WO2012127295A1 - Procédé de récupération de pétrole brut - Google Patents

Procédé de récupération de pétrole brut Download PDF

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Publication number
WO2012127295A1
WO2012127295A1 PCT/IB2012/000505 IB2012000505W WO2012127295A1 WO 2012127295 A1 WO2012127295 A1 WO 2012127295A1 IB 2012000505 W IB2012000505 W IB 2012000505W WO 2012127295 A1 WO2012127295 A1 WO 2012127295A1
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Prior art keywords
stream
crude
gas
stabilized
crude oil
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PCT/IB2012/000505
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English (en)
Inventor
Arul JOTHY
Boon Lee Ooi
Weng Loong HUM
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NGL Tech Sdn Bhd
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NGL Tech Sdn Bhd
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Priority to BR112013023909A priority Critical patent/BR112013023909A2/pt
Priority to US14/004,968 priority patent/US20140001097A1/en
Publication of WO2012127295A1 publication Critical patent/WO2012127295A1/fr
Anticipated expiration legal-status Critical
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/12—Liquefied petroleum gas
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
    • C10G31/08—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by treating with water
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
    • C10G70/04—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes
    • C10G70/043—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes by fractional condensation

Definitions

  • the invention relates to the production of crude oil, and in particular to the maximizing the recovery of stabilized crude oil from an oil and gas producing facility.
  • Raw natural gas comes from predominantly two types of wells: oil wells and gas wells. Natural gas that comes from oil wells is typically termed "associated gas”. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude oil
  • Natural gas from gas wells in which there is little or no crude oil, is termed "non-associated gas". Gas wells typically produce raw natural gas along with a semi-liquid hydrocarbon condensate. Whatever the source of the natural gas, once separated from the associated liquid it commonly exists in mixtures of predominantly methane and ethane and other hydrocarbons; principally propane, butane, and pentanes. Natural gas coming directly from a well contains many natural gas liquids that are commonly removed. In most instances, natural gas liquids (NGL's which includes ethane, propane, butanes and pentanes) have a higher commercial value as separate products, and it is thus economical to remove them from the gas stream.
  • NNL's which includes ethane, propane, butanes and pentanes
  • the processes for removal of natural gas liquids are relatively complex requiring gas pretreatment facilities like C0 2 removal systems and gas dehydration, NGL extraction processes like lean oil absorption or cryogenic expander processes, NGL processing and fractionation facilities like de-methanizer, de-ethanizer, de-propanizer, de-butanizer and butane splitter.
  • gas pretreatment facilities like C0 2 removal systems and gas dehydration
  • NGL extraction processes like lean oil absorption or cryogenic expander processes
  • NGL processing and fractionation facilities like de-methanizer, de-ethanizer, de-propanizer, de-butanizer and butane splitter.
  • pressurized storage and off-loading facilities are also required. This results in facilities, where NGL extraction and processing are undertaken, being very complex with significant safety issues and requires large real estate with significant capital investment. For these reasons these processes are generally built as centralized processing plants and are not considered particularly for offshore facilities and many onshore developments.
  • C4+ components particularly LPGs (C 4 's) are cumbersome to handle in many cases, as they predominantly cannot be stabilized with the light condensate stream and, cannot be spiked into the export gas stream due to export gas dew point limitations.
  • these valuable hydrocarbon components that can neither be spiked into the export gas stream or the stabilized condensate stream are utilized within the site as fuel gas or flared.
  • pipeline gas export dew-point specifications are less stringent, many gas producers export significant quantities of C4+ components with the sales gas instead of recovering the NGLs. In this case, the revenue earned is solely from the heating value (BTU) of the gas which is significantly lower than what it would be worth as liquids.
  • NGL extraction facilities there are a number of new technologies that are being considered for the processing and utilization of the associated gas. These include mini LNG, Gas to Liquid (GTL), Compressed Natural Gas (CNG) and Gas to Solid processes.
