Flow Assurance for Offshore Pipeline

Flow assurance is required to determine the optimum flowline pipe size based on reservoir well fluid test results for the required flowrate and pressure. As the pipe size increases, the arrival pressure and temperature decrease. Then, the fluid may not reach the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the pipe size is too small, the arrival pressure and temperature may be too high and resultantly a thick wall pipe may be required and a large thermal expansion is expected.

Full scope of flow assurance (courtesy of MSL Engineering)
Source: http://petrowiki.org/images/thumb/b/b6/Vol3_Page_554_Image_0001.png/800px-Vol3_Page_554_Image_0001.png

Flow assurance matters for subsea tieback systems (courtesy of BP)
Source: http://petrowiki.org/images/thumb/8/84/Vol3_Page_554_Image_0002.png/800px-Vol3_Page_554_Image_0002.png

It is important to determine the optimum pipe size to avoid erosional velocity and hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance temperature, the required OHTC is determined to choose a desired insulation system (type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S, CO2, etc., the line should be chemically treated or a special corrosion resistant alloy (CRA) pipe material should be used. Alternatively, a corrosion allowance can be added to the required pipe wall thickness. capital expense (Capex) and operational expense (opex) using CRA, chemical injection, corrosion allowance, or combination of the above should be exercised to determine the pipe material and wall thickness.

Plugged Flowlines
Source: Introduction to Offshore Pipelines & Risers - Jaeyoung Lee
 Figure below illustrates one example of how to select pipe size from flow assurance results. The blue solid line represents inlet pressure at wellhead and the red dotted line represents outlet fluid temperature. The 8” ID pipe may require a heavy (thick) wall and the 12” ID pipe may require a thick insulation coating depending on hydrate (wax or asphaltene) formation temperature.

Inlet Pressure & Outlet Temperature vs. Flowline ID
Source: Introduction to Offshore Pipelines & Risers - Jaeyoung Lee

Special considerations

Pressure support consideration
It is necessary for sufficient pressure to be available to transport the hydrocarbons at the required flow rates from the reservoir to the processing unit. Matters that require consideration in this regard include:
  • Pressure loss in flowlines
  • Separator pressure setpoint
  • Pressure loss in wells
  • Artificial lift method selection
  • Remote multiphase boosting
  • Drag reduction
  • Slugging in horizontal wells
  • Gas lift system stability
  • Interaction with reservoir performance
Component and system design consideration
Components and systems should be designed and operated to ensure that flowrate targets are achieved and that flow is continuous. Issues to be taken into account include:
  • Hydrate formation
  • Wax deposition
  • Asphaltenes
  • Sand and solids transport
  • Corrosion
  • Erosion
  • Scale deposition
  • Interaction of slugging and pipe fittings
  • Interaction of slugging and risers
  • Relief and blow-down
  • Pigging
  • Liquid inventory management
  • Well shut-in pressure
Multiphase flow considerations
For multiphase flowlines, it is necessary for the process to be able to handle the fluid delivery, and consideration should be given to a number of issues including
  • Interaction with facilities performance
  • Slugging (steady state)
  • Slugging (transient)
  • Slug-catcher design
  • Severe slugging prevention
  • Effect of flow rate change
  • Temperature loss prediction
  • Piping layout
  • Remote multiphase metering
  • Gas and dense phase export
  • Oil and condensate export
  • Separator performance

Introduction to Offshore Pipelines & Risers - Jaeyoung Lee


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