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The Science and Economics of Multiphase Flow
The document discusses the science and economics of multiphase flow in petroleum engineering, covering aspects such as fluid mechanics, pressure changes, nodal analysis, and flow assurance. It emphasizes the importance of accurate modeling and analysis for optimizing offshore and onshore production systems, while also addressing challenges posed by various fluid properties and terrain effects. Concluding remarks highlight the necessity of integrating economic considerations with technical advancements to maximize production and minimize operational risks.
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The Science and Economics of Multiphase Flow
- 1. Society of PetroleumEngineers Distinguished Lecturer Program www.spe.org/dl Mack Shippen The Science and Economics of Multiphase Flow
- 2. Outline – Introduction – TheScience of Multiphase Flow – The Economics of Multiphase Flow – Concluding Remarks 3 3
- 3. A Broad Viewof Fluid Mechanics milliseconds 1m 1s Detonation Reservoir Pipelines Terrain Slugs Molecular Diffusion Chemical Reactions Cavitation Severe Riser Slugging Hyd. Slugs Bubbly Flow Formation Damage Wax Corrosion Hydrates Scale Erosion & Shut-in 4 Focus of this talk
- 4. Total Production System Completion Choke SafetyValve Tubing Flowline Pump Compressor Separator Export lines Riser Reservoir gas oil Artificial Lift 5
- 5. Pressure Changes Separator gas oil DP Safety Valve DP Reservoir Drawdown DP Completion DP Wellhead Choke DP Flowline DP Compressor DP Oil Export DP Gas Export DP Tubing DP Riser DP Pump • Flow in porous media • Artificial Lift • Multiphase Flow in pipes • Chokes/restrictions • Pumps/Compressors 6
- 6.
- 7. Temperature Changes Separator gas oil DT Safety Valve DT Completion DT Wellhead Choke DT Flowline DT Compressor DT Oil Export DT Gas Export DT Tubing DT Riser DT Pump • Convection (free, forced) • Conduction • Elevation • JT Cooling/Heating • Frictional Heating 8
- 8.
- 9. Outline – Introduction – TheScience of Multiphase Flow – The Economics of Multiphase Flow – Concluding Remarks 3 10
- 10. Liquid Holdup • Functionof the degree of gas-phase slippage • Gas travels faster because of lower density and viscosity • Higher mixture velocity less slip 3 Qg = VgAg QL = VLAL Vg Ag VL AL AL AG No slip slip Holdup = 0 All gas flow Holdup = 1 All liquid flow 𝐻𝐿 = 𝐴 𝐿 𝐴 𝑃𝐼𝑃𝐸 11
- 11. Pressure Losses Terrain effectsare important! pressure losses uphill are only partially recovered going downhill 12 ∝ velocity ∝ viscosity ~ zero∝ density 12
- 12. Evolution of 1DSteady-State Multiphase Models MorePhysics 2000 2010199019801970196019501800 Single-Phase Homogeneous (Mixture Reynolds No.) Darcy-Weisbach-Moody Flow Regime Slip Zuber & Findlay Drift Flux Hagedorn & Brown Dukler, Eaton & Flanigan Gray Empirical Category B 2-Phase (Gas-Liquid) 3-Phase (Gas-Oil-Water) Inclination Angle Evolutionary Key: Flow Regime Slip Lockhart & Martinelli Poettmann& Carpenter Empirical Category A Baxendell & Thomas Empirical Category C Flow Regime Slip Mukherjee & BrillDuns & Ros Beggs & Brill SLB Drift-Flux Orkiszewski Mechanistic (Phenomenological) AnsariGovier, Aziz & Fogarasi Taitel & Dukler Xiao TUFFP Unified Hasan & Kabir OLGA-S LedaFlow PM 4500 30 190 # lines of code 13 State of th State-of- the-Art
- 13. 3-Phase Mechanistic FlowModels 3 BHR 2007-A2 • Based on combined force and momentum balances and best represent the physics of multiphase flow • Account for broad ranges of fluids and pipe geometries • Top 3 (State-of-the-Art) include OLGAS, LedaFlow and TUFFP Reality Model SPE 19451 SPE 95749 14
- 14. Oil-Water Flow 6-inch pipe 1500BOPD 1500 BWPD 1.5 cp oil 2º up 2º down 0º 15 Oil−water flow experiments in 6-in.-diameter pipe (oil shown with red dye and water with blue dye). Each case has identical volumetric flow rates: 1500 bpd of each phase. The left- hand image shows upward flow inclined at θ = +2 ° (from the horizontal). The center image shows horizontal flow θ =0 °, while the right- hand image shows downward flow inclined at θ = −2° (from the horizontal). We observe that in the left-hand image, oil "slips" much faster over the water. In the center image, we have near- perfect stratified flow with no discernible slippage between phases, while in the right- hand image, we observe water rapidly slipping beneath the oil. These experiments clearly show how even a small inclination in pipe elevation can have a dramatic effect on slippage and associated flow regimes.
