spe distinguished lecturer series spe foundation€¦ · fluid selection for deepwater completions...
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SPE DISTINGUISHED LECTURER SERIESis funded principally
through a grant of the
SPE FOUNDATIONThe Society gratefully acknowledges
those companies that support the programby allowing their professionals
to participate as Lecturers.
And special thanks to The American Institute of Mining, Metallurgical,and Petroleum Engineers (AIME) for their contribution to the program.
Fluid Selection for Deepwater Fluid Selection for Deepwater Completions Completions –– New Frontiers Bring New Frontiers Bring
New Fluid Related ChallengesNew Fluid Related Challenges
Syed A. AliChevron Energy Technology Company
OutlineOutline
• General Selection Criteria for Completion Fluids
• Special Considerations for Deepwater
• Compatibility Issues
• Operational Issues
• Packer Fluid Issues
• Summary
General Completion Fluid Selection General Completion Fluid Selection CriteriaCriteria
• DensitySalt type
• Crystallization TemperatureThermodynamic Crystallization Temp (TCT)
• Formation DamageCompatibility with Rock MatrixCompatibility with Formation Fluids
• Corrosion• Cost• HSE
Special Considerations for DeepwaterSpecial Considerations for Deepwater
• Formations Require Sand ControlDictate the use of clear brines
• Unique Water EnvironmentHigh Pressure / Low Temperature (HPLT)Low Temperature at mud line (38 – 40°F)High pressures at mud line
Hydrate formationPressure induced crystallization
• Compatibility with Well Construction MaterialsCRA tubulars
Stress corrosion cracking (SCC)Control line & chemical injection fluids
Low Mud Line Temperature GoMLow Mud Line Temperature GoM
38 – 40°F < 4500’
Density / Brine Type / CostDensity / Brine Type / Cost
9.7 10
11.6 11.1
12.7 13.1
15.1
20.519.1
02468
101214161820
KCl
NaCl
CaCl2
NaHCO2
NaBr
KHCO2
CaBr2
ZnBr2
CsHCO2
Brine Type
Den
sity
(lb/
gal)
0
500
1000
1500
2000
2500
3000
3500
4000
4500
$/bb
l for
hig
hest
Den
sity
Brine Density ProfilesBrine Density Profiles
ShelfDeepwater
mud line
0
2000
4000
6000
8000
10000
12000
14000
16000
9.22 9.24 9.26 9.28 9.30 9.32 9.34
ESD - (lb/gal)
True
Ver
tical
Dep
th -
(ft)
0
2000
4000
6000
8000
10000
12000
14000
16000
9.27 9.28 9.28 9.29 9.29 9.30 9.30
ESD - (lb/gal)
True
Ver
tical
Dep
th -
(ft)
Density (lb/gal)Density (lb/gal)
Shelf WellDeepwater Well
Mud Line
Brine Crystallization (TCT)Brine Crystallization (TCT)Phase Diagrams for CaCl2 and CaBr2 Brines
-65
-55
-45
-35
-25
-15
-5
5
15
25
35
45
55
65
8.338.8 9.3 9.8 10.3
10.811.3
11.812.3
12.813.3
13.814.3
14.815.3
Density (lb/gal)
TCT
(deg
F)
TCT (CaCl2) TCT (CaBr2)
Effect of Pressure on Crystallization Effect of Pressure on Crystallization (PCT)(PCT)
Effect of 10,000 psi Pressure on TCT of CaCl2
-50-45-40-35-30-25-20-15-10
-505
10152025303540455055606570758085
8.3
8.4
8.5
8.68.7
8.8
8.9
9.0
9.1
9.2
9.3
9.49.5
9.6
9.7
9.8
9.9
10.0
10.110.2
10.3
10.4
10.5
10.6
10.7
10.810.9
11.0
11.1
11.2
11.3
11.4
11.5
11.611.7
Density (lb/gal)
TCT
(deg
F)
TCT PCT
Pressure lowers freezing pointPressure raises crystal point
Consequence of Ignoring PCTConsequence of Ignoring PCT
Hydrate FormationHydrate Formation• Water forms a cage-like
structure around a gas molecule:
• Methane• Ethane • Propane• Isobutane• Normal butane• Nitrogen• Carbon dioxide• Hydrogen sulfide
