DP Conference MTS Symposium Flow Assurance Elijah Kempton Tommy Golczynski Marine Technology Society September 30, 2004
Session Outline Flow Assurance Overview Key Flow Assurance Issues Wax Hydrates Slugging Deepwater Impacts on Flow Assurance Emerging Technologies Design Considerations Black Oil Systems Gas Condensate Systems
Flow Assurance Overview
What is Flow Assurance? Analysis of the entire production system to ensure that the produced fluids continue to flow throughout the life of the field. Optimization of the design and operating procedures to cost effectively prevent or mitigate slugging, surge volumes, wax deposition, gelling, hydrates, asphaltenes, etc.
Key Flow Assurance Issues Wax (Paraffin) What is it? A solid hydrocarbon which precipitates from a produced fluid Forms when the fluid temperature drops below the Wax Appearance Temperature (WAT) Melts at elevated temperatures (20 F+ above the WAT) Rate of deposition can be predicted for pigging frequency
Key Flow Assurance Issues Wax Since 1996, there have been 51 major occurrences that the MMS had to be involved in All were paraffin-related Means of remediation Pigging Continuous inhibition (150-250 ppm for Gulf of Mexico) Reduced wax deposition rate by 60-90% Industry Technology Modeling is overly-conservative (6X pigging frequency)
Key Flow Assurance Issues Example WAT Measurement Above WAT Wax Crystals (WAT) Seabed Temp. (40 F)
Key Flow Assurance Issues Factors effecting wax deposition rate Wax Appearance Temperature, WAT Production Fluid Temperature Flowline U-value Fluid Properties Viscosity N-Paraffin Content
Key Flow Assurance Issues Wax Deposition Insulation Impact
Key Flow Assurance Issues Hydrate What is it? An Ice-like solid that forms when: Sufficient water is present Hydrate former (i.e., methane) is present Right combination of Pressure and Temperature (High Pressure / Low Temperature Molecular Structure of Hydrate Crystal
Key Flow Assurance Issues Hydrates Primary cause for insulated flowlines Deepwater operations Increased operating pressure Cold ambient temperatures Means of remediation Crude oil displacement (looped flowlines) Depressurization Coiled tubing Continuous Inhibition (Prevention Only) Methanol/MEG LDHI
Key Flow Assurance Issues Hydrates Base Information 10000 9000 8000 7000 Pressure, psia 6000 5000 4000 Hydrates No Hydrates 3000 2000 Pure Water Sea Water 1000 Produced Water 0 40 45 50 55 60 65 70 75 80 85 Temperature, F
Key Flow Assurance Issues Hydrates Base Information Methanol Dosage, Methanol BBL MeOH/BBL Rate, gpm Water 50 0.600 45 0.575 0.550 40 0.525 35 0.500 30 0.475 25 0.450 20 0.425 0.400 15 0.375 10 5% Water Cut 10% Water Cut 20% Water Cut 25% Water Cut 30% Water Cut 40% Water Cut 50% Water Cut 25 GPM 0.350 761 GOR 1100 GOR 5 0.325 1700 GOR 2500 GOR 0 0.300 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 50 75 100 125 150 175 200 225 250 275 300 Shut-in Flowrate, Pressure, B/d bara
Key Flow Assurance Issues Slugging What is it? Periods of Low Flow Followed by Periods of High Flow Occurs in Multiphase Flowlines at Low Gas Velocities
Key Flow Assurance Issues Slugging Causes Low fluid velocity Bigger Better Seabed bathymetry (downsloping) Riser type Lazy-S is a slug generator Means of prevention Increase flowrate Separator pressure Gas lift Advantages Proven Technology Relative Inexpensive Gas Lift Overview Disadvantages Erosion Concerns Lower Temperatures Difficult with Catenary Risers
