Brine School Starfish
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CLEAR BRINE FLUIDS
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CLEAR BRINE FLUIDS
B Tropics to be Covered:
CBF Properties & Testing
Applications
CBF Selection criteria
Fluid Planning & Maintenance
Corrosion
Displacement
Fluid Loss Control
Filtration
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BRINE PROPERTIES & TESTING
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CLEAR BRINE FLUIDS
B Description of Clear Brine Fluids (CBF)
CBF generally fall into two categories
Halides Chloride [Cl-] and Bromide [Br-]
Formates [COOH-]
Water based fluid
Dissolved salt(s) for density No suspended solids
Non-formation damaging
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CLEAR BRINE FLUIDS
NH4Cl
KCl/NaCl
KCl
NaCl
KCl/KBr
KBr
HCOONa
NaCl/CaCl2
CaCl2
KCl/NaBrNaBr
KCl/NaCl/NaBr
NaCl/NaBr
HCOONa/HCOOK
HCOOK
CaBr2
CaCl2/CaBr2
HCOOK/HCOOCs
CaCl2/CaBr2/ZnBr2
Ca/ZnBr2HCOOCs
Ca/ZnBr2
8 10 12 14 16 18 20 22 24
DENSITY, lb /gal
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Halide CBF vs Formate CBF
B Inorganic vs Organic
Halide CBF inorganic ionic salts
Formates Organic salts
M+(H C ) where M+= Na+, K+and Cs+
B History of Formate CBF Introduced in the 90s as an alternative fluid to halide brines
Touted advantages
more environmentally friendly
More compatible with polymers
Greater clay stabilization
More compatible with scaling anions
Offer advantages due to all formates are mono-valent salts, sodium,potassium & cesium
O
O
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Brine Parameters
B Density
B Crystallization TCT & PCT
B pH
B Viscosity
B Turbidity
B pH
B Filterability
B Chemical Composition Primary components
Contaminants
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Density = mass/volume
B Temperature
Increase in temperature causes volume expansion thereby decreasingdensity value
Thermal expansion factors vary according to fluids and density
B
Pressure Increase in pressure causes fluid compression thereby increasing densityvalue
Less impact on density as compared to temperature affects
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Density
B Temperature correction for surface fluids
B Pressure & Temperature Correction for downhole
Increases in pressure, increases density
Well bore conditions, pressure and temperature corrections are madesimultaneously
dc = du + CT - Cp
dc: corrected density, ppgdu: uncorrected density, ppg
CT: average temperature correction, ppgCP: average pressure correction, ppg
B Use TETRAs TP-Pro to do simultaneous temperature and
pressure corrections for wellbore conditions
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Version 2.2
OPERATOR:
WELL NAME:
LOCATION:
DATE:
SURFACE TEMPERATURE: 70 DEG FBHT: 213.8 DEG F
TVD: 5751 FT
BHP: 3855 PSI
OVERBALANCE: 0 PSI
REQUIRED EFFECTIVE DENSITY: 12.89 PPG
SELECTED SURFACE DENSITY: 13.35 PPG
TCT: 60 DEG F
FLUID COMPOSITION ( 1- Salt; 2-Salt; 3-Salt): 2
ACTUAL OVERBAL ANCE: 83 PSI
EFFECTIVE DENSITY AT 5751': 13.17 PPG
VERTICAL ACTUAL TEMP
DEPTH DENSITY DEGREE
FEET PPG PPG PSI FAHRENHEIT
0 13.35 13.35 0 70
221 13.34 13.34 153 76
442 13.32 13.34 307 81
664 13.31 13.33 460 87
885 13.29 13.32 613 92
1106 13.28 13.31 766 981327 13.27 13.31 918 103
1548 13.25 13.30 1071 109
1770 13.24 13.29 1223 114
1991 13.22 13.29 1375 120
2212 13.21 13.28 1527 125
2433 13.20 13.27 1679 131
2654 13.18 13.27 1831 136
2876 13.17 13.26 1983 142
3097 13.15 13.25 2134 147
3318 13.14 13.24 2285 153
3539 13.12 13.24 2436 158
3760 13.11 13.23 2587 164
3981 13.10 13.22 2738 170
4203 13.08 13.22 2888 175
4424 13.07 13.21 3039 181
4645 13.05 13.20 3189 186
4866 13.04 13.20 3339 192
5087 13.03 13.19 3489 197
5309 13.01 13.18 3639 203
5530 13.00 13.17 3788 208
5751 12.98 13.17 3938 214 TVD
NOTE: Results are based on best available information and assume
equilibrium and static well conditions.