• Hydrate formation requires:• Water• Gas • Low temperature• High pressure
Hydrate FormationHydrate Formation
• Thermodynamic InhibitorsExamples: glycols, alcohols, dissolved salt
• Kinetic InhibitorsReduce rate of hydrate formation
• Anti-agglomerantsReduce crystal sizeHydrate forms “slurry”
Note: Thermodynamic Inhibitors are used in brines
Hydrate Protection
Hydrate Equilibrium PredictionHydrate Equilibrium Prediction• Laboratory Measurements• Computer Models
WHyP
Hydrate Formation Pressure of CaClHydrate Formation Pressure of CaCl2 2 at 40at 40°°FF
Hydrate Inhibition by CaCl2 at 40 degF
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
13000
14000
15000
16000
17000
18000
9.4 9.5 9.6 9.7 9.8 9.9 10 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8
Density of Pure CaCl2
Pres
sure
(psi
)
Hydrate Inhibition with GlycolHydrate Inhibition with GlycolHydrate Protection of CaCl2 at 40F
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
9.3 9.4 9.5 9.6 9.7 9.8 9.9 10 10.1 10.2 10.3 10.4 10.5 10.6 10.7
Density of CaCl2 (ppg)
Hyd
rate
For
mat
ion
Pres
sure
(psi
)
CaCl2 requires Hydrate Inhibitor (MEG) to Control Hydrates to 10,000 psi
8.7% MEG
5.3% MEG
30% MEG
19% MEG
HPLT Leads to Hydrates or PCTHPLT Leads to Hydrates or PCT
-50-45-40-35-30-25-20-15-10
-505
10152025303540455055606570758085
8.38.48.58.68.78.88.99.09.19.29.39.49.59.69.79.89.910.010.110.210.310.410.510.610.710.810.911.011.111.211.311.411.511.611.7
Density (lb/gal)
TCT
(deg
F)
TCTHydrate Region PCT Region
Compatibility Flow ChartCompatibility Flow Chart
Spacer Compatibility TestingSpacer Compatibility Testing
15.4 lb/gal SBM and HEC Spacer
0
50
100
150
200
250
300
350
400
100% OBM 75% OBM 50% OBM 25% OBM 100% Spacer
PVYP60030020010063
15.4 lb/gal SBM and HEC Spacer
Zinc Perforation DebrisZinc Perforation Debris--Brine Brine CompatibilityCompatibility
CaBr2CaBr2 with Zinc
debris
CrudeCrude--Brine CompatibilityBrine Compatibility
O/W emulsion Brine treated with non-emulsifier
CrudeCrude--Brine CompatibilityBrine Compatibility((Emulsion Preventer Adsorption)Emulsion Preventer Adsorption)
25% 50% 75% Pre-treated 11.4 lb/gal CaCl2
25% 50% 75% 11.4 lb/gal CaCl2 with 0.25 vol% SAFE-BREAK CBF (Filtered)
CrudeCrude--Brine CompatibilityBrine Compatibility(Iron Contamination)(Iron Contamination)
5 0 %
1 1 .4 lb /g a l C a C l2 + 2 0 0 0 p p m F e C l 3
Formation WaterFormation Water--Brine CompatibilityBrine Compatibility
Salt PrecipitationFormation water +
nearly saturated brine
Calcium Carbonate PrecipitationFormation water +
Calcium brine
With Scale InhibitorNo Scale Inhibitor
With Scale InhibitorNo Scale Inhibitor
With Scale InhibitorNo Scale Inhibitor
Formation WaterFormation Water--Crude CompatibilityCrude Compatibility
Calcium Calcium NaphthenateNaphthenate ScaleScale
Calcium Naphthenate Scale
•• During the production of acidic During the production of acidic crudescrudes (high TAN), (high TAN), increases in the pH value due to COincreases in the pH value due to CO2 2 degassing degassing leads to the formation of :leads to the formation of :
Mixed carbonate and calcium Mixed carbonate and calcium naphthenatenaphthenate deposits deposits inside tubing or surface installations.inside tubing or surface installations.
Stable emulsions associated with the strong surfaceStable emulsions associated with the strong surface--active power of the active power of the naphthenatenaphthenate group. group.