Key Flow Assurance Issues Slugging Gas Lift Impacts Liquid Liquid Accumulation Outlet Flowrate Above (B/d) Normal (bbl) 150 40000 25000 60000 35000 100 50000 20000 30000 50 40000 25000 15000 0 20000 30000 10000 15000-50 20000 10000-100 5000 10000 5000 5 MMSCFD 010 Gas MMSCFD Surge MMSCFD LiftVolume Gas Gas Lift Lift 0 MMSCFD Gas Lift 5 MMSCFD Gas Lift 10 MMSCFD Gas Lift -150 3.0 0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 3.0 3.5 4.0 4.5 5.0 Time 5.5 (hours) 6.0 6.5 6.5 7.0 7.0 7.5 7.5 8.0 8.0 Time (hours)
Key Flow Assurance Issues Other Issues Chemical Inventory Asphaltenes Scale Pour Point Corrosion Flare Capacity C-Factors Emulsions Surge Volume Cooldown Times Sand Liquids Management Erosion Depressurization Pigging
Deepwater Impacts on Flow Assurance Hydrate Formation/Wax Deposition Leads to: Insulation / dual flowlines Dry oil flushing Active heating Chemicals Revamped operating strategies Lack of pressure / need for boosting Deepwater + high water cut + long tiebacks Riser base gas lift Multiphase pumping Subsea separation
Deepwater: Temperature Losses Potential Energy Losses Gas does work in moving fluids Function of water depth Expansion Cooling (Joule-Thomson Effect) Exacerbated at large pressure differentials RISER DOMINATES DEEPWATER SYSTEMS Insulation may not be the answer!
Deepwater: 125 Temperature Losses 120 FLOWLINE WELLHEAD RISER BASE 115 Temperature ( F) 110 105 100 Potential Energy (Work) 48% Surroundings (U-Value) 6% RISER Joule-Thomson Cooling 46% TOPSIDES 95 0 1 2 3 4 5 6 7 8 Distance (miles)
Deepwater: Temperature Losses Flowline Temperature Drop ( F) Length (miles) 3 Flowline 1.2 Riser 16.6 6 2.9 16.6 15 9.2 16.5
Heat transfer coefficient (U-value) dictates steady state temperatures Q (heat loss) = U A T U-Value, Q T Thermal mass (ρ, Cp) impacts transient performance Measure of heat storage Prolongs cooldown times Prolongs warm-up times Deepwater: Temperature Losses
Transient Temperature Loss 110 100 90 Temperature ( F) 80 70 60 HIGH (Gelled Fluid #2 Water Base) MEDIUM (Gelled Fluid #1 Oil Base) 50 LOW (Nitrogen) 40 0 5 10 15 20 25 30 35 40 Time(hours)
Deepwater: Pressure Losses 2500 WELLHEAD 2000 FLOWLINE RISER BASE 1500 Pressure (psia) 1000 RISER 500 0 0 1 2 3 4 5 6 7 8 Distance (miles) TOPSIDES
Deepwater: Pressure Losses Flowline Pressure Drop (psia) Length (miles) 3 Flowline 143 Riser 1812 6 238 1791 15 405 1764
Deepwater: Dry Trees vs. Subsea Tieback Dry trees preferred for accessibility Dry trees more difficult for flow assurance Typically cannot depressurize Short cooldown times (2-8 hours) Fewer insulation/heating options than subsea Limited chemical (MeOH/MEG) deliverability Wax deposition more difficult to remediate
Dry Tree: Conduction / Convection / Radiation 100 Dry Tree Analysis: Cooldown Comparison Production Fluid Temperature 95 90 85 80 Temperature ( F) 75 70 65 60 HYDRATE FORMATION TEMPERATURE 55 50 45 Solid - Conduction Liquid - Conduction+Convection Gas - Conduction+Convection+Radiation 40 0 1 2 3 4 5 6 7 8 9 10 11 12 Time (Hours)
Dry Tree: Concentric vs. Non-Concentric Accommodate Auxiliary Lines? Concentric Non-Concentric Heat Transfer: Q = k A T / L (Conduction Only)
Dry Tree: Concentric vs. Non-Concentric
Dry Tree: Gas Properties 100 90 80 Temperature ( F) 70 60 15 psia N2 50 30 psia N2 59 psia N2 102 psia N2 40 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Time (Hours)
Design for Expansion Transient issues drive deepwater design Cooldown / restart - Hydrates Typical deepwater practice Dual flowlines / crude oil displacement Typically cannot depressurize (oil systems) Consider potential for future expansion Insulation Topsides facilities
Design for Expansion 22.5 km 10 km 8 km 8 km Total Time to Displace Existing System = 22 Hours (Sequential) Total Time to Displace Integrated System = 45 Hours (Sequential) High Level Insulation, or Additional Topsides Facilities Required!