  • GTL Gas to Liquid
  • CNG Compressed Natural Gas
  • the invention provides a method for the production of stabilized crude oil, the method comprising the steps of: providing a stream of crude oil; injecting steam into said stream and so stripping C3- from said stream; providing a gas stream;
  • the invention provides a system for the production of stabilized crude oil comprising: a steam injection station arranged to receive a stream of unstabilised crude oil, said station arranged to subject said stream to an injection of steam; said steam injection station including a first outflow to deliver a stripped stream of crude to a stabilizer and a second outflow to deliver a flow of gas to a condensation station; said condensation station arranged to condense the gas to produce a condensate, said station further including an outflow to direct the condensate to the stabilizer for comingling the condensate with the stripped stream of crude; wherein the stabilizer is arranged to outflow a stream of stabilized crude resulting from said comingled streams.
  • the invention provides A system for stripping light components from a crude oil stream, comprising a crude stripping column for receiving the crude oil stream, said column arranged to receive steam for applying to the crude oil stream; a surge vessel for receiving the stripped crude stream and arranged to separate water from said stripped crude stream; wherein the surge vessel and crude stripping column are selectively coupled so as on de-coupling the crude oil stream is permitted to by-pass the crude stripping column and flow directly into the surge vessel. Therefore, the invention provides a process and system that maximizes the absorption of C4+ components into the stabilized crude stream.
  • the process involves three operating steps where the crude is first stripped of C3- components. Heavy components, such as C4+, that are in a gas stream are extracted through condensation of the hydrocarbons, which may be through use of a dew-point control system, said control system may further be coupled with a de-propanizer.
  • the process configuration and controls may be such that irrespective of the amount or proportion of crude and condensate produced, the amount of C4+ components in the stabilized product stream is maximized and the amount of C3- components minimized.
  • An advantage of the recovery of this process includes the minimization of the amount of propane and lighter molecular weight components in the stabilized crude stream, which will enable larger quantities of C4+ components to be absorbed into the crude stream and thus improve stabilized crude recovery, among others, whilst maintaining the TVP/RVP specification of the stabilized crude.
  • FIG. 1 is a flow chart of a process according to one embodiment of the present invention.
  • Figure 1 A is a sequential table of results during the process according to one
  • Figure 2 is a schematic view of a stabilization system according to a further embodiment
  • FIG. 3 is a schematic view of an LPG and condensate stabilization system according to the prior art
  • Figure 3 A is a schematic view of multi-stage separation system according to the prior art
  • Figure 3B is a schematic view of a multi-stage Separation and Condensate stabilization system according to the prior art
  • Figure 4 is a schematic view of crude stabilization system according to one embodiment of the present invention.
  • Figure 5 is a schematic view of a crude stripping column according to one embodiment of the present invention.
  • Figure 6 is a graph of equivalent volumetric light components (C3-) in stabilized crude oil comparing the prior art to an example of the present invention
  • Figure 7 is a further graph of equivalent volumetric heavy components (C4+) in stabilized crude oil comparing the prior art to an example of the present invention
  • Figures 8A to 8D are pie charts comparing the recovery rate of C4+ of the prior art processes compared with an example of the present invention.
  • the process according to the present invention may increase the recovery of oil by between 5 to 30% over conventional processes. This is achieved by using crude oil and/or condensates from production wells to absorb intermediate hydrocarbon components (C4+) from a natural gas stream whilst maintaining the stabilized crude product within its vapor pressure specifications (TVP/RVP). This also results in improved crude oil quality (increased API gravity, reduced viscosity) and reduction of greenhouse gas emissions by up to 50% depending on whether associated gas is flared and due to the use of leaner fuel gas.
  • the process according to the present invention may also reduce environmental emissions of hydrocarbon gases and safety issues due to vaporization of volatile hydrocarbon components (CI, C2 and C3) from stabilized crude in the storage tanks by minimizing these components in the stabilized crude.
