Flow Assurance

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

• Fluid composition
  • Gas
  • Oil
  • Water

• Reservoir "rock"
• Hydrocarbons
  • Saturates/ Paraffins
  • Aromatics
  • Resins
  • Asphaltenes
• Non-hydrocarbons
  • Water
  • Mineral salts
  • CO₂, H₂S, mercaptans
  • N₂, He
  • Metals
  • Micro-organisms

• 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 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

• Flow Regimes
  • Describe how the gas and liquid are distributed within a multiphase pipeline.
• Vertical Flow Regimes

• Horizontal flow map

Slip

• 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.

Holdup (H_L)

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

Slugging

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

Solids

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

Hydrates

• 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)

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Hydrate prevention

• 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

• Blockage Remediation
• Remediation techniques are similar to prevention techniques
  • Depressurization
    • Most common method
  • Chemical
  • Thermal
• Safety considerations

Wax/Paraffin's

• 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

• 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

• 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

• 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.

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

Scale

• 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 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

Asphaltenes

• What are Asphaltenes?

• • 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

• 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

• 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

• 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

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

• Active heating
  • Bundles
  • Electrical flow line heating

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

Operability

• 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