Emerging Technologies Artificial Lift Subsea Separation (-) Multiphase Pumping (+) Gas Lift (+ / -) Passive Insulation Solutions Microporous Insulation Phase Change Materials
Emerging Technologies Active Heating Hot Water Circulation Electrically Heated Electrically-heated ready Chemicals Low Dosage Hydrate Inhibitors Cold Flow
Design Considerations: Black Oil and Gas Condensate Systems
Black Oil System: Steady State Design Checklist Hydraulics Line sizing Dry tree vs. subsea tieback Single vs. dual flowlines Dual flowlines becoming standard for deepwater Pressure drop Velocity / erosion (minimum / maximum) Slugging Thermal Insulation requirements Hydrate formation Wax deposition Gel formation
Black Oil System: Transient Design Checklist Shutdown Planned Unplanned Depressurization Restart Warm Cold Fluid displacement / pigging Flowline preheating
Black Oil Systems: Steady State Design Considerations
Black Oil System: Steady State Hydraulics Pressure drop effects Physical Line size Tieback distance Water depth Multiphase flow: Head losses <> head gains Pipe roughness (typical values) Steel: 0.0018 Tubing: 0.0006 Flexible pipe: ID/250 Fluid properties Gas/oil ratio (GOR) Density Viscosity May require insulation to limit viscosity Pressure (psia) 2500 2000 1500 1000 500 0 0 1 2 3 4 5 6 7 8 Distance (miles)
Black Oil System: Slugging Hydrodynamic High frequency Minimal facilities impact 7 6 5 4 Hydrodynamic Slugging Gas Outlet Flow 3 2 1 Terrain High liquid / gas flowrates Topsides concern Riser fatigue concern Utilize gas lift 0 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 80000 70000 60000 50000 40000 30000 20000 Time (hours) Terrain Slugging Liquid Outlet Flow 10000 0 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Time (hours)
Black Oil System: Slugging Slugging issues Sensitivity to Fluid GOR / water cut Water Cut (%) 0 20 40 60 80 Terrain Slugging Regime (BPD) / Surge Volume (BBL) 760 GOR 1300 GOR 1800 GOR 15000 / 150 12500 / 100 7500 / 75 20000 / 160 17500 / 100 15000 / 125 24000 / 175 20000 / 125 15000 / 130 26000 / 325 17500 / 250 10000 / 200 DNF 5000 / 400 5000 / 300
Black Oil System: Slugging Slugging issues Sensitivity to Trajectory: up vs. downslope -7500-7600 -7700 Original Route - 40 miles total length Alternate Route #1-36 miles total length Alternate Route #2-45 miles total length -7800-7900 Water Depth, ft -8000-8100 -8200 400 350 Original Route Alternate Route #1 Alternate Route #2 WELLHEAD RISER BASE -8300-8400 -8500-8600 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 Distance, miles Liquid Accumulation Above Normal* (bbl) 300 250 200 150 100 >24 hour Ramp-up Required 10 hour Ramp-up Required 50 50 bbl Slug Catcher Capacity 0 0 1 2 3 4 5 6 7 8 Time (hours)
Black Oil System: Steady State Thermal Design Hydrates Maintain steady state temperature above hydrate formation region, down to reasonable flowrate Looped flowline ~ 25% of field production (50% per flowline) For low water-cut systems, continuous hydrate inhibition is possible Future: continuous LDHI inhibition
Wax Black Oil System: Steady State Thermal Design Maintain temperature above WAT (stock tank), down to reasonable flowrate Looped flowline ~ 25% of field production (50% per flowline) Maintain viscosity at acceptable levels to reduce pressure drop Insulate to minimize pigging frequency Pigging frequency > residence time Continuous paraffin inhibition (if necessary)
Black Oil System: Steady State Thermal Design Insulation Option Flexible Wet (Syntactic) Burial Pipe-in-pipe Micro-porous Achievable U-value (BTU/hr-ft²- F) 0.75 1.50 0.50 0.75 0.50 1.00 0.20 0.25 0.08 0.10 Issue / Concern Limited insulating capacity Buoyancy issues Dependant on soil properties Combined with insulation Riser installation difficulties Industry acceptance