  • the present invention may be applicable for both onshore and offshore installations.
  • the present invention may also be suitable for facilities where it is not economically viable to install a gas plant with NGL or LPG extraction facilities.
  • FIG. 1 shows a flow chart of one embodiment of the present invention.
  • the process 5 is carried out in three main steps:
  • the unstabilised crude 10 is stripped of propane and lower molecular weight components in a steam stripping column 15 using superheated steam and operated in the range of 0.5 barg to 5 barg. This operation step also strips out salts from the crude stream prior to the crude being routed to the electrostatic coalesce. Thus the process also carries out desalting of the crude.
  • This section 25 of the process extracts C4+ components and condensates from the associated and/or non-associated gas streams 20 whilst expelling 30 lighter components from the condensate stream using a depropanizer column.
  • NGLs from associated and non-associated gas stream 20, laden with C3+ components stripped from the crude stream, is extracted from the gas stream using either a conventional dew-point control system or membranes and the condensate is routed to a de-propanizer column to produce condensate 35 predominantly laden with C4+ components.
  • condensate extracted from the condensate recovery section may be routed to the stripping column surge vessel. This may avoid the need for a flash vessel downstream.
  • the operating pressure and temperature of the fluid in the surge drum may be adjusted such that the crude/condensate mix existing the surge drum meets the TVP specifications. This may be achieved by adjusting the temperature of the condensate stream from the condensate recovery section using a cooler. Crude and Condensate Mixing and Stabilization Section
  • Condensate Recovery Section 25 are both routed to the Crude and Condensate Mixing and Stabilization Section 40.
  • the crude and condensate are mixed, cooled and routed 45 to the Flash Vessel.
  • the Flash Vessel is operated at a temperature and pressure such that the liquids produced are stabilized to meet the TVP/RVP specification of the product.
  • offgas produced from the flash vessel is maintained at a preset value by adjusting the reboiler temperature of the de-propanizer column.
  • the reboiler temperature of the depropanizer column controls the amount of C3/C4 component split in the column bottoms product and the column overhead gas stream, thus ensuring that the amount of C4s in the condensate stream is maximized without generating significant flash gas when the crude and condensate are comingled.
  • This process configuration maximizes the recovery of stabilized crude and ensures that valuable liquids from the associated and non-associated gas streams are recovered as stabilized product suitable for storage in atmospheric tanks.
  • the process is particularly suitable for facilities that handle difficult crudes that includes crudes that are waxy, highly emulsifying, high salt content and/or with high asphaltene content. This is because the process is configured to operate the crude processing section at high temperature (above wax appearance temperature and above emulsion breaking temperature) and is stripped of its light ends when operating at high temperature, thus minimizing risk of asphaltene deposition at the high temperatures in the steam stripping column.
  • steam stripping of the crude also functions to water wash the crude, thus diluting salt concentrations. This minimizes risk of scale and salt deposition in the system and significantly enhances the performance of the downstream electrostatic coalescer. Foaming tendencies of the crude is also minimized both due to the dilution effect of condensed steam on the salts and also due to the stripping action that reduces the light end content in the crude.
  • the Condensate Recovery Section maximizes the recovery C4+ components thus ensuring that the final crude and condensate that is mixed in the Crude and Condensate Mixing and Stabilization Section has maximum C4+ components and thus maximum stabilized liquid recovery within its TVP and RVP specification.
  • the heat duty and column size is minimized compared to the case when crude is routed to a stabilizer column.
  • condensates extracted are clean, issues associated with fouling of the reboiler tubes are avoided.
  • the temperature at which the mixing occurs can be adjusted by appropriately pre-cooling the gas and condensate stream prior to mixing at the Crude and Condensate Mixing and Stabilization Section.
  • the present invention uses the ability of crude oil to absorb some of the C3 components and essentially all the C4+ components from the gas stream and to retain within the stabilized crude oil product these valuable NGL products. This results in increased stabilized crude oil recovery and improved quality of crude, namely, higher API gravity and reduced crude oil viscosity.
