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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

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)

Flow Control in Oil/Gas Wells and

Pipelines

Multiphase Transport Solutions

The Snøhvit solution:Transport directly to shore

The Åsgard field:Floating production system

(www.statoil.com)

Flow Control in Oil/Gas Wells and

Pipelines

Multi-Phase Fluid Flow (Oil/Water/Gas)

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

Callenges for Deep Water Developments

(Hassanein and Fairhurst, BP 1997)

Flow Control in Oil/Gas Wells and

Pipelines

Flow Control

The ability to actively or passively manipulate a flow field in order to effect a beneficial change.

(Gad-el-Hak, 1989)

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

Pipelines

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++

Flow Control in Oil/Gas Wells and

Pipelines

Horizontal Two-Phase Flow

• Segregated flow– Stratified

– Annular

– Wavy

• Intermittent– Slug flow

– Plug flow

• Distributive flow– Bubble/mist flow

– Froth flow

Flow Control in Oil/Gas Wells and

Pipelines

Example – horizontal slug flow

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

Flow Control in Oil/Gas Wells and

Pipelines

Inclined flow

• Waves!

Flow Control in Oil/Gas Wells and

Pipelines

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°

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

Example - vertical flow

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

Slug flow Bubble flow

Flow Control in Oil/Gas Wells and

Pipelines

Vertical Flow Map

• Partly dependent on upstream geometry

Flow Control in Oil/Gas Wells and

Pipelines

Slug Flow -

A fascinating but unwanted and damaging flow pattern

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

• ”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

Flow Control in Oil/Gas Wells and

Pipelines

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:

Flow Control in Oil/Gas Wells and

Pipelines

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.

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

Important Severe Slugging Parameters

• Gas and oil flowrate

• Pipeline pressure

• Upstream geometry

Graph from Fuchs (1997)

Flow Control in Oil/Gas Wells and

Pipelines

Important Severe Slugging Parameters

• Gas and oil flowrate

• Pipeline pressure

• Upstream geometry

Pressure:30 bar

Pressure:50 bar

Figures from Fuchs (1997)

Flow Control in Oil/Gas Wells and

Pipelines

Important Severe Slugging Parameters

• Gas and oil flowrate

• Pipeline pressure

• Upstream geometry

Strigh

t pip

e up

streamP

ipe b

uck

ling u

pstream

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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 1.stage separator

PICSP

D

PT

MV

PT

Used as regulation valve

Flow Control in Oil/Gas Wells and

Pipelines

Robust operation –

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

Flow Control in Oil/Gas Wells and

Pipelines

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 gasAnnulus

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

Pipelines

Slugging in riser Heidrun D-line

Trykk toppside oppstrøms choke

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

Tetthet toppside

Flow Control in Oil/Gas Wells and

Pipelines

Active Well Control at Brage A-21

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

Pipelines

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

Flow Control in Oil/Gas Wells and

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

Flow Control in Oil/Gas Wells and

Pipelines

Flow control in petroleum production

• Noise suppression

• Drag reduction

• Water-oil flow

• Flow assurance

• Slug control

• Multiphase flow simulation

Flow Control in Oil/Gas Wells and

Pipelines

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