Flow Control in Oil/Gas Wells and Pipelines

1. 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)

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 (Oliemans, 1994, Sarica and Tengesdal, 2000)

5. Multiphase Transport Solutions The Åsgard field:Floating production system The Snøhvit solution:Transport directly to shore (www.statoil.com)

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

7. 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

8. Callenges for Deep Water Developments (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)

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

11. Flow control: emulsion viscosity Oil-water mixtures: Increase in viscosity close to inversion point Use of emulsion breaker to lower viscosity

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. 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++

15. Horizontal Two-Phase Flow • Segregated flow • Stratified • Annular • Wavy • Intermittent • Slug flow • Plug flow • Distributive flow • Bubble/mist flow • Froth flow

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

17. Inclined flow • Waves!

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

19. 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

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

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 • Flow rate measurement problems

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) (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

35. 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. 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. 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. Used as regulation valve SP PIC MV 1.stage separator PT PT D 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

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

40. Annulus 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

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

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 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

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