  • the crude is progressively loaded with C3+ components present in the associated gas stream until the crude TVP is back up to 12 psia. With this operation the overall crude volume increases by 7.3%. If further, the crude is stripped of the C3 components and loaded with C4+ components up to its TVP limit of 12 psia, the crude volume increases by a total of 10.6%.
  • the overall crude quality also improves in the process with API gravity of crude increasing from 40.4 to 44.1 and the viscosity of crude reducing from 1.95 cP to 1.45 cP.
  • the process utilizes this concept to absorb C4+ components from the natural gas stream.
  • the absorbent crude oil stream that has been stripped of C3- components is mixed with condensate that has been de-propanized to a level that allows the mixture of crude and condensate to meet the TVP/RVP specification of the stabilized liquid.
  • FIG. 2 shows a schematic view of a system according to one embodiment of the present invention.
  • Full well stream crude 55 with associated gas and produced water is routed to the Inlet Separator 65 where 3 phase separation is carried out.
  • the Inlet Separator 65 is typically operated in the range of 5 to 20 barg and a temperature in the range of 60°C for emulsion breaking.
  • Crude oil from the Inlet Separator is then heated via a crude-crude heat exchanger 70 by the hot crude/condensate stream from the downstream system 90 to recover as much heat as possible from the hot stream.
  • the crude is then letdown in pressure, typically in the range of 0.5 to 4 barg and then fed to the crude stripping column 80.
  • the operating pressure of the crude stripping column 80 is set at as low a pressure as possible at approximately the same pressure as the downstream Flash Vessel 110. This is to minimize steam requirements and to enable common suction pressure to the Flash Gas Compression train 140.
  • the stripping column 80 may be operated at a higher pressure to enable inter-stage feed to the Flash Gas Compressors.
  • Superheated stripping steam 90 is fed at the base of the column 80.
  • the amount of superheated steam used is dependent on the composition of the crude and operating pressure of the column but is typically approximately 1 lb steam per gallon of crude feed to the stripping column.
  • the number of theoretical trays used is in the range of 3 to 10 theoretical stages.
  • the number of theoretical trays used is a tradeoff between steam consumption requirements, compression power and column height to minimize the amount of C3- components in the stripped crude stream whilst the C4+ components are maximized.
  • the temperature of the bulk crude at the bottom of the stripping column is typically maintained within approximately 100°C.
  • the temperature of the steam supply should be such that localized decomposition of crude (when in contact with hot superheated steam) is minimized whilst high enough to provide sufficient heat and minimize steam consumption for stripping.
  • steam supply temperature is in the range of 120 to 180°C and includes a superheat of approximately 30°C.
  • the process 50 selectively displaces the light (C3-) components in the crude whilst maintaining as much of the C4+ components within the crude stream. Nonetheless, the overall process is configured such that any C4+ components that are stripped out of the crude in this section are recovered from the gas stream in the dew-point control section 130 of the process. As such, the main objective of this section of the process is to strip as much of the C3- components from the crude stream. As a result, the vapor pressure of the crude is dropped to well below the TVP/RVP specification of the stabilized crude.
  • the use of steam stripping minimizes the temperature rise of the crude during the stripping process, thus minimizing decomposition of the crude and preventing coking. It also avoids the need for a reboiler which for dirty and fouling crude with high asphaltene content, will cause scale and asphaltene deposition at the reboiler tubes.
  • the steam stripping column can be a conventional column with trayed, structured, random packing or other internals suitable to promote vapor liquid contact.
  • a liquid hold-up boot is required to provide sufficient liquid residence time for vapor liquid separation and to provide adequate surge volume for the downstream pump.
  • the column 80 may be configured as shown in Figure 2. This column configuration enables the system 50 to be operated as a conventional separation train when the column is off-lined for maintenance, etc. It also results in a shorter column as liquid handing is accommodated in the surge vessel 85. This particularly suited for a floating facility where the motion effects can significantly impair the performance of tall columns.
