Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK 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
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK 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
  • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
  • E21B17/01—Risers
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK 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
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK 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
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B23/00—Pumping installations or systems
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
  • F04B49/00—Control, e.g. of pump delivery, or pump pressure of, or safety measures for, machines, pumps, or pumping installations, not otherwise provided for, or of interest apart from, groups F04B1/00 - F04B47/00
• • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
  • F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
  • F04D—NON-POSITIVE-DISPLACEMENT PUMPS
  • F04D13/00—Pumping installations or systems

Definitions

• the present invention relates to the transport of fluid through pipes, and in particular, relates to apparatus for transporting and supplying fluid to a processing facility through at least one section of pipe, and related methods.
• fluid produced from a production well is commonly transported through a transport pipeline to a downstream processing facility where the fluid is processed to turn it into a processed product of desired characteristics.
• the fluid may be led to a receiving facility positioned in the vicinity of the well.
• a receiving facility may facilitate servicing of the well.
• the receiving facility may be in the form of a wellhead platform, and may have well slots allowing access to the wells.
• the receiving facility may typically be provided with a production header to which several flow lines carrying production fluid can be connected, such that the production fluid from the connected flow lines gathered at the production header can be combined together.
• Each flow line may connect with a different well or set of wells in the field.
• such a flow line may be in the form of a production riser extending between the seabed and the well head platform.
• the fluid may be led into a long-distance transport pipeline, typically several kilometres in length, toward the processing facility.
• the processing facility is typicaliy located far away from the locality of the well and/or the receiving facility which initially receives the fluid from the well.
• the fluid from the well is typically transported from the wellhead platform to the processing facility through a pipeline on the seabed.
• the pipeline may then be connected to the processing facility through a pipeline riser which extends upward in the water column from the pipeline to the processing facility at the surface.
• the produced fluid from the well is multiphase, in that it comprises significant amounts of both liquid and gas, often also with solids entrained, and tends to flow in a multiphase regime.
• the produced fluid may typically contain a combination of components such as crude oil, water, and gas from a hydrocarbon reservoir, and other material from the well.
• a multiphase flow may establish itself in the pipeline.
• Multiphase flow can present challenges, dependent upon many factors, such as the proportion and type of constituents of the flow (e.g. the relative amounts of oil and gas), whether the constituents are in gas or liquid phase, physical conditions, and/or structural configuration such as the size of pipe, etc. Complications can occur when transporting multiphase fluid through a pipeline.
• the fluid may tend to stratify into layers with heavier constituents running along the base of the pipe with lighter constituents above.
• water would typically be overlain in succession by oil and then by gas.
• material from the flow of fluid may deposit in the pipeline, and may generate a plug, or partial plug, in the pipeline and/or the riser.
• a slug flow regime may arise where siugs of liquid separated by pockets of gas are formed. Gas bubbles may form in the liquid. Differences or changes in pressure or temperature conditions from point to point along the pipeline can further affect flow behaviour.
• slug catcher In order to deal with slugs, a slug catcher is conventionally present in the processing facility, with the intention of absorbing the effect of any slugs arriving at the processing facility, and stabilising the fluid before it passes into other processing equipment in the processing facility to be processed.
• back pressure effects may arise from the slug catcher, tending to inhibit flow in the pipeline.
• a method of transporting and supplying fluid to a processing facility through at least one section of pipe, the fluid comprising liquid and gas produced from at least one well comprising operating at least one device to apply suction to said section of pipe to encourage the fluid to travel onto the processing facility.
• the fluid Prior to operating the device, the fluid may travel in a slug flow regime through said section of pipe, or may be unable to travel through said section. The fluid may be unable to travel through said section at a desired rate.
• a back pressure to which the fluid may be subjected in said section of pipe may be Sower than prior to operation.
• the fluid may trave! in a flow having an average speed or a flow rate which may be greater than prior to operation.
• the device may comprise at least one pump.
• the method may include pumping the fluid, using the pump.
• the fluid may travel through the pump.
• the suction may be applied may on an upstream side of the pump.
• a vacuum or a partial vacuum may thus be produced in said section of pipe, e.g. upstream of said device, e.g. on the suction side of the pump.
• the device may be operated to facilitate any one or more of the following:
• the device may be operated to stimulate mixing of the liquid and gas in the fluid.