EFFECTIVE
DENSITY
PEMEX
Vigilante
Mexico
14-Mar-08
Input Well Data
Calculated corrected density@ down hole conditions
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Crystallization Temperature
B Definition: Temperature at which a consti tuent of the brine
fluid will come out of solution
B Terminology
Surface crystallization
FCTA - First crystal to appear TCT - True crystallization temperature
LCTD - Last crystal to dissolve
Pressurized crystallization
PCT Pressurized crystallization temperature
Notation reference pressure tested and PCT value ie 4/35 has been tested at
4000 psi with a PCT of 35 deg. F
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Schematic of crystallization curve
FCTA
TCT
LCTD
Time
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PCT
B Crystallization temperature shift due to pressure effects
B Depending upon the salt composit ion, pressure wil l either
have no effect or elevated the expected crystallization
temperature
B
PCT are measured with a high pressure apparatus,monitoring temperature, volume & pressure changes.
B PCT is a phenomenon to be consider for offshore
completions at water depths greater than 1500 ft
B PCT fluids are rated for the minimum encountered
temperature and the corresponding maximum pressure Sea bed temperature
BOP testing pressure
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TETRAs PCT Tester
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Viscosity
B Definition: Property of a fluid that resists the force tending to
cause the fluid to f low.
B Viscosity, = [Shear stress, ] in units of centipoise, cp
B Rheological Models
Newtonian Model
Bingham Plastic Model
Power-Law Model
B Application
Calculation of pressure drop under flow
Calculation of equivalent circulating density
[Shear rate, ]
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Viscosity
B All CBF brines are nearly Newtonian in fluid behavior
B Apparent viscosities are sensitive to salt composition
B Within a salt system, as the salt concentration increases, the
viscosity wil l increase coorresponding
B
Measurements are typically made with Fann 35 typeviscometer at either 600 rpm or 300 rpm.
B Payzone fluids are either Bingham or Power law fluids
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Clarity - API 13J, 2nd Ed
B Definition: Relative expression referring to the turbidity of a
brine due to the presence of suspended insoluble or non-
miscible particulate matter.
B Monitored to determine formation damage potential
B QA/QC on fi ltration performance
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Clarity Measurements
B Turbidimeter Nephelometer type
Data - NTUs
Value is influenced by particlesize, size distribution andrefractive index
May be correlated to suspendedsolid concentration by calibrationcurve
B Gravimetric Method Measures total suspended solids
1.2 m filter disks Dry retained solids and filter disk at
105oC for 1 hour
Data is reported as mg of dried solidsper volume of test fluid
B Particle Counters
Measures particle size & concentration
Does not require sample preparation
Data is reported as particle sizedistribution
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pH
B Fluid specification
Neutral to slightly alkaline CBFs
Sodium chloride & sodium bromide
Potassium chloride & potassium bromide
Calcium chloride & Calcium bromide
Highly alkaline CBFs Sodium, Potassium & Cesium formate fluids
Artificially buffered to 10 with carbonate solution
Acidic CBFs
Zinc CBF
Ammonium chloride
B Monitoring of acid/base contamination
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Filterability
B Objective
Evaluate the ability of filtration to bring used fluid back to specification
Determine possible polymer or other contamination
B Test Method
Filter CBF through a 0.45 micron absolute filter paper using an inline filter
holder and syringe Passing: Greater than 50 ml of filtrate thru one filter paper
Failure: List actual filtrate volume thru one filter paper
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TETRAs QA/QC
B Brine Analysis Program Part of TETRAs CBF management program
QA blending at the plant facility
QC of return fluids from rig
Measures salt composition
Physical properties Density
Crystallization
Turbidity
Filterability
Contaminates
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APPLICATIONS
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B Completion/Workover Fluid
Gravel pack fluid
Stimulation fluid
Frac fluid
B Packer Fluid
B PayZone Drilling Fluids
Applications
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Completion and Workover Fluid