  • crude from the downstream crude transfer pumps may be recycled to the stripping column to ensure that minimum column turndown is not exceeded.
  • Offgas from the crude stripping column depending on the operating pressure is either comingled with offgas from the downstream Flash Vessel 110, is cooled and routed to the Flash Gas Compression Train 140.
  • the stripping column 80 is operated at a higher pressure than that of the Flash Vessel 110, the offgas from the stripping column may be cooled and routed to the inter-stage of the Flash Gas
  • Hot stripped crude from the Stripping Column is routed to the Stripping Column Surge Vessel where 3 phase (gas, crude and water) separation is performed. Any gas separated is comingled with superheated stripping steam and routed to the Stripping Column. Crude is discharged from the vessel under level control via a pump to the electrostatic coalescer.
  • the process recovers C4+ components from the associated and non-associated gas streams.
  • the condensates may be extracted from the gas stream by a dew-point control system using JT-Valve, turbo-expander, mechanical refrigeration, membranes or a combination. Liquids recovered from the dew-point control system 135 and possibly the compression train scrubbers are letdown in pressure and routed to de-propanizer column.
  • the reboiler temperature of the depropanizer 145 is set to maximize the recovery of C4+ components.
  • the de-propanizer column 145 rejects into the overhead gas stream, most of the C3 and lower molecular weight components whilst the C4+ components are routed to the column bottoms.
  • the TVP of the column bottoms is adjusted, such that, when the condensate comingles with the crude stream, the combined crude and condensate stream TVP/RVP (typically approximately 12 psia) specification is met. This is accomplished by adjusting the reboiler temperature set-point.
  • a flash gas flow control signal from the Crude Condensate Mixing and Stabilization section of the process provide a cascade control set-point to reboiler temperature controller.
  • the process is essentially configured such that the condensate is stabilized (in the depropanizer column 145) to a level that is just adequate that the TVP/RVP of the combined crude and condensate product stream meets the storage and export specification.
  • the depropanizer column will ensure that light ends from the condensate stream are displaced into the offgas stream and heavier ends are routed to the column bottom stream.
  • the Depropanizer column 145 can be a conventional column with trayed, structured, random packing or other internals suitable to promote vapor liquid contact.
  • a liquid hold-up boot is required to provide sufficient liquid residence time for vapor liquid separation and to provide adequate surge volume for the downstream pump.
  • Crude that is stripped of C3- components in the Crude Stripping Section of the process is then routed to the electrostatic coalescer 100, if required, to dehydrate the crude to meet crude BS&W content.
  • the steam stripping operation also functions to water wash the crude and thus enhances the operation of the electrostatic coalescer 100.
  • the dewatered crude is then comingled with condensate from condensate de-propanizer.
  • mixing of the crude and condensate streams can be done upstream of the electrostatic coalescer 100. In this case, the condensate may need to be pre-cooled and the operating pressure of the electrostatic coalescer maintained such that vapor break-out will not occur within the electrostatic coalescer.
  • the mixed stream is then routed to the crude-crude heat exchanger 70 for heat recovery and then to a cooler 105 before the pressure is letdown typically to a pressure of approximately 0.5 to 1 barg.
  • the operating pressure is such that there will be sufficient head for the liquid to overcome the downstream system pressure drop en-route to storage.
  • the fluid is then routed to a flash vessel 110 for vapor liquid separation.
  • the operating temperature of the flash vessel is set such that crude and condensate mix will be stabilized to the desired TVP/RVP specification. Typically, the temperature is set at approximately 60 to 70°C.
  • Offgas from the Flash Vessel is comingled with offgas from the stripping column, cooled and routed to the flash gas compression train.