• the section of pipe may comprise a riser between a pipeline and the processing facility.
• the section of pipe may comprise a riser, such as a pipeline riser arranged to connect a seabed pipeline section with the processing facility.
• the device may be arranged downstream from the riser, e.g. at a location along a part of the path between the riser and a slug catcher.
• the device may typically be arranged on or adjacent to the processing facility, e.g. mounted thereupon.
• the section of pipe comprises a riser
• the device may be arranged to apply suction in at least an upper end of the riser to encourage the fluid to travel onto the processing facility, which may be provided on a platform.
• the fluid may be transported through a pipeline.
• the pipeline may be a seabed pipeline.
• the pipeline may be arranged to connect a receiving facility onto which the fluid may be received, and the processing facility, on which the supplied fluid may be processed.
• the processing facility may have equipment for processing the fluid. Such processing may be for turning the fluid into a processed fluid with desired/predetermined characteristics, e.g. processed fluid product for a downstream recipient or end-user.
• equipment in the form of any of the following may be provided in the processing facility for producing the processed fluid: a separator; a scrubber; a cooler; a heater; purification and/or refining equipment; a chemical treatment device; a slug catcher; a pump, compressor, or other machinery; related pipework, equipment, and/or valves for facilitating control or operation of such equipment for producing the processed fluid.
• the receiving facility may be positioned in proximity to the well, and the processing facility may be remote from the well. Either or both of the receiving facility and the processing facility may be provided on a platform, e.g. a surface platform.
• the receiving facility may be configured to tie in a plurality of wells to combine the produced fluid from the wells in a common flow.
• the receiving facility may have a production header, through which multiple wells may be tied to combine the fluid.
• the fluid from the well e.g. fluid combined at the header from multiple wells, may be guided from the receiving facility into the pipeline.
• the receiving facility may be adapted to allow access to the well or wells, and/or to control the production of fluid from the well.
• the well may be an offshore well.
• the receiving facility may typically comprise a wellhead platform associated with one or more offshore wells.
• the receiving facility may include equipment, such as a production transport pump and/or a compressor, for the driving fluid into and along the pipeline downstream.
• the receiving facility may accordingly typically be positioned in proximity to the well or wells, and the processing facility may typically be positioned remote from the well, and/or remote from the receiving facility.
• the method may include operating the device when required, e.g. after a period of time or if detecting a need e.g. if detecting slug flow.
• the method may thus include detecting a characteristic of the fluid, e.g. a condition of the flow, and operating the device in dependence upon the detection of the characteristic, e.g. condition of the flow.
• the production transport pump and/or compressor and said device operated to apply suction may cooperate to facilitate the transport and supply of the fluid onto the processing facility.
• the method may include reducing an output level of the production transport pump and/or compressor (e.g. reducing the pump speed, capacity, or pressure generated).
• the output level of production transport pump and/or compressor may be reduced. This may reduce power required to operate the production transport pump and/or compressor.
• the processing facility may include a slug catcher downstream from the pipe section to which the suction is applied.
• apparatus for transporting and supplying fiuid to a processing facility, the fluid comprising liquid and gas produced from at Seas! one well, the apparatus comprising;
• At least one device for applying suction to said section of pipe for encouraging the fluid to travel to the processing facility.
• the device may comprise at least one pump.
• the pump may comprise any one or more of a multiphase pump; a centrifugal pump; and a turbine pump.
• the device may comprise at least one compressor.
• the apparatus may further comprise a controller configured to control the device based upon a condition or characteristic of the fluid.
• the apparatus may be configured to be arranged upstream of a slug catcher of a processing facility.
• the device may comprise at least one pump for pumping the fluid along said section of pipe, and the apparatus may further comprise a liquid supplier for adding liquid into the fluid being pumped to facilitate operation of the pump.
• the apparatus may further comprise at least one tank for storing the liquid. An amount of the stored liquid in the tank may be added into the fluid being pumped to facilitate operation of the pump.
• the apparatus may further comprise a controller arranged to control the supply of the liquid.
• a transport arrangement comprising the apparatus of the second aspect and further comprising first and second platforms which are spaced apart from one another, the processing facility being provided on the second platform, and a pipeiine arranged between the first and second platforms for transporting the fluid therebetween, said section of pipe being arranged to connect the pipeline with the processing facility on the second platform.
• the section of pipe may typically comprise a riser.
• the device operated to apply suction to the section of pipe to encourage the fluid to travel onto the processing facility may typically comprise at least one pump.
• the fluid transported by the pipeline may travel upward through the riser, through the pump, and into a slug catcher which may be disposed on the second platform.
• the pump may be provided on the second platform at or near an upper, e.g. top, end of the riser, and upstream of the slug catcher.
