Flow Control in Oil/Gas Wells and Pipelines

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Flow Control in Oil/Gas Wells and Pipelines

• Trial Lecture

Ph.D Dissertation Even Solbraa14.February 2003
2
Outline
1. Introduction to flow control 2. Multi-phase
flow with emphasis on slug flow 3. Stabilization
of flow in Oil/Gas wells and pipelines 4.
Examples of flow control for selected oil and gas
fields 5. Conclusions
3
Norwegian Oil and Gas Production

• Platforms
• Floating production units
• Pipelines directly to shore
• Oil to refineries
• Gas exported to Europe

(illustrations Statoil picture library)
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Trends and Facts in Oil and Gas Production

• Few new giant oil and gas fields are likely to
  be discovered
• More than a quarter of the worlds oil and more
  than 15 of its natural gas lies offshore
• Most of the new discoveries are expected to
  occur offshore
• New large fields are probable in deep waters
• Develop new and cost effective solutions for
  small fields
• Multiphase transport directly to shore
• Tie-in of well stream from sub sea installation
  to platform

(Oliemans, 1994, Sarica and Tengesdal, 2000)
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Multiphase Transport Solutions
The Snøhvit solutionTransport directly to shore
The Åsgard fieldFloating production system
(www.statoil.com)
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Multi-Phase Fluid Flow (Oil/Water/Gas)
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What is the sea depth of future fields ?

• Norwegian Sea 1500 meter
• Gulf of Mexico 2500 meter
• West Africa 1500 meter
• Brazil 300 meter
• Caspian Sea 600 meter
• Venezuela 300 meter

Common Deep water nature of the provinces
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Callenges for Deep Water Developments
(Hassanein and Fairhurst, BP 1997)
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Flow Control

• The ability to actively or passively manipulate a
  flow field in order to effect a beneficial
  change.
• 
  (Gad-el-Hak, 1989)

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Flow assurance

• The ability to produce hydrocarbon fluids
  economically from the reservoir to export over
  the life of a field in any environment.
• 
  (Forsdyke 1997)
• Challenges
• Hydrates
• Wax/paraffin deposition
  Fluid control
• Scale
• Emulsions
  
• Slugging
  Flow control
• Sand
  

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Flow control emulsion viscosity
Oil-water mixtures Increase in viscosity
close to inversion point
Use of emulsion breaker to lower viscosity
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Sand Control

• Sand will follow the oil and gas from the
  reservoir
• Sand can deposit in the pipeline and process
  equipment
• Oscillating pressure and well production will
  increase sand production

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Outline
1. Introduction to flow control 2. Multi-phase
flow with emphasis on slug flow 3. Stabilization
of flow in Oil/Gas wells and pipelines 4.
Examples of flow control for selected oil and gas
fields 5. Conclusions
14
Multiphase Transport

• Flow with one or several components in more than
  one phase
• Gas-liquid flows
• Gas-solid flows
• Liquid-solid flows
• Three-phase flows (e.g. gas-oil-water)
• Simulation tools
• Industry standard OLGA (two fluid model)
• PETRA objectoriented implementation in C

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Horizontal Two-Phase Flow

• Segregated flow
• Stratified
• Annular
• Wavy
• Intermittent
• Slug flow
• Plug flow
• Distributive flow
• Bubble/mist flow
• Froth flow

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Example horizontal slug flow
From Multiphase Flow Laboratory, Trondheim Movie
provided by John-Morten Godhavn, Statoil
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Inclined flow

• Waves!

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Horizontal Flow Map
Bubble

• Flow pattern map for horizontal flow
• Often specified in terms of superficial velocity
  of the phases

Slug
Annular
Stratified
Stratified Wavy
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Vertical flow

• Bubble flow
• Continuous liquid phase with dispersed bubbles of
  gas
• Slug flow
• Large gas bubbles
• Slugs of liquid (with small bubbles) inbetween
• Churn flow
• Bubbles start to coalesce
• Up and down motion of liquid
• Annular flow
• Gas becomes the continuous phase
• Droplets in the gas phase

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Example - vertical flow
Slug flow
Bubble flow
From Multiphase Flow Laboratory, Trondheim Movies
provided by John-Morten Godhavn, Statoil
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Vertical Flow Map