  • the offgas rate from the Flash Vessel is always maintained at a pre-set value, typically at approximately 0.5 to 1 MMscfd. This is done by means of a cascade control loop, where the flow controller output of the offgas from the Flash Vessel is used as the control set point of the depropanizer reboiler temperature controller. This ensures that the amount of butanes (C4s) that is extracted from the condensates routed to the depropanizer column is maximized to the limit that can be handled by the mixed crude and condensate stream whilst meeting the TVP/RVP specification.
  • the process of the present invention has application in production facilities where crude and gas are produced simultaneously and where it is not economical to install conventional NGL extraction facilities.
  • the case study in the following sub-section demonstrates how the process of the present invention can be used on facilities that produce and process non-associated gas and crude in parallel.
  • FIG. 1 A LPG facility designed for a nominal capacity of 170 MMscfd of export gas, 10,000 bpd of LPG and 34,000 bpd of crude oil.
  • Figure 3 shows typical mixed LPG extraction and condensate stabilization system 155. The process utilizes multistage separation 165, 175, 185 to stabilize the condensate. Off-gas from the multi stage stabilization system is re-compressed 195, 200 and co- mingled with non-associated gas. The gas will be treated and dehydrated to the water dew point specification.
  • Condensate rich in LPG components will be extracted at the hydrocarbon dew point control unit 225.
  • the condensate is then routed to the LPG fractionation unit 255.
  • the LPG fractionation unit consist de-ethanizer and debutanizer columns 255 to produce mixed LPG and stabilized condensate products.
  • the stabilized condensate will mix with stabilized crude oil and send to oil storage tank whereas the LPG 260 will be stored in pressurized LPG bullets or refrigerated tanks.
  • Table #1 Material Balance for LPG and Condensate Stabilization System (Dry
  • a multi stage separation is a more commonly used process configuration for offshore facilities due to its simplicity and as traditionally the industry focus has not been to enhance recovery of stabilized liquid and reduce environmental emissions at the expense of capital expenditure (CAPEX) and facility complexity. It comprises several stage of separation and heating to separate water and gas and in the process stabilizes the crude oil to the specified TVP specification. Commonly, flash gas compression will be installed to recovery vapor from the liquid separation train.
  • Figure 3 A shows typical configuration of 3 stage separation system. Considering the same inlet feed stream, the following tabulation gives the material balance of pertinent streams for the process depicted in the figure above.
  • Table #2 Material Balance for Conventional Multi Stage Separation System (Dry Basis)
  • This process configuration is similar to above multi stage separation and stabilization but has in addition a hydrocarbon dew point control unit and condensate stabilizer column.
  • the condensate (C4+ components) is extracted from gas stream at the dew point control unit and routed to stabilizer column to where the condensate is stabilized to meet the required TVP specification.
  • the stabilized condensate will then be comingled with the stabilized crude oil from the separation train. The comingled stream is then cooled prior to being routed to the storage tanks.
  • Figure 3B shows a typical configuration of the system with 3 stages of separation plus a condensate stabilization system. Considering the same inlet feed streams, the following tabulation gives the material balance of pertinent streams for the process depicted in the figure above.
  • Table #3 Material Balance for Conventional Multi Stage Separation Plus Condensate Stabilization System (Dry Basis)
  • Figure 4 shows a process configuration of one embodiment of the system of the present invention.
  • the system comprises of a dew-point control system 225 for condensate extraction 230, a condensate depropanizer column 250 and at the crude handling side, a crude steam stripping column 171 in which the liquid surge and residence time for vapour liquid separation is achieved.
  • Table #4 Material Balance for a System of the Present Invention (Dry Basis)
  • Table #5 gives the comparison in terms of product recovery and properties of the product stream for the above four process configurations considered.
  • the system of the present invention recovered the most amount of stabilized crude, in the range of an incremental production of 460 to 2220 bpd compared to the other 3 processes with improved stabilized crude properties (lowest RVP/TVP, highest crude API gravity and lowest crude viscosity).
  • RVP (psia) 9.0 9.0 9.0 8.7
  • Total heating duty included 8000 kg/h of superheated steam for stripping.
