Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH DRILLING; MINING
  • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/34—Arrangements for separating materials produced by the well
  • E21B43/36—Underwater separating arrangements
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH DRILLING; MINING
  • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/34—Arrangements for separating materials produced by the well
  • E21B43/40—Separation associated with re-injection of separated materials

Definitions

• the present invention relates to a method and system for handling production fluid extracted from a hydrocarbon reservoir.
• production fluid comprising hydrocarbon fluid and water
• production fluid comprising hydrocarbon fluid and water
• the reservoir may not have enough pressure to drive the production fluid to the host facility.
• a pipeline is provided which conveys injection water from the host facility at a pressure higher than the reservoir pressure to a seabed facility at which it is manifolded to connected water injection wells for injection into the reservoir.
• this increases the percentage of water already in the production fluid which means that the production fluid pipeline to the host facility has to be of a sufficient size to convey production fluid including the water naturally occurring therein and the injected water. This makes such a pipeline expensive.
• a method for handling production fluid comprising the steps of: receiving production fluid in an underwater facility from a hydrocarbon reservoir; separating water from the production fluid in the underwater facility; and disposing of the water below the surface of the water in which the underwater facility is located.
• the production fluid pipeline which connects the underwater facility to the host facility, may be specified to be of a smaller diameter as it only needs to transport water free production fluid to the host facility.
• Removal of the water from the production fluid removes a significant source of corrosion of the production fluid pipeline which may enable the pipeline to be of a lower grade, less noble or cheaper material.
• the removal of the water also reduces the possibility of hydrate formation in the pipeline as the production fluid cools. This results in less chemical injection from the host facility into the production fluid being required.
• a pipeline for supplying the injected chemicals from the host facility to the production fluid pipeline can be reduced in diameter, and less equipment for chemical injection is required at the host facility.
• the pump required can be smaller than that required when the production fluid contains water, as there is less fluid to be pumped to the host facility.
• the invention provides considerable cost savings. There are also savings in deck space on the host facility and in the weight to be supported by the host facility.
• the savings in pipeline costs enables longer tie-backs to the host facility to be economically considered which may allow the use of an existing host facility to be used as opposed to having to provide a new host facility. This is of particular benefit when the field to be developed is located beneath deep water.
• the percentage of water in the production fluid continues to increase over the life of the field to the point where the field becomes uneconomic to continue, because the production fluid only comprises a small percentage of hydrocarbons.
• the production fluid pipeline will have spare capacity as it is no longer required to transport water.
• the pipeline enables additional developments of the existing field or developments of a new field to be tied in to the underwater facility to use this spare capacity avoiding the need to lay a new pipeline to the host facility. Any well of a new development may be "daisy chained" to the underwater facility.
• the step of purifying the water separated from the production fluid Before the step of disposing of the water, there may be included the step of purifying the water separated from the production fluid. 5 Before the step of disposing of the water, there may be included the step of measuring the purity of the water. Furthermore, a subsequent step may be included in which the purified water is returned back for further purification when the result of measuring the water purity reveals that it has a purity level below a predetermined threshold level.
• the measuring step may comprise measuring the o amount of oil in water.
• the step of disposing of the water may comprise disposing of the water into the water in which the underwater facility is located.
• the step of disposing of the water may include injecting the water into the reservoir. This may include the additional step of combining the water with 5 injection fluid from a host facility before injection into the hydrocarbon reservoir.
• the water for disposal may be purified before being combined with injection fluid from the host facility to avoid the chemical composition of the water causing undesirable chemical reactions which would affect production.
• the step of disposing of the water may include injecting the water into a 0 disposal well.
• a system for handling production fluid comprising an underwater facility having production fluid separation means for receiving production fluid from a hydrocarbon reservoir and separating water from the production fluid, and 5 disposal means for disposing of the water from the underwater facility to below the surface of the water in which the underwater facility is located.
• the underwater facility preferably includes water purification means for purifying water separated from the production fluid by the separation means before the water is disposed of by the disposal means. o There may be provided a measuring device between the water purification means and the disposal means for measuring the purity of the purified water.
• the underwater facility may have recirculation means for delivering purified water back to the water purification means when the result of measuring the water purity reveals that it has a purity level below a predetermined threshold level.
• the measuring device may measure the amount of oil in the water.
• the measuring device may comprise a photochromatic device.
• the disposal means may be arranged to dispose of the water into the water in which the underwater facility is located.
• the disposal means may include a connector for enabling the disposal means to be connected to a disposal well or to the hydrocarbon reservoir.
