Flow Assurance

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Flow Assurance for Subsea.png

Flow Assurance

  • Reservoir Fluids
    • Sampling, lab fluid analysis, development of predictive reservoir fluid models
  • Multiphase Flow
    • Rheology, flow modeling – steady state and transient
    • Pressure loss, diameter of tubing & flowlines
    • Slugging and liquid surge
  • Heat Transfer
    • Insulation, heating
  • Solids
    • Hydrates, wax, asphaltenes, scale, etc.
    • Flow restrictions or blockages
  • Internal Corrosion
  • Emulsions
  • Sand
    • Sand transport / deposition
    • Erosion
  • Production Chemistry
  • System Operability
    • Various operating modes: normal operation, shutdown, startup, well testing, turndown/rampup, pigging, etc.

Reservoir Fluids

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  • Fluid composition
    • Gas
    • Oil
    • Water

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  • Reservoir "rock"
  • Hydrocarbons
    • Saturates/ Paraffins
    • Aromatics
    • Resins
    • Asphaltenes
  • Non-hydrocarbons
    • Water
    • Mineral salts
    • CO2, H2S, mercaptans
    • N2, He
    • Metals
    • Micro-organisms
Reservoir Fluids Numbers.png
  • Saturation pressure (bubble point or dew point)
    • Where does the density change?
    • Switch from single to multiphase flow
  • GOR
    • How much does the density change?
    • How much gas is with the oil?
  • API gravity
    • Measure of density
  • Viscosity
    • How does the fluid flow?

Multiphase Flow

Multiphase Flow.png

  • Multiphase flow is the simultaneous flow of multiple fluid phases (gas, oil, and water) inside a pipe.
  • This flow can be in:
    • Reservoir
    • Wellbore
    • Flowlines
    • Risers
    • Export pipline
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  • Flow Regimes
    • Describe how the gas and liquid are distributed within a multiphase pipeline.
  • Vertical Flow Regimes

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  • Horizontal flow map

Horizontal Flow Map.png



  • Under most conditions, the liquid, being more dense and viscous, moves more slowly than the gas
  • Dispersed bubble and annular flow generally have little slip
  • In downwardly inclined pipes, the liquid velocity can be greater than the gas velocity.


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Holdup (HL)

  • Relative amount of liquid at one point in a pipeline.
  • Due to slip HL


  • Hydrodynamic
  • Terrain
    • Riser slugging
  • Pigging
  • Rate change


  • Hydrates
  • Wax/Paraffins
  • Scale
  • Asphaltenes
  • Calcium Naphthenates


  • Crystalline compounds of water and light hydrocarbon and other gas molecules
  • Ice-like solid crystals
  • Cages of water molecules surrounding hydrocarbon molecules
  • Can form with methane, ethane, propane, isobutane, n-buttane, n2, CO2 and H2S
  • Forms at temperatures higher than 32°F (up to ~80°F) at high pressure (> 50psia)

Hydrate prevention

Hydrate Prevention.png
  • Chemical
    • Thermodynamic inhibitors (shift chemical equilibrium)
      • Methanol and other alcohols
      • Glycols (MEG, DEG, TEG, others)
      • Salt (brine)
    • Low dosage hydrate inhibitors (a.k.a. LDHI)
      • Anti-agglomerants
      • Kinetic Inhibitors
    • Thermal
      • Maintain temperature above hydrate formation conditions
      • Insulation
      • Active heating
    • Water removal
    • Low pressure operation
      • Maintain pressure below hydrate formation
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  • Blockage Remediation
  • Remediation techniques are similar to prevention techniques
    • Depressurization
      • Most common method
    • Chemical
    • Thermal
  • Safety considerations



  • Wide range of high molecular weight paraffin's (alkalies or saturated hydrocarbons)
  • Slightly soluble in oil
  • Solidify from oil primarily due to decrease in temperature
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  • As wax solidifies from oil, there are three major concerns:
    • Wax deposition on tubing or pipe walls during normal flow
      • During normal operation
    • Gelling of the oil during shutdown
      • During shutdown and subsequent restart
      • Primarily a dead oil problem
    • Increases in viscosity due to wax particles suspended in the oil
      • During normal operation, low flow or turn down operation, or restart
      • Note some high wax content oils tend to form stable emulsions
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  • Cloud Point or Wax Appearance Temperature
    • Temperature at which the first wax crystals form
    • At the cloud point, only a small fraction of wax molecules crystallize
    • As the temperature continues to drop more wax crystallizes
    • Combine with thermal-hydraulic modeling to determine where wax can deposit

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  • Pour Point
    • Lowest temperature at which an oil can be poured under gravity
    • Below the pour point, wax crystals form a matrix structure or a gel
    • A yield force is required to break the gel and start the oil flowing
    • Defined by ASTM D97 test method
  • Viscosity
    • An important parameter for sizing pipelines and pumps
    • Is strongly dependent upon the temperature
    • Above the cloud point the viscosity of oil only a function of temperature-Newtonian behavior.
    • Below the cloud point, wax crystals suspended in the oil affect the viscosity, and viscosity is a function of temperature and shear rate-non-Newtonian behavior.

