1. Flow Control in Oil/Gas Wells and Pipelines
Trial Lecture
Thank for introduction and thanks to all for comming to this trial lecture
The subject for my trial lecture is Flow Control in Oil/Gas Wells and Pipelines
Looking at the title many of you will might think it is a smal subject. Not true. How can flow in pipes be such a difficult problem. In reality it is a huge subject. The subject is so large that it is not possible to be an expert in all relatedsubject. In this trial lecture I will give you a introduction to Flow Control from my view.
Practical situation pumbing of driinkwater in house. We just need a big enoug pump. Air in the drink water system - problem. Two phase flow of air and water.
From oil and gas reservoirs and pipes: gas, oil, sand, ice, wax at very high pressures. Very tough problem.
Ph.D Dissertation Even Solbraa 14.February 2003

2. 1. Introduction to flow control
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
Outline for the presentation
Introduction to flow control and multi-phase flow General overview of fluid and flow control in petroleum production. I will og into more detail about one important part of flow control – namely: slug flow and especially severe slugging
Description of slug flow
Slug flow is unstable flow in pipelines and something we dont want Severe slugging is undiserable as air in the water tap system.
Stabilization of slug flow Description of stabilization methods for slug flow
Examples of flow control for on some 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
The norwegian oil and gas production system:
Oil production offshore. Production plaform with oil transport by oil tankers and by pipelines: The oil is sent to raffeneriers i.g Mongstad – where e.g the fuels are produced.
Gasproduction from gas fields/gas-condensate fields/and oil-gas fields. Gas is transported thorug pipelines to the european market. The use og natural gas in the norwegian is minimal. Power generation in norway from water and imported energy. Norway is actually a net importer of energy.
Description of the illustrations Heidrun: Gas condesate fields Åsgard: Floating production Norne floating production
All in the Norwegian Sea
Oil production on the Tampen area see big risers transporting the fluids
Typical depths: meter?
Temperatures: 4 C
(illustrations: Statoil picture library)

4. 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
In a review article Olimans addressed the state of art in the development of multiphase production systems and highlighted future trends.
Mutliphase became a offshore production in 1973 – oil crisis – offshore – multiphase became important – 1970/1980 high oil prices. Collapse of oil prices in 1986 cheaper offshore solutions needed.
New solutions are constantly developed – but cost are continuously increased. But increased environmental and safety concerns .
More than one quarter of the worlds oil and 15% of the worlds oil lies offshore. Few new giant offshore fields are likely to be discovered. Industry must look to smaller fields. Often on deep water.
Multiphase transport directly to shore will be important and tie in of well streams to existing platform. The use of existing infrastructure will be important – and will create longer life for excisting production equipment.
(Oliemans, 1994, Sarica and Tengesdal, 2000)

5. Multiphase Transport Solutions
The Åsgard field: Floating production system
The Snøhvit solution: Transport directly to shore
During the past 30 years multiphase flow technology has become increasingly important for the economic transportation of well streams from reservoir to process.
Early : big concrete platform (
1990 floating production systems (larger depths)
2000 production directly to shore (snøhvit)
In the illustrations we see the
Åsgard oil and gas field: 300 meters deep at the halten bank
Planned (2005) snøhvit transport solution directely to shore 160 km pipeline 300 meter depth. No fixed or floating units. Barents Sea.
The same directely to shore solution is planned for the Ormen Lange field meter water depth – (start 2007). (

6. Multi-Phase Fluid Flow (Oil/Water/Gas)
In the illustration we see a typical situation for oil and gas production offshor. Oil and gas is brought up the reservoir to the sea bed from production lines.
Reservoir management
Reservoir management can consit of gas injection and water injection to control the flow in the reservoir and keep the reservoir pressure high.
Kontroll av brønnstrøm er viktig styring av brønn.
Dette gjøres for eksemple gassinjeksjon og injeksjon av produksjonsvann i brønn.
Hydrater, scale, vax and asphaltenes are unwanted phenomena that we have to control to prevent blockage of the pipelines. I describe these phenomena's briefely.
Hydrates is freezing of ice at temperatures relatively high temperatures. Hyrdrate formation can cause plugs in the pipeline. Scale is salts clogging the pipeline wall. Deposition of salts will oc cur when producing salt containing formation water. Asphaltenes is deposition of very heavy hydrocarbon that will fall out of the oil at pressure reduction – and can create blockage of pipes.
Corrosion is a problem for all pipelines – and control of free water is very important. CO2 will increase the corrosion rate do to its acidity in water.
Slug control in pipelines is a phenomena that has got more and more atensian when langer pipelines and at deeper water depths have been built. Problems related to slug flow will be described in depth later in the presentation. With emphasis on slug reduction and control methods.