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Completion & Workover Fluids
B Desired Properties Density - well control
Non-formation damaging
Solids Free
Compatible with formation water
Compatible with clays/shale
Non-Corrosive
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Completion & Workover Fluid
B Density 8.5 ppg to 21.0 ppg
Maximum equivalent pressure gradient of 1.1 psi/ft
Density increase with spike fluid or anhydrous salts
Density decrease with low density fluid or water
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Completion & Workover Fluid
B Solids Free Fluid Low pumping pressures
No solids to obstruct wellbore operations
Avoid density stratification
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Completion & Workover Fluid
B Formation Damage - Overview
Permeability - fluid flow
Porosity - pore volume
Production
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Completion & Workover Fluid
B Formation Damage - Partic le Invasion
No suspended solids in brine fluids
Brine filtration is extremely important
Diatomaceous earth filtration
Cartridge filtration
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Completion & Workover Fluid
B Formation Damage thru c lay hydration and dispersion Damage mechanism
Hydrated clays/shale decrease porosity
Dispersed clays/shale may potentially reduce permeability
High salinity fluids inhibit clay swelling and migration
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Water sensitive clays
INSITU CLAYS
HYDRATED CLAYS
DISPERSED HYDRATED CLAYS
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Completion & Workover Fluid
B Formation Damage - Water Compatibil ity
Insitu precipitation reduces permeability & porosity Seawater
s Sulfates
s Bacteria
Formation water compatibility
s Cation scaling/precipitation
Sodium
Calcium, Barium, Strontium
Heavy metals - iron
s Anion scaling/precipitation
Bicarbonate/carbonate
Sulfates
Sulfides
Halides & Formates are extremely soluble
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Packer Fluid
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Packer Fluid
B Maintain complete or partial hydrostatic pressure
requirement of the well
B Long term application
B Closed system
B Desired Properties No solids, non-damaging, inhibitive, no physical obstruction
Temperature stability
Low corrosion
Remain pumpable
Compatibility with elastomers
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Packer Fluid
B Advantages Wide range of densities
Non-formation damaging
Solids free
Fluid stability
Low corrosion rate
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Packer Fluid
B Solids Free Fluid Unlike muds, no solids to settle over time
No solids to hinder or prevent removal of packers
Fluid can be used as non-damaging workover or kill fluid
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PACKER FLUID
0
200
400
600
800
1000
1200
0 100 200 300 400 500 600 700 800 900 1000 1100 1200
TOTAL SUSPENDED SOLIDS, mg /l
HEIGHTO
FSETTLEDSOLIDS
,cm
15,000 FT (4572 M) 9 5/8 IN CASING5,000 FT (1,524 M) 7 5/8 IN CASING
2 7/8 IN TUBING
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Packer Fluid
B Fluid Stability Thermally stable - >400oF for halides,
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CBF SELECTION CRITERIA
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Fluid Selection
Correct Density
[Temperature & Pressure]
PCT Check
[Pressure & Crystallization point]
Fluid Evaluation
Formation Damage
Fluid Economics Environmental & Safety
Corrosion Resistant Alloy Compatibility
Final Working Fluid Specification
Completion Fluid's Density
& Crystallization point
Well Design
& Hydraulics
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Well Design & Hydraulic
B Provide hydrostatic pressureBHP = grads , psi/ft x TVD, ftDensity, ppg = grad, psi/ft x 0.052
B Desired CBF density may be based upon the overburden pressure,underburden pressure or ECD
Overburden pressure =BHP +Overbalance pressure Underburden pressure =BHP Underbalance pressure
ECD takes into consideration of pressure drops under dynamic conditions Pressure consideration due to weak liner top, cement etc. Open hole consider pore & fracture presure
B Final density must be calculated to compensate for temperatureand pressure using TP-Pro
Onshore calculation Offshore calculation allows for temperature modeling to seabed temperature and from seabed
temperature to bottom hole temperature
C lli i P i
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Crystallization Point
B Definition: Temperature at which a consti tuent of the brine
fluid will come out of solution