  • LPG recovery With LPG recovery, the incremental crude recovery is significant, approximately 1 ,760 bpd compared to a multi-stage separation system. In addition, approximately 9200 bpd of mixed LPG is also produced. There appears to be significant merits to installing LPG recovery facilities for this case study.
  • both CAPEX and OPEX are significantly increased.
  • dedicated LPG storage and offloading facilities usually provided by dedicated FSOs, are also required.
  • OPEX includes additional manning for the LPG recovery and fractionation facilities, LPG storage FSO and dedicated shuttle tankers for LPG transport.
  • LPG storage and offloading facilities offshore significantly increases the facility complexity, risk and HSE (Health, Safety and Environment) profile of the facility. For these reasons these facilities are seldom installed offshore unless in few cases where there is significant economic drivers for LPG storage and recovery.
  • this embodiment of the present invention is significantly less complex and does not require LPG storage and offloading facilities.
  • Figure 5 shows a detailed view of the crude stripping column system 273. Further details show the unstabilised crude stream, having being separated from a multiphase crude stream, with the entry of the superheated steam 295 into the base of the stripping column 280, and the outlet of the stabilized crude 291 to be co-mingled with the condensate stream.
  • a feature of the crude stripping column system of Figure 5 is that it may be used with the stabilized system of Figure 4, or as a separate invention in its own right with a different system. Accordingly, a crude stripping arrangement of the prior art may be replaced by the coupled system 273 shown in Figure 5, whereby the column 280 is selectively coupled to the surge vessel 285. It follows that, in this arrangement, the addition of selectively operable valves 277, 278 permit by-passing of the column 280 and allows the remaining surge vessel 285 to act as a conventional 3 stage separation system. Thus the flexibility provided by the selective coupling offers significant advantage in savings of capital infrastructure and operating cost.
  • the column height is significantly reduced as the liquid hold-up requirements are now housed in a separate vessel. This is particularly beneficial for floating facilities where tall columns can impair its performance.
  • Figure 6 shows equivalent volumetric light components (propane, ethane and lighter) in the stabilized oil.
  • LPG extraction process 315 conventional three stages separation process 320 and three stages separation plus condensate stabilization process 325, due to the inherent in-efficiency of a multi-stage stabilization process for the crude stream, small quantities of ethanes 335 and propanes 340 remain in the crude stream. Although relatively small quantities, due to their high vapor pressure, these components significantly contribute to the increase in the vapor pressure of the stabilized liquid product. This results in high vaporization losses at the storage tanks which in-turn results in shrinkage of crude in the storage tanks and hydrocarbon venting at the storage tank vents.
  • Figure 8 A shows a pie chart providing percentage of C4+ recovery in the conventional 3 stage separation process. Approximately 84.7% of C4+ is recovered in the crude oil, but 15.3% of C4+ is not recovered and end up in the export gas stream. This process configuration gives very low recovery of stabilized liquids and in many cases results in export gas not meeting the dew-point and Wobbe Index specification of export gas. The 3 stage separation process is thus the most inefficient among the four processes mentioned.
  • Figure 8D shows 91.4% of C4+ is recovered in crude oil by the present invention process which gives the highest recovery of C4+ components in the stabilized crude product stream among all the four processes considered.
  • the process Apart from increasing the stabilized crude recovery by approximately 7% over a conventional 3 stage separation process (which is by far the most widely used system offshore), the process also correspondingly leans-out the export gas by reducing the C4+ content thus enabling typical export gas dew-point and Wobbe index specification to be met.
  • the system and process of the present invention introduces a process configuration which may increase stabilised liquid yield from an oil and gas processing facility by as much as 30% more than that achievable using a conventional and widely used multistage separation process.
  • Advantages of the present invention may include:
  • Incremental stabilized crude recovery is approximately 5 to 30% of that using a conventional multistage separation system.