Black Oil System: Steady State Thermal Design 50.0 Arrival Temperature Water Cut = 0% Arrival temperature ( C) 48.0 46.0 44.0 42.0 40.0 38.0 36.0 34.0 32.0 30.0 Adiabatic (0 BTU/ft² hr ºF) 0.09 BTU/ft² hr ºF 0.20 BTU/ft² hr ºF 0.30 BTU/ft² hr ºF 0.50 BTU/ft² hr ºF 28.0 26.0 24.0 22.0 0.5 W/m².K 1.0 W/m².K 2 W/m².K 3.0 W/m².K no heat loss 20.0 7500 10000 12500 15000 17500 20000 22500 25000 27500 30000 32500 35000 37500 40000 Liquid Flowrate (blpd)
Black Oil Systems: Cooldown Design Considerations
Black Oil System: Cooldown Shutdown statistics Typical shutdown durations 89% shutdowns < 10 hours 94% shutdowns < 12 hours 99.9% shutdowns < 24 hours Typical shutdown causes Pumps Scale Corrosion Sand Paraffin Hydrates Asphaltenes Separation Other
Black Oil System: Cooldown Planned shutdown Procedure Inject hydrate inhibitor for one residence time (minimum) At high water cuts, may need to reduce flowrate to effectively treat system Inject hydrate inhibitor into subsea equipment Particular attention to horizontal components Self-draining manifold / jumpers Treat upper portion of wellbore SCSSV vs. top ~50 ft Shut-in system
Black Oil System: Cooldown Unplanned shutdown Procedure Determine minimum cooldown times No-Touch Time ~2-4 hours / no action taken subsea Light Touch Time ~2-4 hours / treat critical components Time is a function of chemical injection philosophy / number of wells Preservation Time Time required to depressurize or displace flowlines with non-hydrate forming fluid Time=0 Time=4 Time=8 No-Touch Light Touch Preservation
Black Oil System: Cooldown Insulation selection Cooldown time determined by: U-Value Thermal mass (ρ, Cp) Measure of heat storage Line size impacts Bigger = More Thermal Mass Gas / liquid interface typically controlling point Gas = low thermal mass Highest pressure Coldest temperature Temperature (F) 150 Pipe-in-Pipe (0.20 BTU/hr-ft²-F) 140 Wet Insulation (0.75 BTU/hr-ft²-F) 130 Flexible Pipe (1.00 BTU/hr-ft²-F) 120 110 100 90 80 70 60 HYDRATE FORMATION (PURE WATER) 50 40 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 Time (hours)
Black Oil System: Cooldown 140 0 hours (Steady State) 130 120 110 RESERVOIR WELLHEAD FLOWLINE 1 hours 2 hours 4 hours 6 hours 8 hours 10 hours 100 12 hours 18 hours Temperature (F) 90 80 24 hours 70 60 50 40 RISER 30 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Distance (miles)
Black Oil System: Cooldown 6000 5500 5000 RESERVOIR 0 hours (Steady State) 24 hours 4500 4000 WELLHEAD Pressure (psia) 3500 3000 2500 2000 FLOWLINE 1500 RISER 1000 500 0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Distance (miles)
Black Oil System: Cooldown 1.0 0.9 RESERVOIR WELLHEAD FLOWLINE 0.8 0.7 Liquid Holdup (-) 0.6 0.5 0.4 0.3 0.2 0.1 0 hours (Steady State) RISER 24 hours 0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Distance (miles)
Black Oil System: Cooldown 60 WELLHEAD 50 RESERVOIR FLOWLINE 40 Hydrate Propensity, T-Thyd (F) 30 20 10 0 hours (Steady State) 1 hours 0 2 hours 4 hours 6 hours -10 8 hours 10 hours -20 12 hours 18 hours RISER 24 hours -30 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Distance (miles)
Black Oil System: Cooldown Checklist Is there adequate chemical injection to treat subsea components within cooldown time? Wellbore Trees Jumpers Manifolds What is the subsea valve closure philosophy? Packed: More liquid / higher pressures Un-packed: Less liquid / lower pressures Does insulation provide sufficient cooldown time? No-touch Light-touch Preservation Is gel formation a possibility? If yes, system design philosophy changes Is SCSSV set deep enough to avoid hydrates?