• the slug catcher and the pump may be arranged on the platform, the pump being arranged in the flow path between the riser and the slug catcher.
• the pipeline may typicaiiy be a !ong-distance transport pipeline, e.g. of several kilometres length, e.g. with a length greater than 1 km, or greater than 10 km or more, e.g. in the range of 1 to 10 km or 1 to 100 km.
• a processing facility provided with the apparatus according to the second aspect of the invention.
• the fluid from the well may typically include oil or gas recovered from a hydrocarbon reservoir.
• the fluid may thus comprise production fluid and may include for example gas, oil, water, or combinations thereof.
• Some solid material may also be contained in and carried with the fluid, in certain variants, the device may comprise a compressor.
• a fifth aspect of the invention there is provided method of conditioning a flow of fluid in a pipeline, the fluid comprising liquid and gas produced from at least one well, the method comprising providing at least one device at a location along the pipeline and operating the device to apply suction to the pipeline such that the flow obtains a condition for facilitating transport of the fluid in the flow.
• the first facility may typically be a receiving facility.
• the second facility may be a processing facility.
• At least one pump arranged at or in proximity to the second facility, and being operable to obtain at least one condition in the pipeline to encourage the fluid to travel through the pipeline to the second facility.
• the condition may be pressure condition, e.g. a pressure produced as a resuit of applied suction.
• the obtained condition may be a vacuum or partial vacuum.
• the second facility may include a slug catcher and the pump may be arranged upstream of the slug catcher.
• any of the various aspects of the invention may include further features as described in relation to any other aspect, wherever described herein.
• Features described in one embodiment may be combined in other embodiments.
• a selected feature from a first embodiment that is compatible with the arrangement in a second embodiment may be employed, e.g. as an additional, alternative or optional feature, e.g. inserted or exchanged for a similar or like feature, in the second embodiment to perform (in the second embodiment) in the same or corresponding manner as it does in the first embodiment.
• Embodiments of the invention can be advantageous in various ways as will be apparent from throughout the specification.
• Figure 1 is a schematic representation of a multiphase transport pipeline with a processor unit arranged at a downstream end;
• FIG. 2 is a schematic representation in further detail of the processor unit shown in
• an arrangement 1 including a seabed pipeline 4 for transporting production fluid from a well 2 to a downstream processing facility 3.
• the production fluid in this case is multiphase, and includes raw hydrocarbon output from a subsurface reservoir in the form of crude oil and gas.
• the fluid also includes produced water,
• the pipeline 4 serves to contain and transport the fluid in a multiphase flow through the pipeline 4.
• a riser 5 is arranged between the pipeline 4 and the processing facility 3. The fluid travels upward through the riser 5 from the seabed pipeline 4 to the processing facility 3 which is provided on a platform (a processing platform) at the sea surface.
• an entry pipe 8 connects to the seabed pipeline 4 for delivering the fluid into the pipeline 4 from a wellhead platform 7.
• the entry pipe 6 extends downward between the wellhead platform 7 and the seabed pipeline 4. Accordingly, the production fluid from the well 2 can be carried in a multiphase flow from the wellhead platform 7 to the downstream processing facility 3 through the interconnected entry pipe 6, seabed pipeline 4, and riser 5.
• the flow of production fluid is obtained by way of a pressure differential between the upstream and downstream ends 1a, 1b.
• the arrangement includes apparatus in the form of a processor unit 10 which is arranged at the processing facility 3.
• the processor unit 10 is configured to control the pressure Y. In this way, the processor unit 10 can affect the pressure differential between the upstream and downstream ends 1a, 1 b by which the flow is driven through the pipeline 4.
• the processor unit 10 is operated to apply suction to the top of the riser 5, suppressing the pressure Y to encourage the fluid to travel up through the riser 5 to the processing facility 3 on the platform.
• the processor unit 10 includes first and second pumps 12, 14, which are arranged to receive the production fluid from the pipeline 1 through an inlet 13 and pump the fluid out through an outlet 14.
• the pumped fluid from the outlet 14 of processor unit 10 is passed onward, typically via a slug catcher, for further processing by processing equipment in the processing facility 3.
• a processed fluid may thereby be produced on the processing facility 3 having a predefined character that may be exported.
• suction is generated and the pressure Y is significantly suppressed at a top end of the riser 5, (and/or in the path downstream from the top of the riser 5).
• the pressure Y obtained by operation of the first and second pumps 12, 14 in effect "pulls" the fluid in from the pipeline 4 to the downstream processing facility 13.
• the first and second pumps 12, 14 are operated in an overcapacity condition with respect to the material of the fluid arriving at inlets 12i, 14i.
• the first and second pumps 12, 14 are operated at a speed sufficient to accept and pump the production fluid through the pumps 12, 14 without imparting any significant back pressure against the flow of the fluid entering the pumps 12,
• the back pressure may be lowered compared with that experienced when the pumps 12, 14 are not used, all other conditions being equal.
• the pressure differential between the pipeline and the top of the riser 5 can thus be enhanced to encourage the flow to the processing facility 3.