  • the process also improves the quality of the crude by increasing its API gravity and reducing its viscosity. This is due to the increased amount of intermediate hydrocarbons (C4s and C5s) in the stabilized crude stream.
  • the steam stripping process also reduces the salt content in the crude as it essentially water washes the crude.
  • Export gas and fuel gas quality is also improved as much of the C4+ components in the gas stream is removed and absorbed into the stabilized crude stream thus improving the gas dew-point specifications and the Wobbe Index of the export and fuel gas.
  • the process strips out volatile hydrocarbon components (CI , C2 and C3) from the crude stream, thus, producing stabilized crude stream with low vapor pressure and with minimal volatile hydrocarbons. This significantly reduces greenhouse gas emissions at the storage tanks. As gas and fuel gas is leaner, the process also reduces
  • Foaming tendencies of the crude is also minimized both due to the dilution effect of condensed steam on the salts and also due to the stripping action that reduces the light end content in the crude.
  • the process is configured to operate the crude processing section at high temperature (above wax appearance temperature and above emulsion breaking temperature) and is stripped of its light ends when operating at high temperature, thus minimizing risk of asphaltene deposition at the high temperatures in the steam stripping column. This makes the process suitable for virtually all types of crudes, including very heavy crudes.
  • the process minimizes the amount of intermediate hydrocarbons (NGLs) in the gas stream by absorbing these components into the stabilized crude stream. This effectively minimizes the recycling of intermediate hydrocarbon components that is recycled as the gas is dew-pointed to meet export gas specifications (depending on requirement). This in turn reduces the amount of gas compression power, heating and cooling duty requirements.
  • NNLs intermediate hydrocarbons
  • the process is suitable for implementation in virtually all oil and gas processing facilities where crude is to be stabilized for storage or pipelined under pressure. It is may be suited for crudes like waxy crudes, crudes with high asphaltene content, crudes with high salt content and with scaling and foaming tendencies, etc. This is because the process includes stream stripping which also water washes the crude, avoids the use of reboiler for the crude handling system and maintains the temperature of the crude stream hot whilst ensuring that C4+ components absorbed into the crude stream is maximized.
  • the process may be suitable for facilities for which it is not techno-economically viable to pipeline produced gas to a centralized gas processing plant with LPG recovery facilities or install an LPG recovery plant with the associated LPG storage and offloading facilities.
  • This includes facilities where gas is re-injected or flared, marginal field developments and for developments in remote locations.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L'invention concerne un procédé de production de pétrole brut stabilisé, qui comporte les étapes consistant à: prévoir un écoulement de pétrole brut; injecter de la vapeur dans ledit écoulement et extraire ainsi le C3- de l'écoulement; prévoir un écoulement de gaz; extraire le C4+ de l'écoulement de gaz, et produire ainsi un écoulement à partir du C4+ extrait; mélanger entre eux l'écoulement strippé et l'écoulement de C4+ afin de produire ainsi un écoulement de pétrole brut stabilisé.
PCT/IB2012/000505 2011-03-18 2012-03-16 Procédé de récupération de pétrole brut Ceased WO2012127295A1 (fr)

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BR112013023909A BR112013023909A2 (pt) 2011-03-18 2012-03-16 processo para recuperação de petróleo bruto
US14/004,968 US20140001097A1 (en) 2011-03-18 2012-03-16 Process for the recovery of crude

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MYPI2011001234 2011-03-18

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US10260010B2 (en) 2017-01-05 2019-04-16 Saudi Arabian Oil Company Simultaneous crude oil dehydration, desalting, sweetening, and stabilization
US10533404B2 (en) * 2017-11-21 2020-01-14 Phillips 66 Company Processing of oil by steam addition
US10370948B2 (en) * 2017-11-21 2019-08-06 Phillips 66 Company Processing of oil by steam addition
US10125590B1 (en) * 2017-11-21 2018-11-13 Phillips 66 Company Processing of oil by steam addition
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