Black Oil Systems: Depressurization Design Considerations
Black Oil System: Depressurization Hydrate remediation strategy Reduce pressure below hydrate formation pressure at seabed Effectiveness based on: Fluid properties GOR Water cut Seabed bathymetry Upslope Downslope Deepwater issues 10000 9000 8000 7000 6000 5000 4000 3000 Phyd ~ 200 psia Pure Water 2000 Sea Water 1000 Produced Water 0 40 45 50 55 60 65 70 75 80 85 Temperature, F Reduce pressure to ~200 psia at seabed Maintain pressure below hydrate conditions during restart Time=0 Time=4 Time=8 Pressure, psia No-Touch Light Touch Preservation : Depressurization
Depressurization:Subsea Tieback 4500 4000 BOTTOM HOLE 3500 3000 2500 FLOWLINE 0.0 hours 0.5 hours 1.0 hours Pressure (psia) 2000 1500 1000 MUDLINE 500 RISER BASE 0 0 1 2 3 4 5 6 7 8 9 Distance (miles)
Depressurization Dry Tree 4500 4000 3500 3000 BOTTOM HOLE 0.0 hours 0.5 hours 1.0 hours Pressure (psia) 2500 2000 1500 1000 SCSSV MUDLINE 500 GAS/LIQUID INTERFACE 0 0 2000 4000 6000 8000 10000 12000 Distance (feet)
Black Oil System: Depressurization Checklist Can you depressurize below hydrate formation conditions? If YES, can you depressurize in late-life at high water cuts? If YES, can you maintain pressure below hydrate formation conditions during restart? Difficult for deepwater If YES, is there a pour point concern? Depressurization increases restart pressure requirements If NO, consider the following for hydrate prevention: Displacement (dual flowlines) Active heating Continuous chemical inhibition
Black Oil Systems: Displacement Design Considerations
During Prevention time, displace produced fluids from flowline Time=0 Black Oil System: Displacement Hydrate Prevention - Shutdown Unable to get hydrate inhibitor to in-situ fluids during shutdown Dual flowlines required Sufficient insulation / cooldown time Function of flowline length Time=4 Time=8 No-Touch Light Touch Preservation : Displacement
Black Oil System: Displacement Discharge Pressure Required HOLD BACKPRESSURE AT OUTLET
Black Oil System: Displacement Hydrate Prevention - Shutdown 1800 Dead Oil Flushing - Year 5 FPSO Pump Discharge Pressure FPSO Arrival Pressure Controlled at 1500 psia 1600 1400 Produced fluids move up second riser Gas breaks through second riser 1200 Pig moves up second riser 1000 800 600 400 200 Pig reaches base of first riser 0 0 0.5 1 1.5 2 2.5 3 3.5 Time (H)
Black Oil System: Displacement Hydrate Prevention - Shutdown During Prevention time, displace produced fluids from flowline Topsides design considerations Available backpressure Circulation rate Limited by pig integrity Typically 3-5 ft/sec May be faster for straight-pipe Storage volume Circulation passes With pig: 1 residence time Without pig: 2-3 residence times for efficient water removal
Black Oil System: Displacement Hydrate Prevention Dry Tree During shutdown, how quickly will fluids fall below SCSSV? Very little work done with L/D ratios >100 (deepwater riser ~10000) Field data shows oil/water separation ~ 70-80 ft/hr Bullhead / displace with non-hydrate forming chemical to SCSSV Methanol/MEG (volume concerns) Heavy diesel (high density, by-pass produced fluids) Dead oil Ability to bullhead a function of displacement rate
Is there sufficient time to accomplish displacement operation? Sufficient insulation / Cooldown time Is the topsides facility designed to accomplish displacement operation? Pump capacity Storage capacity Black Oil System: Displacement Checklist Can system be restarted into crude-oil filled flowline? Displace with gas? High pour point fluids what is the restart pressure required? For dry trees, is a proper fluid available for displacement?