- 15. Rule of 10’sFor Today’s “State of the Art” Stable Flow < Operating Rate < Erosional Limits Deviation angles ±10º of vertical or horizontal Liquid volume fractions > 10% Water or oil fraction < 10% relative to total liquid Pipe diameters < 10 inches Oil viscosities < 102 centipoise 3 Can generally expect +/- 10% Error in Accuracy of Holdup and Pressure Predictions for conditions of: 16
- 16. Multiphase Flow ResearchCenters IFE, Norway Sintef, Norway Cranfield University (TMF), UK University of Tulsa (TUFFP), US 17
- 17. Top 5 R&DChallenges 3. Exotic Fluids - Heavy Oil - Foam - Slurries 5. Model Discontinuities 4. Improved Closure vv Relationships 2. Odd Angles 1. 3+ Phases 18
- 18. Outline – Introduction – TheScience of Multiphase Flow – The Economics of Multiphase Flow – Concluding Remarks 3 19
- 19. Economics “Economics is thestudy of the use of scarce resources which have alternative uses” - Lionel Robbins 20
- 20. Examples Example Description 1 -Offshore Field Planning Offshore Oil 2 - Slug Catcher Sizing Offshore Gas Condensate 3* – Terrain Effects Onshore Shale Oil 4* – Heavy Oil Pipeline Onshore Heavy Oil * Backup example for onshore focused audiences – see supplemental slides 21
- 21. Example 1: OffshoreField Planning PlatformCost Platform Capacity Ultra-deep Deep Shallow 22
- 22. Example 1: OptimalPlatform Size 1 32 Time OilProductionRate Oil Production Capacity NetPresentValue(NPV) 23
- 23. Example 1: IntegratedModeling Constraints: Reservoir Forecast Production Network Process Facilities Max. Liquids: 80,000 BPD Max. Water: 25,000 BPD Max Gas Lift: 100 MMscfd Compressor power: 9,000 Hp. Production Network IPTC-11594 24 24
- 24. Example 1: Dealingwith thru-life constraints IPTC-11594 Dominant Constraint: Total Liquid Production Rate Dominant Constraint: Total Compressor Power Dominant Constraint: Water Handling Capacity Dominant Constraint: Operating Costs 25
- 25. Example 1: GasLift Optimization OilProductionRate Total Gas Lift Injection Rate Oil Rate Optimum Field Well 1 Well 2 Economic Optimum (Qo/Qgi) Numerous published field studies have shown gas lift optimization to improve production by 3-15% SPE175785SPE 120664SPE 123799 26
- 26. Example 2: LiquidsHandling for Offshore Wet Gas Export Pipeline 100-mile 32” 50-mile 24” wet gas 20-mile 12” dry gas Onshore Slug Catcher PSIG 0403 30-mile 16” wet gas 27
- 27. Example 2: Pigginga Flowline Why? • Remove solids > reduce blockage risk • Remove liquids > less pressure loss VL VG VM VL VGVM Size of slug proportional to gas-liquid slip 28
- 28. Example 2: Ramp-UpSurge Qg initial Qg final Qg surge VL VL VL Size of surge proportional to difference in liquid content before and after 29
- 29. Example 2: SlugCatcher Sizing SLIP (Pig) SURGE (Ramp-Up) PSIG 0403 OLGASRampUp OLGASPig XiaoRamp XiaoPig $30M $16M Installed Cost: 30
- 30. Example 2: SlugCatcher Sizing Uncertainties PSIG 1603 31
- 31. Example 2: SlugCatcher Sizing Deterministic Analysis -30% 25% -60% 40% PSIG 1603 32
- 32. Example 2: SlugCatcher Sizing Probabilistic Analysis P-10 P-50 P-90 P-50 P-90 P-10 PSIG 1603 33
- 33. Example 2: SlugCatcher Sizing Economics PSIG 1603 34
- 34. Example 3: SimplePressure Drop Calculation 5 mile, 4” flowlineGOR = 5000 scf/STB 45° API Gravity QL = 1000, 100 BPD Your Job: Calculate the required inlet pressure! 500 psia 35
- 35. Example 3: TerrainEffects 62 feet 5 miles Absolute difference (Net - 0.14°) Terrain effects (+/- 4°from horizontal) 36
- 36. Example 3: Results– Pressure Loss 1,000 BPD 100 BPD Vmix ~ 2 ft/s Stratified-Smooth & Slug Flow D Z Terrain Takeaway: Terrain Effects Critical For Low Rate Cases! Vmix ~ 15 ft/s Stratified-Wavy & Slug Flow 37
- 37. Example 3: Results– Liquid Holdup (OLGAS) 1,000 BPD 100 BPD D Z Terrain HL (no-slip) ~ 5% Slug Stratified Slug Stratified 38