• a retrievable module for an underwater processing system the module comprising the system described above.
• the retrievable module enables the equipment within it to be easily recovered for inspection, maintenance or repair without interrupting operations.
• the module may be of the type forming part of the modular system designed by Alpha Thames Ltd of Essex, United Kingdom and named Alpha PRIME.
• Figure 1 is a schematic diagram of a system for putting the invention into practice:
• Figures 2 and 3 are schematic diagrams illustrating modified systems;
• FIGS 4 to 6 are details of Figures 1 to 3, respectively.
• a system 1 has a host facility which may be, for example, onshore or on a fixed or floating rig.
• the host facility 2 is connected to a remote seabed facility 3 by a production fluid pipeline 4 and a water injection pipeline 5.
• the seabed facility 3 is connected to a plurality of wells 6,7 for a hydrocarbon reservoir whereby each well is connected to the facility 3 by a separate flowline 8,9. Some of these wells are production wells 6 and the remaining wells are water injection wells 7.
• the seabed facility 3 has a base structure 10 to which the production fluid pipeline 4 and the water injection line 5 are connected.
• the water injection line 5 is connected to the flowlines 9 to the water injection wells 7.
• the flowlines 8 from the production wells 6 are manifolded to a single conduit 11.
• the base structure 10 supports a retrievable module 12 which is connected to the manifold conduit 11 and the production fluid pipeline 4 by a multi-ported fluid connector 13 such as that described in GB-A-2261271 which enables the module 12 to be isolated from all the pipelines 4,5 and flowlines 8,9 connected to the seabed facility 3 when the module 12 is to be retrieved.
• the manifold conduit 11 is connected to an inlet 14 of a two-phase fluid separator vessel 15 in the module 12 via the fluid connector 13.
• a first outlet 16 of the fluid separator vessel 15 is connected to the production fluid pipeline 4 via the fluid connector 13.
• a second outlet 17 of the vessel 15 is connected to a port 18 on the outside of the module 12 via a fluid clean-up unit 19 and a fluid monitoring device 20.
• An example of such a fluid clean-up unit is the TORE SEP and de-oiling hydrocyclone package available from Merpro Ltd of Bristol, United Kingdom and an example of such a fluid monitoring device is the JORIN VIPA metering device available from Jorin Ltd of Berkshire, United Kingdom.
• the host facility 2 injects water into the hydrocarbon reservoir via the water injection pipeline 5, the flowlines 9 and the water injection wells 7.
• the injected water drives the production fluid at an increased pressure to the seabed facility 3 via the production wells 6 and flowlines 8.
• the fluid separator vessel 15 receives the production fluid 6 from the production wells and separates water from the production fluid.
• the at least substantially water free production fluid leaves the fluid separator vessel 15 by the first outlet 16 and is conveyed to the host facility 2 by the production fluid pipeline 4.
• the separated water leaves the separator vessel 15 by the second outlet 17 and enters the fluid clean-up unit 19 which removes hydrocarbons from the water.
• the cleaned water is then passed through the fluid monitoring device 20, such as a photo-chromatic device, which measures the amount of oil in the water.
• the fluid monitoring device 20 is used to ensure that the cleaned water is sufficiently clean so that it can be disposed of into the sea surrounding the module via the port 18, the cleaned water may be pressure boosted by a pump 24 before disposal. If the water is measured to 5 contain more than the legislated allowable maximum limit of oil in water then the water is not sufficiently clean for disposal and is instead returned to the fluid clean-up unit 19 for further cleaning via the recirculation pipe 21.
• FIGs 2 and 5 illustrate one modification to the system 1.
• the second outlet 17 of the fluid separator vessel 15 is connected by a conduit 23 to the water injection pipeline 5 at the base structure 10 via the pump 24, the fluid connector 13 and a non-return valve 28, the latter 5 preventing fluid from the pipeline 5 from entering the separator vessel 15 via the second outlet 17.
• the water injection pipeline 5 has a non-return valve 29 upstream of the conduit 23 connected to the separator vessel 15. This prevents separated fluid from the separator vessel 15 flowing up the pipeline 5 towards the host facility 2.
• the non-return valves 28,29 have been o omitted from Figure 2 for clarity.
• water separated from the production fluid is conveyed by the conduit 23 into the water injection pipeline 5 where it is combined with water from the host facility 2 for injection into the hydrocarbon reservoir via the water injection wells 7.
• FIGs 3 and 6 illustrate a modification to the system 22 shown in Figure 5 2.
• a disposal well 26 is connected to the base structure 10 by a flowline 27 and the second outlet 17 of the separator vessel 15 is connected to this flowline 27 via the pump 24 and the fluid connector 13.
• the disposal well 26 may, for example, inject water into the hydrocarbon reservoir or into an aquifer beneath the seabed and there may be a plurality of disposal wells connected to the base structure 10 of the seabed facility.
• seabed facility 3 may be located at a wellhead of a well.
• the pipelines and flowlines described may be of rigid or flexible construction.
• a pump may not be required to pump water into the sea. However, this is dependent upon the depth of the seabed facility where a pump is more likely to be required at greater depths.

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Publications (1)

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• 2001
  • 2001-10-12 GB GBGB0124615.6A patent/GB0124615D0/en not_active Ceased
• 2002
  • 2002-10-11 WO PCT/GB2002/004630 patent/WO2003033869A1/en not_active Application Discontinuation
  • 2002-10-11 EP EP02801385A patent/EP1446553A1/de not_active Withdrawn
  • 2002-10-11 US US10/491,875 patent/US20050034869A1/en not_active Abandoned
  • 2002-10-11 BR BR0213622-8A patent/BR0213622A/pt not_active IP Right Cessation
• 2004
  • 2004-05-11 NO NO20041927A patent/NO20041927L/no unknown

Non-Patent Citations (1)

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