Flow Assurance Overview

Introduction

Flow assurance encompasses the engineering disciplines that ensure reliable and safe transport of produced fluids from the reservoir to processing facilities. The term originated in the deepwater industry but applies to all production systems where fluid properties or operating conditions threaten continuous flow.

Flow assurance addresses three primary risks:

  • Hydrate formation -- solid ice-like structures that plug pipelines and equipment
  • Corrosion -- internal metal loss from dissolved gases (CO2, H2S) in produced fluids
  • Erosion -- mechanical wear from high-velocity fluids and entrained solids

Why Flow Assurance Matters

Safety and Environmental Protection

Risk Consequence Prevention
Hydrate plug Pipeline rupture, uncontrolled release Inhibitor injection, insulation
Corrosion failure Loss of containment, spill Material selection, chemical treatment
Erosion breach Wall thinning, leak Velocity limits, pipe sizing

Production Continuity

Unplanned shutdowns from flow assurance failures cost operators millions of dollars per event. Proactive management through calculation-based design prevents:

  • Hydrate blockages during shut-in and restart
  • Corrosion-induced leaks requiring emergency repairs
  • Erosion damage at chokes, bends, and restrictions

Asset Integrity

Flow assurance calculations support the entire asset lifecycle:

  1. Design phase -- material selection, pipe sizing, insulation specification
  2. Operations phase -- inhibitor dosing, velocity monitoring, inspection planning
  3. Late life -- increased water cut effects, reduced pressure implications

Calculation Categories

Hydrate Prevention

Gas hydrates form when water molecules cage gas molecules under conditions of high pressure and low temperature. Prevention requires either keeping conditions outside the hydrate stability zone or injecting thermodynamic inhibitors.

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Key calculations:

  • Temperature depression from inhibitor concentration
  • Required inhibitor concentration for a target depression
  • Inhibitor injection rates (methanol and MEG)
  • Subcooling margin assessment

Documentation: Hydrate Prevention

Corrosion Management

Internal corrosion in oil and gas systems is primarily driven by dissolved CO2 (sweet corrosion) and H2S (sour corrosion). Accurate prediction of corrosion rates enables proper material selection and chemical treatment programs.

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Key calculations:

  • CO2 partial pressure and fugacity
  • Uninhibited and inhibited corrosion rates
  • NACE severity classification
  • Corrosion allowance for design life

Documentation: Corrosion and Erosion

Erosion Control

Erosion occurs when fluid velocity exceeds safe limits, causing mechanical damage to pipe walls. The API RP 14E erosional velocity criterion provides the industry-standard approach.

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Key calculations:

  • Erosional velocity from API RP 14E
  • Mixture density at flowing conditions
  • Actual mixture velocity
  • Erosion ratio (actual/erosional) and risk classification
  • Minimum pipe diameter for a given flow rate

Documentation: Corrosion and Erosion

Decision Framework

Selecting the Right Analysis

Condition Analysis Required Key Input
Subsea or cold environment Hydrate prevention P, T profile, water content
CO2 in produced gas Corrosion management CO2 mole fraction, T, P
High flow rates or gas rates Erosion control Flow rates, pipe diameter
All production systems Combined assessment Full fluid characterization

Integration with Other Disciplines

Flow assurance calculations depend on and feed into other engineering areas:

Discipline Relationship to FA
PVT Fluid properties (density, viscosity, water content) are inputs to FA calculations
VFP Pressure and temperature profiles along flowlines determine hydrate and corrosion risk zones
Facilities FA calculations drive separator sizing, chemical injection system design, and material selection
Reservoir Fluid composition changes over field life affect corrosion and hydrate risk

Typical Workflow

Field Development Planning

  1. Characterize fluids -- obtain PVT data, gas composition, water analysis
  2. Model P-T profiles -- use pipe flow correlations along proposed routes
  3. Screen hydrate risk -- compare P-T profiles against hydrate curves
  4. Assess corrosion -- calculate rates from CO2/H2S content and conditions
  5. Check erosion -- verify velocities are within safe limits for pipe sizes
  6. Design mitigation -- specify inhibitors, materials, pipe diameters, insulation

Operational Monitoring

  1. Track inhibitor usage -- compare actual injection rates to calculated requirements
  2. Monitor corrosion -- compare measured rates to predicted baseline
  3. Review velocity -- recalculate as production rates and water cuts change
  4. Update for changing conditions -- reservoir pressure decline, increasing water cut

Input Parameters

Common Inputs Across FA Calculations

Parameter Symbol Units Used In
System pressure PP psia Hydrate, corrosion, erosion
Temperature TT degF Hydrate, corrosion
CO2 mole fraction yCO2y_{CO_2} fraction Corrosion
Gas specific gravity γg\gamma_g -- Hydrate, erosion
Water cut fwf_w fraction Corrosion
Liquid rate QLQ_L bbl/d Erosion
Gas rate QgQ_g MMscf/d Erosion
Pipe inner diameter dd in Erosion

Detailed Documentation

Articles

References

  1. Sloan, E.D. and Koh, C.A. (2008). Clathrate Hydrates of Natural Gases, 3rd Edition. CRC Press.

  2. de Waard, C. and Milliams, D.E. (1975). "Carbonic Acid Corrosion of Steel." Corrosion, 31(5), pp. 177-181.

  3. API Recommended Practice 14E (2007). "Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems." 5th Edition. American Petroleum Institute.

  4. Hammerschmidt, E.G. (1934). "Formation of Gas Hydrates in Natural Gas Transmission Lines." Industrial & Engineering Chemistry, 26(8), pp. 851-855.

  5. Carroll, J.J. (2014). Natural Gas Hydrates: A Guide for Engineers, 3rd Edition. Gulf Professional Publishing.

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