7. What is the sea depth of future fields ?
Norwegian Sea meter
Gulf of Mexico meter
West Africa meter
Brazil meter
Caspian Sea 600 meter
Venezuela meter
One important challenge for new developments is that they will be on very deep waters.
Traditionally the Norwegian fields have been on relatively shallow water. The 17” konsesjonsrunde water depth as deep as 1500 meter will be available.
The gulf of Mexico need production systems for water depth around 2500 meter. The challenges is incredible for such depths. Outside West Africa we have depths up to 1500 meter.
Common to many of the new offshore areas is that they will be on deep water – and also need long distance transport. For offshore production these will
Common: Deep water nature of the provinces

8. Callenges for Deep Water Developments
Hassanein and Fairhurst 1997 summarized some challenges we face when try to produce oil and gas in deep waters.
To day oil and water are transported to a platform and separated. Old fields can produce 70% of water. Water reinjection is energy demanding and very expensive. It also leads to large amounts of CO2 to the atmosphere. Water removal on the sea-bed and direct injection of produced water. Troll pilot was installed in 2001 and has been a success for Norsk Hydro and ABB. Technology
A big challenge for deep water develop is to keep the well pressure as high as possible. It will be important to separate the water down stream.
Low dose inhibitors is also important . Slug control in pipes. Need for good thermodynamic models and simulation tools. Olga is a standard tool used to simulate multiphase pipelines to day. But the program has still many weak part. The models in the program eg. Had to be changed after the start of the Troll pipeline.
Sand removal (control sandproduction from wells).
Oil water emulisifications.
All related to flow controll – and fluid control.
Riser slug control will be important in deep water fiedls and long pipelines. Sever slugging are probable to occur under such conditions.
(Hassanein and Fairhurst, BP 1997)

9. Flow Control
The ability to actively or passively manipulate a flow field in order to effect a beneficial change.
(Gad-el-Hak, 1989)
Gad-el-Hal a well know researcher in turbulent flow defined flow control as :
The ability to actively or passively manipulate a flow field in order to effect a beneficial change.
Actively change of a flow field will e.g. be use of gas lifts and new installations in the pipe.
Passively could in general be the use of flow improvers in the pipe.
We see that control covers both control of the fluid properties and the physical design of the production system.

10. 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 assurance
Definition – the ability to produce hydrocarbon fluids economically from reservoir to export over the life of a field in any environment.
Taking in to account all extreme environments with deep waters this is a big subject. The main cahllenges in flow assurance is:
Hydrates.
Wac/Parafines
Scale
Emulisions
Slugging
Sand

11. Flow control: emulsion viscosity
Oil-water mixtures:
Increase in viscosity close
to inversion point
Use of emulsion breaker to lower viscosity
Emulsion Viscosity can be a large problem for the oil industry. The illustration shows suspension of oil and water at varying water cuts. From water in oil to oil in water. The viscosity is very high near the inventionpoint (from oil continious to water continious). This will reduce the flow and almost stop the flow completely. Emuisoins breakers are chemicals that sticks to the oil-water interface – and reduces the effect of emulusions drastically.
In the graph above s
Parameters affecting phase inversion.

12. 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

13. 1. Introduction to flow control
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
Outline for the presentation
Introduction to flow control and multi-phase flow General overview of fluid and flow control in petroleum production. I will og into more detail about one important part of flow control – namely: slug flow and especially severe slugging
Description of slug flow
Slug flow is unstable flow in pipelines and something we dont want Severe slugging is undiserable as air in the water tap system.
Stabilization of slug flow Description of stabilization methods for slug flow
Examples of flow control for on some oil and gas fields
5. Conclusions

14. Flow with one or several components in more than one phase
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++
In this presentation phenomena related to multiphase flow will be in focus.
The definition of multi phase flow is: one or more phases flowing in contact.
This can be a gas and a liquid – as in boiling water.
Gas solid flow –
Liquid solid flows
Three phase flows – (gas, liquid, sand, wax,..)
I will now describe the basic phenomena of two phase flow – before describing phenomena and problems related to this phenomena.
The standard simulation tools used for modelling these flow are OLGA developed. Such modelling tools will often be uncertain – becouse the complicated nature of the flow. Much work are in progress to further develop these programs.

15. Horizontal Two-Phase Flow
Segregated flow
Stratified
Annular
Wavy
Intermittent
Slug flow
Plug flow
Distributive flow
Bubble/mist flow
Froth flow
To simplify our understanding of two phase flow – we have defined some flow – pattern. Based on the visual insight in the flow. Horizontal flow are generally
Segregated flow is flow where we have a cler defined interphase between the gas and liquid. This can be stratified flow – or annular flow.
At high solution flow rates considerable gas will be in the slug as bubbles.
Intermittent flow is defined as irregular flow with variations in time.
Distributed flow is flow where either the bubbles are distributed in the other phase.
Oil/gas reservoirs will lead to bubble and slug flow in the pipe system.
Gas/condensate reservoirs will result in laminar vawy and annular flow.
In the next slide two of the flow patters are observed by a stationary videocamera.