B Selected according to the lowest temperature to be
encounter
Ambient temperature
Sea bed temperature
B The specified TCT of the CBF should approximately 5 deg. F
lower than the minimum working temperature
PCT
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PCT
B Factors to consider for PCT fluids
Consider PCT effects when well is in 1500 ft of water or greater Sea bed temperature
Hydrostatic pressure at sea bed
Any overburden pressure at sea bed depth such as BOP testing
Maximum calculated pressure is hydrostatic pressure (corrected) plusoverburden pressure
B As with TCT, PCT ratings should have a safety factor
The PCT temperature rating should be 5 deg. F lower than the minimumtemperature at the given maximum pressure
Example a well with a sea bed temperature of 35 deg. F and maximumpressure at sea bed depth of 10,000 psi should have a fluid with rating of
10/30
Fi l Fl id S ifi ti
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Final Fluid Specification
B Once density and TCT/PCT are determined, types of possible
salt systems can be defined
CLEAR BRINE FLUIDS
NH4Cl
KCl/NaCl
KCl
NaCl
KCl/KBr
KBr
HCOONa
NaCl/CaCl2
CaCl2
KCl/NaBr
NaBr
KCl/NaCl/NaBr
NaCl/NaBr
HCOONa/HCOOKHCOOK
CaBr2
CaCl2/CaBr2
HCOOK/HCOOCs
CaCl2/CaBr2/ZnBr2
Ca/ZnBr2
HCOOCs
Ca/ZnBr2
1.00 1.20 1.40 1.60 1.80 2.00 2.20 2.40 2.60
SPECIFIC GRAVITY
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Mechanisms of Formation Damage
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Mechanisms of Formation Damage
B Change of Wettabili tyB Particle Invasion
B Clay Hydration
B Formation Water Compatibili ty
B Crude Compatibility
B Other Fluids
FORMATION WATER
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FORMATION WATER
B Anions Sulfates
Carbonates
B Cations
Barium
Heavy metals
Sodium
B pH Destabilization of Clays
Precipitation
Formation Water Compatibil ity
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p y
0
200
400
600
800
1000
1200
1400
1600
25/75 50/50 75/25
Completion Brine/Formation Water Ratio
Turb
idity,
ntu
11.5 ppg NaCl/NaBr
12.5 ppg NaBr
11.0 ppg CaCl2
12.0 ppg CaCl2/CaBr2Formation Water:SG =1.109Na =53551 ppmFe =3 ppmBa =ND
Ca =7060 ppmMg =571 ppmCl =93174 ppmCO3
-2 =926 ppmSO4
-2 =3375 ppmpH =10.8
Formation Water Compatibili ty
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Formation Water Compatibili ty
0
2
46
8
10
1214
16
25/75 50/50 75/25Completion Brine/Formation Water
Sol
ids,
vo
l.%
12.5 ppg CaCl2/CaBr2
12.5 ppg CaBr2
14.0 ppg CaBr2
Formation Water:SG =1.14NaCl =18.6 wt.%
CBF Selection
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CBF Selection
B
Environmental Governmental regulations
Zinc CBF zero discharge
Reportable quantities GOM
s Zinc Bromide 1000 lbs
s Ammonium chloride 5000 lbs
Toxicity values
Disposal considerations
Toxicity
Salinity
Halides
Safety & Personnel handling
Zinc CBF
CBF Selection
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CBF SelectionFluid Economics
B Each salt has different COG
B Fluids are blended as mixed salts to lower cost
B Generally chlorides are less expensive than bromides
B Should be last cri teria
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Fluid Planning & Maintenance
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Working Fluid
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(2 to 3 times circulating volume)B Calculating working flu id volume requirements
Circulating volume
Volume of wellbore with drill pipe in place
Holding tanks
Minimum of one hole volume
Filtration equipment
Fluid hold in the equipment
Filtration rate of equipment versus fluid circulation rate
Surface piping
Fluid volume held in the system
Re-supply turnaround time
Contingency needs and pill requirements
Fluid loss thru displacement interface, downhole & surface
Make up of fluid loss pills
Working Fluid Maintenance
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Working Fluid Maintenance
B Fluids can lose density from water or other low density fluidingression
B Density increase required to maintain well control or wellbore
B Use of spike fluid or material for working fluid density
maintenance
Fluid with a significantly higher density than the working fluid Dry salts
Density Loss due to Fluid Ingression
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Density Loss due to Fluid Ingression
B All clear brine fluids are hygroscopic absorb water fromatmosphere at points of exposure
Rigs utilizing clear brine fluids require closed tanks to minimize this problem
B Surface fluid handling system are not completely water tight
and water run off can contaminate brine fluid.
