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.

QuestionsQuestions