• the speed of flow in the riser 5 may be increased.
• first and second pumps 12, 14 While in other cases one pump may be sufficient, two pumps in the form of first and second pumps 12, 14 are operated in parallel in this example in order to provide sufficient capacity. Accordingly, the fluid arriving into the inlet 13 is split between the first and second pumps 12,
• the first and second pumps 12, 14 are both multiphase pumps (e.g. centrifugal pumps) configured to operate with a production fluid that contains liquid and gas. Typically, such a pump requires a proportion of liquid of around 40% by volume. If the first and second pumps
• the processor unit 10 includes a tank 30 for storing liquid, from which an amount of liquid can be supplied into the respective inlets 12i,
• a first supply pump 31 is used to pump liquid from the tank 30 into the inlet 12i, and a second supply pump 33 is used to pump liquid from the tank into the inlet 14i.
• the first and second supply pumps 31 , 33 are controlled by a controller 40 which is arranged to communicate with the first and second supply pumps 31 , 33.
• the controller 40 may include a computer device and may be arranged to send data to the first and/or second supply pumps 31 , 33 to operate them appropriately, e.g. to supply suitable amount of liquid into the inlet 12i and/or the inlet 14i.
• the controller 40 may also be arranged to communicate with the first pump 12 and the second pump 14 for obtaining status information.
• the controller may send instructions for operating the first and second pumps 12, 14, e.g. to operate a motor of the relevant pump.
• the controller 40 is also arranged to communicate with the tank 30, for example to control valves on the tank 30, or to obtain tank information such as liquid levels, etc.
• Instructions may be communicated by the controller 40 to the tank 30, and/or to the first and/or second supply pumps 33, 34, based upon the obtained tank information and/or the pump status information, so that the appropriate supply of liquid into the first and second multiphase pumps 12, 14 is obtained.
• the processor unit 10 may be installed and operated when required, e.g. retrofitted, when the pressure differentiai along the pipeline 4 fails below a predefined target level or conditions of the flow change, e.g. such as a change in composition of fluid arriving on the processing platform, a drop in velocity, or a change in another flow characteristic or property.
• Sensors or other equipment may be provided for detecting the condition of the flow (e.g. provided on the downstream processing facility 3), and the processor unit 10 may be operated in response to the detected condition or a change thereof.
• a shut-off valve 20 in the pipeline is closed so that the production fluid from the riser pipe 5 is re-directed into the inlet 13 of the processor unit 10, flows through the processor unit 10, and then enters back info the pipeline 4 on the downstream side of the valve 20.
• the shut-off valve may be partially closed so that the part of the fluid flows through the valve 20 whilst another part of the fluid from the riser pipe 5 flows through the processor unit 10.
• a pipeline 4 additionally has a fiow valve 22 downstream of the processor unit 10 for controlling the pressure and flow of the pumped fluid which exits the processor unit 10 so that requirements of downstream processing equipment such as separators, scrubbers, coolers, heaters, and the like, can be met.
• the processor unit 10 By use of the processor unit 10 to apply suction and suppress the downstream pressure (pressure Y, at downstream end 1b), transport of production fluid from the well 2 can be facilitated. This can be particularly useful in relation to multiphase flows where the production fluid may comprise a wide range of different fluids, including oil, gas, and water, and may exhibit challenging flow behaviour.
• the provision of the processor unit 10 can stimulate mixing of constituents in the fluid in the riser 5 to produce a mixture which may be better suited for transport through the riser to the processing facility.
• the mixture may be less susceptible to slug development than prior to operating the processor unit 10.
• Stratification and blockage potential may be reduced in particular where the flow of the production fluid through the pipeline changes direction such as at the junction between the seabed pipeline 4 and the riser 5.
• the contribution of the processor unit 10 to generating a good pressure differential for driving the flow of production fluid can help to reduce any pumps or need for pumps at the upstream end 1a, e.g. on the wellhead platform.
• the provision of the processor unit 10 may facilitate recovery from the wells for a longer period of time, and/or reduce costs associated therewith.
• by placement of the processor unit 10 upstream of the slug catcher back pressure effects in the pipeline 1 from the slug catcher, can be reduced or eiiminated. Indeed, when used together with the processor unit 10 at the downstream end 1 b, pumps or increased pumping power may be installed at the upstream end 1a, e.g.

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• Engineering & Computer Science (AREA)
• Life Sciences & Earth Sciences (AREA)
• Mining & Mineral Resources (AREA)
• Geology (AREA)
• Fluid Mechanics (AREA)
• Environmental & Geological Engineering (AREA)
• Physics & Mathematics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Mechanical Engineering (AREA)
• General Engineering & Computer Science (AREA)
• Pipeline Systems (AREA)
• Paper (AREA)
• Lasers (AREA)
• Flow Control (AREA)

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Citations (4)

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• 2015
  • 2015-07-15 NO NO20150921A patent/NO20150921A1/no not_active Application Discontinuation
• 2016
  • 2016-07-14 WO PCT/NO2016/050159 patent/WO2017018887A1/en active Application Filing
• 2018
  • 2018-02-13 NO NO20180222A patent/NO20180222A1/en unknown

Patent Citations (4)

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