• Partly dependent on upstream geometry

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Slug Flow -A fascinating but unwanted and
damaging flow pattern
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Consequences of Slugging

• Variations in flowrate to 1.stage separator
• Shutdowns, bad separation, level variations
• Pressure pulses, vibrations and tearing on
  equipment
• Flow rate measurement problems
• Variations in gasflow
• Pressure variations
• Liquid entrainment in gas outlet
• Flaring
• Flow rate measurement problems

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Slug Flow Classification

• Normal steady slugs Hydrodynamic slugging
• Unaffected by compressibility
• Incompressible gas (high pressure) or high liquid
  rate
• Normally not an operational problem
• Short period
• Slugs generated by compressibility effects
• Severe slugging in a riser system (riser induced)
• Hilly terrain slugs (terrain induced)
• Other transient compressible effects
• Long period
• Transient slugs
• Generated while changing inlet rate
• Reservoir induced slug flow

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Slug flow generation
Hydrodynamic slug growth Two criteria

• Wave growth due to Kelvin Helmholtz
  instabilities
• Slug growth criteria (the slug has to grow to
  be stable)

(Oliemans 1994)
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Hydrodynamic slugging

• Formed when waves reach the upper pipe wall
  the liquid blocks the pipe, and waves grows to
  slugs
• Short slugs with high frequency
• Gas rate, liquid rate and topography influences
  degree of slugging
• Triggers riser slugging

Eksempel fra flerfaseanlegget på Tiller.
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Slugs from Gas Lift

• Gas lift is a technology to produce oil and gas
  from wells with low reservoir pressure
• Gas lifts can result in highly oscillating well
  flow
• Casing-heading instabilities

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Slug formation in pipeline/riser

• Initiation and Slug formation
• Gas velocity too low to sustain liquid film in
  riser
• Liquid blocking
• Gas pressure increases in pipe
• No/low production
• Slug production
• Gas pressure equals liquid head
• Liquid accelerates when gas enters riser
• Large peak in liquid flow rate
• Gas blow down
• Pressure drops as gas enters riser
• Gas bubbles become continuous, liquid film at
  wall
• Gas velocity too low...
• Liquid fallback
• Liquid film flows down the riser

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Conditions for severe slugging

• Flow maps for pipe/riser
• Conditions from literature
• Bøe 81, Taitel et al 90, Schmidt et al 85,
  Fuchs 87
• Pressure limits
• Depend on pipe geometry
• Based on steady state analysis
• Inaccessible variables
• Dynamic simulation
• When does slugging occur?
• Pipelines with dips and humps
• Low gas-oil ratio
• Decreasing pressure
• Long pipelines
• Deep water production

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Important Severe Slugging Parameters

• Gas and oil flowrate
• Pipeline pressure
• Upstream geometry

Graph from Fuchs (1997)
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Important Severe Slugging Parameters
Pressure30 bar

• Gas and oil flowrate
• Pipeline pressure
• Upstream geometry

Pressure50 bar
Figures from Fuchs (1997)
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Important Severe Slugging Parameters
Stright pipe upstream

• Gas and oil flowrate
• Pipeline pressure
• Upstream geometry

Pipe buckling upstream
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Outline
1. Introduction to multi-phase flow 2. Slug
flow 3. Stabilization of flow in Oil/Gas wells
and pipelines 4. Examples of flow control on some
oil and gas fields 5. Conclusions
34
Slug reduction/elimination techniques

• Design changes
• Slug catchers and separators
• Rate/GOR change or pressure change
• Pipe diameter regulation (use of many smal pipes)
  (Yocum, 1975)
• Gas injection at riser base (Hill, 1990)
• Pipe insertion (self induced gaslift) (Sarica
  Tengesdal, 2000)
• Venturi tubes
• Dynamic simulation (Xu et al, 1997)
• Operational changes
• Choking (Schmidt et al., 1979, Taitel, 1986,
  Jansen et al., 1996)
• Feed-forward control of separator level
• Dynamic simulation (Xu et al., 1997)
• Pigging operations
• Use of flow-improver
• Foaming (Hassanein et.al., 1998)
• Artificial gas lifts
• Optimise well production
• Increase gas injection in well
• Feedback control

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Robust design - Gas injection at riser
base (Hill, 1990)
Qgas