- 38. Example 3: Results– Pigging Volumes 1,000 BPD 100 BPD D Z Terrain Takeaway: Terrain Effects Critical For Low Rate Cases! PigSlugVolume(bbl) 0 10 20 30 40 50 60 70 80 90 100 PV (Terrain) PV(DZ) PV (Terrain) PV(DZ) OLGAS TUFFP PIGSLUGVOLUME(BBL) Pig Slug Volume PigSlugVolume(bbl) 39
- 39. Example 3: JustPart of the Network! Shale Oil Network: Eagleford Field, Texas 40
- 40. Example 4: Inspiration TheEl Morro Araguaney Pipeline 41
- 41. Example 4: HeavyOil Pipeline Pin = 800 psia 16◦ API 30 % watercut Pout = 800 psiaCalculate Liquid Rate 42
- 42. Example 4: DiluentInjection – 5.7” pipe pump No pump ~ 7000 BPD OIL ~ 5000 BPD DILUENT ~ 3500 BPD OIL ~ 3600 BPD DILUENT ~10,000 cp ~ 300 cp 43
- 43. Example 4: DiluentInjection – 7” pipe pump No pump ~ 7000 BPD OIL ~ 3500 BPD OIL ~ 2700 BPD DILUENT ~ 1800 BPD DILUENT 44
- 44. Example 4: PipelineEconomics Method Effect Constraints OPEX CAPEX Pump ↑ pressure ↔ friction loss MAOP Power ↔ Med ↑ High Diluent ↓ viscosity ↓ friction loss Diluent availability Power ↑ High ↔ Med Larger Pipe size ↓ velocity ↓ friction loss Phase of development ↓Low ↑ High DRA ↓ turbulence ↓ friction loss ↔ Med ↓Low Maximum Allowable Operating Pressure Drag Reducing Agents Operating Cost Upfront Capital Cost MAOP = DRA = OPEX = CAPEX = 45
- 45. Outline – Introduction – TheScience of Multiphase Flow – The Economics of Multiphase Flow – Concluding Remarks 3 46
- 46. Concluding Remarks • Goodtechnology in multiphase flow modeling has emerged from years of research and development • Challenges still remain flow assurance is not a certainty • Economics justify the Science! • Ultimate goal is to maximize production while minimizing flow assurance risks and operational costs 47
- 47. An Integrated Viewof Fluid Mechanics Pipelines Wellbores Reservoir Process Equipment 48
- 48. Society of PetroleumEngineers Distinguished Lecturer Program www.spe.org/dl Your Feedback is Important Enter your section in the DL Evaluation Contest by completing the evaluation form for this presentation Visit SPE.org/dl
- 49.
- 50. Flow Assurance –Getting it Right • Deepwater development ~ $3-10B • Subsea infrastructure ~ $1-3B • Slugcatcher ~ $30M • Subsea booster ~ $250M • Offshore downtime costs ~ $8M/day Onshore Slugcatcher Subsea Booster S1
- 51. Example 1: ESPOptimization OilProductionRate Total ESP Power Oil Rate Optimum Field Well 1 Well 2 Economic Optimum (Qo/Qgi) S2
- 52. Flow Assurance -Solids Problems Asphaltene Wax Scale Hydrate S3
- 53. Multiphase Flow DesignTasks Time ProductionRate Target Rate 50% Turndown Natural flow Artificial Lift Decline Line Sizing 2 2 Arrival Temperature Equipment Selection & Sizing Erosion constraints 1 1 3 Backpressure effects 3 4 Wellbore Artificial Lift 5 4 5 Multiphase Boosting Liquids Management 7 7 Hydrodynamic Slugs 6 Pigging 6 Watercut GOR Shut-in & Start-up Operations 8 Ramp-up 8 10 Solids Formation 10 11 Gelling (kick-off pressure) 11 Steady-State Dynamic Terrain Slugging9 9 S4
- 54. Common Flow AssuranceWorkflows Basic Detection Good Approximation Rigorous Key: Full Transient Steady- State (SS) Liquids Handling Ramp-up Surge (Cunliffe’s Method) Ramp-up Surge Pigging volumes Hydrodynamic Slugs Terrain Slugs Severe Riser Slugs Pigging volumes Hydrodynamic Slugs Terrain Slugs Severe Riser Slugs Slugtracking Pipe Integrity CO2 Corrosion CO2 Corrosion (SS) Erosion Erosion (SS) Leak/Blockage Detection Leak/Blockage Detection Solids Wax Prediction Scale Prediction Wax Deposition Hydrate Prediction Hydrate Prediction Wax Prediction Hydrate Kinetics/ plugging Wax Deposition Asphaltene Prediction Well-Specific Liquid Loading Liquid Loading Nodal Analysis Gas Lift Unloading Artificial Lift Diagnostics Gas Lift Unloading Well Testing Wellbore Cleanup Worst Case Discharge (Blowout) Worst Case Discharge (Blowout) Artificial Lift Diagnostics Application Shut-down/ Start-up Shut-in (Cooldown) System Start-up Depressureization S5