16. Example – horizontal slug flow
Video recording done at the multi phas alboratory.
Low velocities of liquid and gas. No gas in slugs.
From Multiphase Flow Laboratory, Trondheim
Movie provided by John-Morten Godhavn, Statoil

17. Inclined flow
Waves!
Upwards inclined flow will have a tendency to form slugs more asilly.
Gravity forces will act against the flow direction – and the holdup will increase. Chenses for waves to hit the upper pipe wall and form slugs will therefore increase.
Downwords pipeflow will haave less chance to form slugs. The gravity will act in the flow direction – and the liquid film thickness will be reduced. Chances for slug formating is therefor lowered. Downwards flow is typical for flow down towards the riser base on a platform.

18. Horizontal Flow Map Flow pattern map for horizontal flow
Bubble
Flow pattern map for horizontal flow
Often specified in terms of superficial velocity of the phases
Slug
-1°
+1°
Annular
Stratified
Stratified Wavy

19. Vertical flow Bubble flow Slug flow Churn flow Annular 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

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

21. Vertical Flow Map Partly dependent on upstream geometry
Low gas and liquid velocities : bubble flow.
At increasing gas velocities: slug flow and larer churn flow.
At very high velocities annular flow.

22. Slug Flow - A fascinating but unwanted and damaging flow pattern

23. 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
Slugs can be of many shapes and forms.
Small slugs can be some meter long.
Longe sugs can be many kilometers long.
Slug flow will create a unstable and unwanted situation for the process. We will experience times with onli oil-prduction (when the slug comes), times with only gas production(the bubble) and times of no production.
The can result in flooding of separators – and a reduced product quality. Compressores will work in a sub optimal working point.
Rate measuremnt will be difficult – because of a highly varying flow rate.
Reservoirs are influenced by pressure variations cased by slug flow. Presssure variations can cause calpase of reservoirs and large sand production.
Pressure variations can also be damaging for the pipe- mechanical stress. And the varying pressure will lead to reduced total output of the pipe.

24. 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

25. 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)
It is usefull to define four different ways a slug can form
Wavy growth due to Kelvin Helmholtz instabilities. To form slug flow the slug flow criteria of Espedal and Bendiksen has to be fylwill. In high pressure systems we will often see that the waves reaching the top of the pipe – but the slug is not able to grow. In low pressure systems the slug growth criteria are normally ulfilled – and Wave growt is the controling criteria.Hitting the wall can therefore create a conditionally stable slug flow.
Pipe sags can be traps for liquid and can be completely blocked. Slug flow will form in such situations if the gas is not supplied in a rate so the pressure bild up is not able to blow the slug out directely.
Startup slugs are normal in equapment with suddenly change in flowrates, and also pigging operations will create slug flow.
(Oliemans 1994)

26. 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.

27. Annulus
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

28. 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

29. 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

30. Important Severe Slugging Parameters
Gas and oil flowrate
Pipeline pressure
Upstream geometry
Graph from Fuchs (1997)

31. Important Severe Slugging Parameters
Pressure:30 bar
Gas and oil flowrate
Pipeline pressure
Upstream geometry
Pressure: 50 bar
Figures from Fuchs (1997)

32. Important Severe Slugging Parameters
Stright pipe upstream
Gas and oil flowrate
Pipeline pressure
Upstream geometry
Pipe buckling upstream

33. 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
Miniseparators
Active choking
Model based regulation
Althoug is has been identified as early as 1973, severe slugging phenomena have not resived much atention until later 1990 for deep-water developments.
Yochum in 1975 identified several sevele slugging elimination techniques that we still consider to day. This was e.g. reduction of pipediameter, splitting of flow in more pipes.Mixing of dicvices at riser base.
All these elimination techniqes leads to higherflow rates in the pipe – and we we less possible be in the slug flow area.
Schmidt in 1979) noted that severe slugging could be eliminated or minimi8zed by chocking at the riser top. For deep water systems the back pressure increas can giv llarge reduction in flow capaity.
Pots used riser gas injection as an elimination method for severe slugging (changing GOR).
Hill in 1990 described riser-base gas injection test performed in a field to eliminate severe slugging. The gs injection was shown to eliminate severe slugging. They had to bring the flow patter n to annula flow.
Kaasa (1990) proposed a second riser connection the pipeline to the platform to eliminate severe slugging. Downward sloping pipe act as a slug catcher since stratified flow. The second riser filled with gas.
McGuinnes and Cooke – mixing of wellstreams can eliminate slug flow. Field case from Malaysia. New gas
Hollenber in 1995 proposed a topside flow control system to eliminate slugging. The principle is to keep the mixtrue flow rate constant through the operationwith a control valve. Use of control separator – easier to measurem flowrate..
Courbot proposed an automatic control scheme to prevent severe slugging in. The riser base presure was kept constant by a valve upstream of the separator to control the flow. Could casur reduction in production for dep waters. Long risers – delay in control sysrtems.
Subsea separation. Expensive.
Foaming – use of foming agents.
Sarcia and Tengesdal (2000) self gas lifting. Use own gas to produce a gaslift in the riser.
Slug reduction techniques can be divided into thre types:
Design changes.
Operational changes
Feedback controll