• Reduced static head (weight of liquid)
• Prevent severe slugging
• Smoothen start-up transients

• -
• Large amounts of injection gas needed
• Extra injection pipe needed

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Robust design - Self gas lifting (Sarcia
Tengesdal, 2000)

• Reduced static head (weight of liquid)
• Prevent severe slugging
• Smoothen start-up transients
• No extra injection gas needed

• -
• Extra injection pipe needed will be expensive

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Robust operation Choking(Schmidt et al., 1979,
Taitel, 1986, Jansen et al., 1996 )

• Higher pressure and smaller severe slug flow
  regime
• Easy and cheap technique

• -
• Manual work
• Lower capacity of pipe

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Feedback control Active Choking(Statoil, 2003)

• Reduces the slug length by opening the hock
  valve when the slugs starts to develop sucks
  the slug up.
• Easy and cheap technique

• -
• Lower capacity of pipe
• Can be a problem for deep waters

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Robust operation Optimize Well Production (ABB)
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Robust operation Increased/controled gas
injection rate in gas lifts

• Increased gas flow rate and GOR (less chance for
  severe slugging)
• Less static head

• -
• Increased frictional losses
• Joule-Thomson Cooling
• Need injection gas

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Feedback control -Miniseparators(Hollenberg,
1995, S3TM)

• Principle is to keep the mixture flow rate
  constant through the operation with a control
  vale.
• Difficulty in measuring flowrates is solved by
  using minisparators

• -
• Lower capacity of pipe

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Slug reduction/elimination techniques

• Design changes
• Slug catchers and separators
• Rate/GOR change or pressure change
• Pipe diameter regulation (use of many smal pipes)
  (Yocum, 1975)
• Gas injection at riser base (Hill, 1990)
• Pipe insertion (self induced gaslift) (Sarica
  Tengesdal, 2000)
• Venturi tubes
• Dynamic simulation (Xu et al, 1997)
• Operational changes
• Choking (Schmidt et al., 1979, Taitel, 1986,
  Jansen et al., 1996)
• Feed-forward control of separator level
• Dynamic simulation (Xu et al., 1997)
• Pigging operations
• Use of flow-improver
• Foaming (Hassanein et.al., 1998)
• Artificial gas lifts
• Optimise well production
• Increase gas injection in well
• Feedback control

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Outline
1. Introduction to flow control and multi-phase
flow 2. Slug flow 3. Stabilization of flow in
Oil/Gas wells and pipelines 4. Examples of flow
control on some oil and gas fields 5. Conclusions
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Slugg Control at Heidrun NordflankenUse of
active slug control

• Simulation before startup indicated slugging
• Field measurements after startup proved slugging
• Continuous slug regulation since startup
• Also in use under startup of new wells

D
Elevation -355m
4700m
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Slugging in riser Heidrun D-line
Trykk toppside oppstrøms choke

• Large pressure variations
• Periods ca. 17 minutes.
• Disapears when chocking upstream

Tetthet toppside
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Active Well Control at Brage A-21
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OptimizeIT Active Well Control on Brage A-21
Starting Active Control
Pres. bar
Downhole pressure
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Conclusions

• Introduction to flow control
• Unstable multiphase flow what, why
• Severe slugging in gas/oil pipelines
• Methods for control of severe slugging
• Still an unresolved problem for deep waters
• Successful practical examples

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Thanks

• Institute for Energy and Process Technology,
  NTNU
• Statoil
• Norwegian Research Council
• People who have helped my with this trial
  lecture Lars Imsland, Elling Sletfjerding,
  John Morten Godhavn

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Flow control in petroleum production

• Noise suppression
• Drag reduction
• Water-oil flow
• Flow assurance
• Slug control
• Multiphase flow simulation

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Drag reduction

• Internal flows (pipes, ducts)
• 100 skin friction
• Increased throughput
• Reduced pumping power
• Reduced pipe/duct size
• Wall modifications
• Smoothing (paintings, coatings, pigging)
• Riblets (shark-skin)
• Compliant walls, flexible skin
• MEMS (Micro-electromechanical systems)
• Additives
• Particles, dust, fibres
• Polymers, surfactants (Drag reducing agents)
• Micro-bubbles, fluid films