•• Three species contribute to calcium Three species contribute to calcium naphthenatenaphthenatedeposits:deposits:
NaphthenicNaphthenic acidacidCalciumCalciumBicarbonateBicarbonate
FormationFormation--Brine CompatibilityBrine CompatibilityChevronTexaco Tahiti Project
Test Fluid 14.8 lb/gal Calcium Bromide/Zinc BromideCore #2-37
0
50
100
150
200
250
300
350
400
450
500
0 20 40 60 80 100 120 140 160
Cumulative Flow, Pore Volumes
Perm
eabi
lity,
mD
Inject 2 pore volumes of test brine.Hold for 1 hour.
Resume flow in the injection direction
Ki = 434 mDKf = 415 mD
96% Return Permeability
Frac FluidFrac Fluid--Brine CompatibilityBrine Compatibility
VES Frac Fluidwith CaBr2Brine
VES-Brine Sludge recoveredfrom trip tank
ElastomerElastomer--Brine CompatibilityBrine Compatibility
Hardness Nitrile Rubber
Exposure Time (days)
MetallurgyMetallurgy--Brine CompatibilityBrine Compatibility
79.867.435.31.00.119.2ZnBr2 / CaCl2 / CaBr2
19.813.410.00.30.117.0ZnBr2 / CaCl2 / CaBr2
6.62.92.40.50.115.1CaCl2 / CaBr2
3.01.61.60.90.313.6CaCl2 / CaBr2
1.90.90.70.20.111.6NaBr0.10.10.10.40.312.4CaCl2
0.10.10.10.70.411.2NaCl / NaBr0.10.10.21.50.510.0NaCl
350°F300°F250°F150°F70°FDensity(lb/gal)
Brine Type
Corrosion Rates for Brines Without Inhibitor(N-80 Steel, 30 Days, mpy)
79.867.435.31.00.119.2ZnBr2 / CaCl2 / CaBr2
19.813.410.00.30.117.0ZnBr2 / CaCl2 / CaBr2
6.62.92.40.50.115.1CaCl2 / CaBr2
3.01.61.60.90.313.6CaCl2 / CaBr2
1.90.90.70.20.111.6NaBr0.10.10.10.40.312.4CaCl2
0.10.10.10.70.411.2NaCl / NaBr0.10.10.21.50.510.0NaCl
350°F300°F250°F150°F70°FDensity(lb/gal)
Brine Type
Corrosion Rates for Brines Without Inhibitor(N-80 Steel, 30 Days, mpy)
MethanolMethanol--Brine CompatibilityBrine Compatibility
Compatibilityat 40°F for 24 hrs
Ethylene GlycolEthylene Glycol--Brine CompatibilityBrine Compatibility
Compatibilityat 40°F for 24 hrs
Control Line FluidControl Line Fluid--Brine CompatibilityBrine Compatibility
Oceanic 720R at 190°FOceanic 720R at 190°F
Deepwater OperationsDeepwater Operations
• ExpensiveOperational costs up to $750,000 / day
LogisticsLarge volumes
Long boat trips
Complex rig storage / handling
Pre-planning
Eliminate unplanned activities
Operational IssuesOperational Issues
• Mud-to-Brine Displacements
Floater, Drill ship
Large risers / sub-sea completions
TLP, Spar
Small risers / wet or dry trees
Limited rig storage
Critical Path Evaluation
Time line for logistics» Fluid volumes / tank space / vessel support
Displacement DesignDisplacement Design1 versus 2 Stage Displacement
• Single Stage DisplacementDirect displacement from mud-to-brine in entire wellbore (including riser)
Allows pipe movement in casingMay be important in deviated wellbores
• 2 Stage DisplacementIndirect for Riser
Mud-to-seawaterSeawater-to-brine
Indirect versus Direct for CasingMud-to-seawater-to-brine versus mud-to-brine
No pipe movement in casing• Mechanical Aids in Riser / Casing
Circulating Sub, Jetting Tool & Riser Brush
Displacement DesignDisplacement Design
• Computer SimulationImportant to model hydraulic limitations
Pump pressure limitsLiner top differential pressure limits
Defines maximum flow rates• Lab Testing to Match Spacer Design with
HydraulicsSpacer chemistrySpacer compatibilitySimulate spacer contact time / volumes / flow rates
Packer Fluid SelectionPacker Fluid Selection
• Metallurgical Issues
Brine compatibility
Corrosion of CRA tubulars