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  • Wax Management
    • Mechanical
      • Pigging
    • Chemical
    • Thermal
      • Insulation
      • Active heating
    • Other
      • Operating procedures



  • A deposit of inorganic mineral compounds from formation water
  • Generally inorganic salts such as carbonates and sulfates of the metals calcium, strontium and barium
  • May also be the complex salts of hydrous oxides and carbonates
  • Scale formation and deposition occurs due to:
    • Temperature and pressure changes
    • Mixing of different waters
    • Adding methanol or glycol to production stream
    • Corrosion
  • Deposition can occur in the:
    • Formation
    • Wellbore
    • Flowlines
    • Process Equipment
    • Scale formation with sea water injection

Scale Formation Table.png
  • Scale can be managed by:
    • Prevent deposition using chemical inhibitors
      • Preferred approach for subsea
      • May need to inject deep in the well
      • May need to perform squeeze treatments in the formation
    • Pre-treatment to remove scale formers in injection water (e.g. SRM - sulfate removal membranes)
    • Allow scale to form and periodically remove it
      • Not practical for subsea developement



  • What are Asphaltenes?

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    • Heavy, complex molecules
    • Defined by solubility
      • ASTM D-3279-90
      • Solid that precipitates when an excess of n-heptane or n-pentane is added to an oil
    • Do not have a single, unique structure or molecular weight
    • Do not melt
  • Asphaltenes-Deposition
    • Asphaltenes can deposit due to a drop in pressure
    • Gas lifting can cause asphaltene deposition
    • Asphaltenes can deposit due to the mixing of different oils
    • Asphaltenes can deposit in the formation, well-bore tubing, flow-lines, and topsides
    • Asphaltenes can cause emulsion problems
  • Asphaltenes-Control
    • Chemical
      • Chemical inhibitors are available to prevent asphaltene deposition
    • Mechanical
      • Pigs can be used to periodically remove asphaltene deposits in flow-lines
      • Must be combined with large quantity of aromatic solvent
  • Asphaltenes-Remediation
    • Asphaltene Solvents
      • Asphaltenes are soluble in aromatic solvents (e.g. xylene, toluene)
      • Used to remediate wellbores or other equipment
      • May be used with coiled tubing
  • Thermal methods
    • Asphaltene deposits do not melt
    • Heat will not remove an asphaltene deposit or prevent asphaltenes from depositing

Calcium Naphthenates

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  • Naphthenates are solid that forms from a reaction between calcium in produced water and naphthenic acid in oil
  • Found in some West African and North Sea fields
  • High TAN oils (TAN = total acid number)

Internal Corrosion

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  • Corrosion can occur inside a pipe anytime water is present
  • Corrosion is accelerated by the presence of 02, CO2, or H2S
  • Pipeline failures are a big potential liability
  • Corrosion prevention
    • Chemical inhibitors
    • Protective coatings, corrosion resistant alloys
    • Limit flow rates/velocities
    • Other


  • Emulsions are complex mixtures of immiscible liquids consisting of a dispersed liquid in a continuous liquid phase
  • Water-in-oil emulsions
    • Most common in crude oil systems
    • Exists in water cuts as high as 80%
  • Oil-in-water emulsions
    • High water cuts
  • Increased viscosity
  • Separation
  • Viscosity

Emulsion Viscosity.png

Solids Management

  • Thermal
    • Insulation
    • Active heating
  • Chemical
    • Inhibitors
    • Disperants
    • Coatings
  • Mechanical
    • Pigging
    • Coiled tubing

Thermal Management

  • Why are we interested in thermal management?
    • Many of the potential solids are temperature sensitive, particularly hydrates and wax
    • Viscosity increases (sometimes significantly) with decreasing temperature
  • Thermal management options
    • Insulation - keep the heat you have
    • Active heating - add energy
  • Insulation
    • Flow lines
      • External or wet insulation- syntactic foams
      • Pipe-in-pipe
      • Burial
      • Bundle
    • Subsea equipement
      • External or wet insulation-syntactic foams
  • Insulation - flow line


  • Insulation - subsea manifold

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  • Active heating
    • Bundles
    • Electrical flow line heating
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Chemical Injection

  • Chemicals are needed to control a number of potential solids and production chemistry concerns
  • Chemical compatibility
  • Chemical Injection- Design Philosophy
    • Reservoir fluid analyses
    • Chemical performance testing
    • Umbilical and injection system design
    • Operation monitoring

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  • Development of Operating Philosophies, Strategies, and eventually Procedures
  • Integration of Flow Assurance Design
    • Management of solids - chemical injection, insulation, etc.
    • Deliverability, need for artificial lift
  • Life of field assessment
  • Definition of operating boundaries/ranges
  • Consider various modes of operation
    • Normal operation, well testing, shutdown, startup, etc.
  • Operational monitoring
  • Intervention requirements