Flow Control in Oil/Gas Wells and Pipelines Trial Lecture Ph.D Dissertation Even Solbraa 14.February...

Flow Control in Oil/Gas Wells and

Pipelines

Flow Control in Oil/Gas Wells and Pipelines

Trial Lecture

Ph.D Dissertation Even Solbraa14.February 2003


Pipelines

1. Introduction to flow control 2. Multi-phase flow with emphasis on slug flow3. Stabilization of flow in Oil/Gas wells and pipelines4. Examples of flow control for selected oil and gas

fields5. Conclusions

Outline


Pipelines

(illustrations: Statoil picture library)

Norwegian Oil and Gas Production

• Platforms

• Floating production units

• Pipelines directly to shore

• Oil to refineries

• Gas exported to Europe


Pipelines

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 world’s 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 solution:Transport directly to shore

The Åsgard field:Floating 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

Use of emulsion breaker to lower viscosity

Oil-water mixtures:Increase in viscosity closeto inversion point

0 20 40 60 80 100

Water cut (%)

0

50

100

150

200

250

300

350V

isco

sity

(m

Pa*

s) 2 m/s without emulsion breaker2 m/s with emulsion breaker

Emulsion viscosity as a function of water cut


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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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1. Introduction to flow control 2. Multi-phase flow with emphasis on slug flow3. Stabilization of flow in Oil/Gas wells and pipelines4. Examples of flow control for selected oil and gas

fields5. Conclusions

Outline


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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, TrondheimMovie provided by John-Morten Godhavn, Statoil


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Inclined flow

• Waves!


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Horizontal Flow Map

• Flow pattern map for horizontal flow

• Often specified in terms of superficial velocity of the phases

Annular

Slug

Stratified WavyStratified

Bubble

-1°

+1°


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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

From Multiphase Flow Laboratory, TrondheimMovies provided by John-Morten Godhavn, Statoil

Slug flow Bubble flow


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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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• ”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

Slug Flow Classification


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Slug flow generation

(Oliemans 1994)

• Wave growth due to Kelvin Helmholtz instabilities

• Slug growth criteria (the slug has to grow to be stable)

Hydrodynamic slug growth Two criteria:


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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

Annulus

• 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

1. Initiation and Slug formation• Gas velocity too low to sustain liquid film

in riser

• Liquid blocking

• Gas pressure increases in pipe

• No/low production

2. Slug production• Gas pressure equals liquid head

• Liquid accelerates when gas enters riser

• Large peak in liquid flow rate

3. Gas blow down• Pressure drops as gas enters riser

• Gas bubbles become continuous, liquid film at wall

• Gas velocity too low...

4. 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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Pressure:30 bar

Pressure:50 bar

Figures from Fuchs (1997)


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Strigh

t pip

e up

streamP

ipe b

uck

ling u

pstream


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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

Outline


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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– Miniseparators– Active choking– Model based regulation


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Robust design -

Gas injection at riser base(Hill, 1990)

+ •Reduced static head (weight of liquid)

• Prevent severe slugging

• Smoothen start-up transients

Qgas

-

• 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

-


• Can be a problem for deep waters 1.stage separator

PICSP

D

PT

MV

PT

Used as regulation valve


Pipelines


Optimize Well Production(ABB)

OptimizeIT Active Well Control

- - stabilizes the oil production stabilizes the oil production from the well by active from the well by active control of the production control of the production and/or injection chokeand/or injection choke


Pipelines


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 gasAnnulus


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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

-



Pipelines

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– Miniseparators– Active choking– Model based regulation


Pipelines

1. Introduction to flow control and multi-phase flow2. Slug flow3. Stabilization of flow in Oil/Gas wells and pipelines4. Examples of flow control on some oil and gas fields5. Conclusions

Outline


Pipelines

4700m

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


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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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2 2.5 3 3.5 4

76

78

80

82

84

86

88

Days

Brage WellCon data (Day 0 = 24-Aug-2001 07:59:00)

PT -13-217

Pres. [bar]Downhole pressure

OptimizeIT Active Well Control on Brage A-21

Starting Active Control


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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


Pipelines

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

Flow Control in Oil/Gas Wells and Pipelines Trial Lecture Ph.D Dissertation Even Solbraa 14.February...

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