invention.
  • each OTSG is identical and has a boiler feed water design flow rate of 2500 m /d and generates 75% v/v quality steam, and that the daily operation is expected to generate 9375m 3 /d of dry steam.
  • the dry steam requirement is 9375 m 3 /d
  • a total of five conventional OTSG units in parallel would be required.
  • a total of 12,500m 3 /d water treatment capacity would be needed to supply sufficient boiler feed water for steam generation.
  • the total boiler blowdown stream from the five OTSGs configured in parallel would total 3125 m /d.
  • Table 5 below presents an illustrative comparison of a steam generation process of the invention versus the prior art approach, at OTSG steam qualities of 75% and 80%.

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Control Of Eletrric Generators (AREA)

Abstract

La présente invention concerne un nouveau procédé et un nouveau système de génération de vapeur dans l’industrie du pétrole et du gaz, et en particulier dans l’industrie du pétrole lourd. Le procédé comprend l’approvisionnement en eau d’alimentation de chaudière (BFW) ayant une qualité suffisante par le biais d’un ou plusieurs générateur(s) primaire(s) de vapeur humide afin de générer de la vapeur humide primaire; la séparation de la vapeur humide primaire en un flux sec primaire et une phase liquide primaire; et l’approvisionnement en phase liquide primaire d’un ou plusieurs générateur(s) de vapeur secondaire(s) afin de générer de la vapeur secondaire. Les générateurs de vapeur secondaires peuvent ou non être des générateurs de vapeur humide. Cette configuration en série unique entraîne une augmentation de la production de vapeur par unité d’eau d’alimentation de chaudière, et une réduction globale des déchets liquides ou de la dépressurisation de la chaudière, en comparaison avec la configuration de génération de vapeur humide SAGD classique (drainage par gravité assistée par la vapeur). L’invention concerne également un système d’exécution du procédé.
PCT/US2009/032019 2008-02-21 2009-01-26 Procédé et système de génération de vapeur dans l’industrie pétrolière WO2009105309A1 (fr)

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CA2621991A CA2621991C (fr) 2008-02-21 2008-02-21 Methode et systeme de generation de vapeur dans l'industrie petroliere

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US8240370B2 (en) 2009-12-18 2012-08-14 Air Products And Chemicals, Inc. Integrated hydrogen production and hydrocarbon extraction
CN102854294A (zh) * 2011-10-17 2013-01-02 中国石油天然气股份有限公司 用于检测油田注过热蒸汽工艺中水质标准的系统及方法
WO2013058822A1 (fr) * 2011-06-10 2013-04-25 Exxonmobil Upstream Research Company Procédés et systèmes pour fournir de la vapeur
WO2014066034A1 (fr) * 2012-10-24 2014-05-01 Conocophillips Company Production directe de vapeur de purge de chaudière
US20140224192A1 (en) * 2013-02-13 2014-08-14 Lawrence E. Bool, III Steam quality boosting
CN104763998A (zh) * 2015-03-11 2015-07-08 中国石油大学(华东) 余热两级回收型分体式蒸汽发生装置
US9328601B2 (en) 2013-04-30 2016-05-03 General Electric Company System and method for enhanced recovery of oil from an oil field
US9359868B2 (en) 2012-06-22 2016-06-07 Exxonmobil Upstream Research Company Recovery from a subsurface hydrocarbon reservoir
US9593563B2 (en) 2011-10-05 2017-03-14 Statoil Petroleum As Method and apparatus for generating steam for the recovery of hydrocarbon
CN109964081A (zh) * 2016-11-02 2019-07-02 西门子股份公司 蒸发器系统

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US8166925B2 (en) 2007-10-26 2012-05-01 Fccl Partnership Method and apparatus for steam generation
CA2762451C (fr) 2011-12-16 2019-02-26 Imperial Oil Resources Limited Methode et systeme de prelevement de fluides dans un reservoir
WO2017192766A1 (fr) * 2016-05-03 2017-11-09 Energy Analyst LLC. Systèmes et procédés pour générer de la vapeur surchauffée avec un gaz de combustion variable pour une récupération améliorée de pétrole
CA2972203C (fr) 2017-06-29 2018-07-17 Exxonmobil Upstream Research Company Solvant de chasse destine aux procedes ameliores de recuperation
CA2974712C (fr) 2017-07-27 2018-09-25 Imperial Oil Resources Limited Methodes ameliorees de recuperation d'hydrocarbures visqueux d'une formation souterraine comme etape qui suit des procedes de recuperation thermique
CA2978157C (fr) 2017-08-31 2018-10-16 Exxonmobil Upstream Research Company Methodes de recuperation thermique servant a recuperer des hydrocarbures visqueux d'une formation souterraine
CA2983541C (fr) 2017-10-24 2019-01-22 Exxonmobil Upstream Research Company Systemes et methodes de surveillance et controle dynamiques de niveau de liquide
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US8414666B2 (en) 2009-12-18 2013-04-09 Air Products And Chemicals, Inc. Integrated hydrogen production and hydrocarbon extraction
US8240370B2 (en) 2009-12-18 2012-08-14 Air Products And Chemicals, Inc. Integrated hydrogen production and hydrocarbon extraction
WO2013058822A1 (fr) * 2011-06-10 2013-04-25 Exxonmobil Upstream Research Company Procédés et systèmes pour fournir de la vapeur
US9593563B2 (en) 2011-10-05 2017-03-14 Statoil Petroleum As Method and apparatus for generating steam for the recovery of hydrocarbon
CN102854294A (zh) * 2011-10-17 2013-01-02 中国石油天然气股份有限公司 用于检测油田注过热蒸汽工艺中水质标准的系统及方法
US9359868B2 (en) 2012-06-22 2016-06-07 Exxonmobil Upstream Research Company Recovery from a subsurface hydrocarbon reservoir
WO2014066034A1 (fr) * 2012-10-24 2014-05-01 Conocophillips Company Production directe de vapeur de purge de chaudière
US20140224192A1 (en) * 2013-02-13 2014-08-14 Lawrence E. Bool, III Steam quality boosting
US9328601B2 (en) 2013-04-30 2016-05-03 General Electric Company System and method for enhanced recovery of oil from an oil field
CN104763998A (zh) * 2015-03-11 2015-07-08 中国石油大学(华东) 余热两级回收型分体式蒸汽发生装置
CN104763998B (zh) * 2015-03-11 2016-07-06 中国石油大学(华东) 余热两级回收型分体式蒸汽发生装置
CN109964081A (zh) * 2016-11-02 2019-07-02 西门子股份公司 蒸发器系统
CN109964081B (zh) * 2016-11-02 2020-10-20 西门子股份公司 蒸发器系统
US10907823B2 (en) 2016-11-02 2021-02-02 Siemens Aktiengesellschaft Evaporator system

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CA2621991A1 (fr) 2008-11-19

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