35. Gas injection at riser base
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

36. Self gas lifting + - (Sarcia & Tengesdal, 2000)
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

37. + - Higher pressure and smaller severe slug flow regime
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

38. 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
1.stage separator
PIC SP D PT MV
Used as
regulation valve -
Lower capacity of pipe
Can be a problem for deep waters

39. Robust operation – Optimize Well Production
(ABB)
OptimizeIT Active Well Control
- stabilizes the oil production from the well by active control of the production and/or injection choke

40. Robust operation – Increased/controled gas injection rate in gas lifts+
Increased gas flow rate and GOR (less chance for severe slugging)
Less static head
Annulus -
Increased frictional losses
Joule-Thomson Cooling
Need injection gas

41. 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

42. 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
Althoug is has been identified as early as 1973, severe slugging phenomena have not resived much atention until later 1990 for deep-water developments.
Yochum in 1975 identified several sevele slugging elimination techniques that we still consider to day. This was e.g. reduction of pipediameter, splitting of flow in more pipes.Mixing of dicvices at riser base.
All these elimination techniqes leads to higherflow rates in the pipe – and we we less possible be in the slug flow area.
Schmidt in 1979) noted that severe slugging could be eliminated or minimi8zed by chocking at the riser top. For deep water systems the back pressure increas can giv llarge reduction in flow capaity.
Pots used riser gas injection as an elimination method for severe slugging (changing GOR).
Hill in 1990 described riser-base gas injection test performed in a field to eliminate severe slugging. The gs injection was shown to eliminate severe slugging. They had to bring the flow patter n to annula flow.
Kaasa (1990) proposed a second riser connection the pipeline to the platform to eliminate severe slugging. Downward sloping pipe act as a slug catcher since stratified flow. The second riser filled with gas.
McGuinnes and Cooke – mixing of wellstreams can eliminate slug flow. Field case from Malaysia. New gas
Hollenber in 1995 proposed a topside flow control system to eliminate slugging. The principle is to keep the mixtrue flow rate constant through the operationwith a control valve. Use of control separator – easier to measurem flowrate..
Courbot proposed an automatic control scheme to prevent severe slugging in. The riser base presure was kept constant by a valve upstream of the separator to control the flow. Could casur reduction in production for dep waters. Long risers – delay in control sysrtems.
Subsea separation. Expensive.
Foaming – use of foming agents.
Sarcia and Tengesdal (2000) self gas lifting. Use own gas to produce a gaslift in the riser.
Slug reduction techniques can be divided into thre types:
Design changes.
Operational changes
Feedback controll

43. 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

44. Slugg Control at Heidrun Nordflanken Use 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

45. Slugging in riser Heidrun D-line
Trykk toppside oppstrøms choke
Large pressure variations
Periods ca. 17 minutes.
Disapears when chocking upstream
Tetthet toppside

46. Active Well Control at Brage A-21

47. OptimizeIT Active Well Control on Brage A-21
Starting Active Control
Pres. [bar]
Downhole pressure

48. 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

49. 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

50. Flow control in petroleum production
Noise suppression
Drag reduction
Water-oil flow
Flow assurance
Slug control
Multiphase flow simulation
Noise suppression – resonance in pipes. A problem sometoimes ocuring in oil prductin
Drag reduction and flow improvers
Water-Oil flow
Flow Assurance – emulsions, wax, hydrates,..
Slug control, …
Slug control will be the main focus of this presentation.

51. Drag reduction Internal flows (pipes, ducts) Wall modifications
~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
Horizontal flow: Almost 100% of pressure drop due to skin friction.
Drag reduction wil increas capasity a lot.
Can also prevent severe slugging due to easier flow of oil. Pumping power will be reduced or pipe-line diameters can be reduced.
Drag reduction can be obtained in two ways:
wall modifications (paintings, coating)
additives (fibers, dust)