Black Oil Systems: Restart Design Considerations
Black Oil System: Cold Restart System pressure < hydrate formation conditions throughout restart? For deepwater, hydrostatic pressure in riser too high Separator pressure: may need alternate start-up vessel Hydrate inhibition required until arrival temperature reaches Safe Operating Temperature (SOT) Maintain hydrate inhibitor rate: Fluid completely inhibited Reduce hydrate inhibitor rate: Fluid not completely inhibited to shut-in conditions SOT is minimum topsides temperature that provides sufficient cooldown time, in the event of an interrupted restart
Black Oil System: Cold Restart 0.60 0.55 Methanol Dosage, BBL MeOH/BBL H2O 0.50 0.45 0.40 0.35 0.30 PURE WATER 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 Shut-in Pressure, psia SEA WATER PRODUCED WATER
Black Oil System: Cold Restart 50 45 40 75% WATER 50% WATER Methanol, gpm 35 30 25 20 25% WATER 15 10 5 5% WATER 0 2000 3000 4000 5000 6000 7000 8000 9000 10000 Flowrate, BPD
Black Oil System: Cold Restart Achievable restart rates determined by: Shut-in conditions Fluid GOR Water cut Hydrate inhibitor Rule of Thumb : Greater inhibitor injection rates result in lower overall inhibitor volumes used during restart Small tiebacks: 5-10 gpm / well Large deepwater: 25+ gpm / well Warm-up trends: Wellbore: Very quick (<30 minutes) Flowline: Function of flowrate / water cut / length / insulation
Black Oil System: Cold Restart
Black Oil System: Cold Restart
Cold Restart: Case Study 3 Mile Tieback Warm-up Time Insulation Type 5000 STBPD 10000 STBPD Max Flowrate Micro-porous 5.8 2.9 1.1 Pipe-in-pipe 6.1 3.0 1.1 Conventional 9.2 3.5 1.2 Flexible 10.6 3.2 1.1 Buried > 24 8.4 1.5
Cold Restart: Case Study 15 Mile Tieback Warm-up Time Insulation Type 5000 STBPD 10000 STBPD Max Flowrate Micro-porous > 24 13.0 7.0 Pipe-in-pipe > 24 14.0 7.2 Conventional > 24 > 24 10.9 Flexible > 24 > 24 12.3 Buried > 24 > 24 > 24
Cold Restart: Case Study 15 Mile Tieback MeOH Volume Insulation Type 5000 STBPD 10000 STBPD Max Flowrate Micro-porous > 850 798 772 Pipe-in-pipe > 850 814 781 Conventional > 850 > 1700 1074 Flexible > 850 > 1700 1053 Buried > 850 > 1700 > 2300
Is there sufficient hydrate inhibitor available? Delivery rates Storage volumes Black Oil System: Restart Checklist How will multiple wells be restarted? Single well at max. rate Multiple wells at reduced rate Single flowline vs. dual flowline What is the minimum temperature required to achieve safe conditions? Safe Operating Temperature (SOT)
Black Oil System: Summary of Design Considerations Hydraulics Ensure Production Delivery Throughout Field Life Minimize Slugging Wax Deposition Minimize Wax Deposition (Insulation/Pigging/Chemicals) Hydrate Formation Avoid Steady State Hydrate Formation Optimize Cooldown Times (Insulation) Prevent Transient Hydrate Formation (Depressurization/Displacement/Chemicals) Minimize Inhibitor Consumption