• Insulating Packer Fluid
Flow Assurance
Tubing / Casing integrity
Packer Fluid SelectionPacker Fluid Selection
• High-Strength 13Cr Production TubingMost popular metallurgy in deepwaterYield Strength > 95 ksi are prone to SCC
Chloride brines induce CSCC» Low pH, O2 and Temp > ~ 200°F exacerbate» Thiocyanate inhibitors lead to SCC
• Duplex stainless steels (22-28 Cr)Less susceptible to SCC than 13CrThiocyanate inhibitors should be avoided
• Inhibited calcium bromide brines can cause severe localized corrosion of 13Cr as result of CO2 acidification
Chloride Stress Corrosion Chloride Stress Corrosion CrackingCracking
Tubing Failure Due to CaClTubing Failure Due to CaCl22 Packer Fluid @ 339Packer Fluid @ 339°°FF
Stress Corrosion CrackingStress Corrosion Cracking(Non(Non--Zinc Brines With Zinc Brines With ThiocyanateThiocyanate Inhibitor)Inhibitor)
Well 1 2 3 4 5
Metallurgy DSS 25% Cr 22Cr DSS 125 ksi
13Cr 95 ksi actual test indicated 110 ksi
13Cr 110 ksi Hyper
Chrome
13Cr 110 ksi
Hyper Chrome
Brine 11.3 ppg CaCl2
11.0 ppg CaCl2
11.4 ppg CaCl2
12.0 ppg CaBr2/CaCl2
11.6 ppg CaCl2
Additives Thiocyanate inhibitor
Thiocyanate inhibitor
Thiocyanate inhibitor
Thiocyanate inhibitor
Thiocyanate inhibitor
BHT 350°F 370°F 270°F 352°F 284°F
Pressure 14,000 psi 16,800 psi n/a n/a ?
Failure SCC 1 year
SCC 1 month
SCC 3 to 4 days
SCC < 1 week
SCC 7 to 8
months
Failure Depth
Vapor Zone +200°F
Near hanger and deep
into the well
± 8,600’ Estimated 120°F to
180°F
8,450’ to 11,100’ 200°F to
250°F
± 7,500’ estimated
160°F
Comment
O2 incursion
into splash zone – well was vented producing steam out of annulus
Testing drew the
conclusion it was due
to H2S from the inhibitor
Successfully producing today with the same tubing in 11.4 ppg
CaBr2 inhibited
with amine inhibitor
Failed in identification
grooves – successfully producing
with formate packer fluid
Field FailuresField Failures
Stress Corrosion CrackingStress Corrosion Cracking(Non(Non--Zinc Brines With Zinc Brines With ThiocyanateThiocyanate Inhibitor)Inhibitor)
Insulating Packer FluidsInsulating Packer Fluids
• Provide Extended Shut-in Period:Without wax or asphaltene depositionWithout hydrate problemsWithout PCT problems
• Increase Produced Fluid Temperature During Continuous Production
• Decrease Thermal Effects on Tubing / CasingExpansion right after start-upCycles of expansion and contraction during intermittent production
Careful Brine Selection Avoids “Train Wrecks” Careful Brine Selection Avoids “Train Wrecks” and Cost Overrunsand Cost Overruns
• Measure PCT of Brine Formulation with Additives• Confirm Hydrate Equilibrium Curve• Confirm Compatibility of Brine with
Formation Reservoir fluidsOther fluids (frac fluid, acids, control-line fluids)Elastomers
• Measure Corrosion Rates on Coupons (Min. 28 days)CasingTubingProduction Equipment
• Determine the Necessary DosageCorrosion inhibitors / Oxygen Scavengers (packer fluids)Non-emulsifiersScale inhibitors
SummarySummary
• The Preceding Fluid Selection Strategy was Successfully Employed on the Following Chevron Deepwater Projects:
Genesis (2,600’ WD; 12,500 – 17,000’ MD)Typhoon (2,000’ WD; 16,000’ MD)Boris (2,400’ WD; 15,500’ MD)Tahiti (4,000’ WD; 26,500’ MD)
• Utilizing this Strategy on Typhoon Contributed $30 MM Savings and Finished 33 Days Ahead of AFE Target.
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