B Contamination of brine fluid from water lines Standard operating procedure is to lock off all water lines prior to bringing
CBF onto rig.
B Contamination of brine fluid from ingression of reservoir
fluids
Oil
Formation water
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Spike Fluid/MaterialFactors
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Factors
B Determine during well pre-planning
B Based upon most l ikely density range increase of workingfluid for well control
B Weigh up option must keep TCT or PCT at or below wells
specification
B Consider rig l imitations
Tank capacity The lesser the density differential, the greater volume consumption of spike fluid
impacting volume of spike fluid
Mixing capabilities (dry materials)
B Time
Time require to maintain the working fluid
Turnaround time for bringing new fluid onsite
B Economics
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CORROSION
Definition of Corrosion
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B Destruction or deterioration of a material by reaction with its
environment.
Metals
Non-metallic materials such as plastics, ceramics
B These reactions may be chemical and/or physical.B Corroded metal reverts back to most stable form - oxides
Corrosion Problems
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B Metal Loss
B Formation of Solids which contr ibute to formation damage
B Contamination of Clear Brine Fluid
B Possible Catastrophic Failure of Tubing and Equipment
Types of Corrosion
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yp
B Uniform Corrosion Metal loss distributed over entire
exposed surface area
Most common form
Caused by chemical reactions
Long term corrosion effects can beaccurately predicted
B Localized Corrosion Crevice
Pitting
Stress
Intergranular
Can lead to premature failure of tubingor equipment
B Environmental Assisted Cracking
Form of Stress corrsion
Requires an applied stress andelectrochemical reaction
Primary considerations are on CRA
Effective corrosion control requires a
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multiple approach method
B Brine compositionB Aeration
B Contaminates
B Corrosion inhibitors
B Oxygen scavenger
B Biocides
B Corrosion resistant alloy
Uniform Corrosion Data
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s CaCl2/CaBr2/ZnBr2 Brine
Test conditions: 177oC, N-80
steel, 7 days
s Inhibited Systems
1.86 sg brine: 121oC, N-80 steel, 5
days
2.04 sg brine: 149oC, N-80 steel, 7days
0
20
40
60
80
100
120
140
160
1.76 1.86 1.96 2.06 2.16 2.26
DENSITY, sg
CORROSIONR
ATE,mpy
Composition A
Composition B
Composition C
0
5
10
15
20
25
30
35
40
45
1.86 2.04
DENSITY, sg
CORROSIONR
ATE,mpy
Control
Tetrahib Plus
MatchWell
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B Empir ical Corrosion Database developed by TETRA on CBFs
and additives to predict EAC on various metallurgiesB MatchWell is a fluid selector program that recommends an
optimum fluid system to avoid EAC for the given well
metallurgy & parameters
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DISPLACEMENT
Displacement And CleanupD fi iti
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Definition
Substitute one fluid for another in the wellbore
while removing all residue of the original fluid.
Displacement And Cleanup Goals
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B Maintain well control
B Avoid Health Safety & Environmental concerns
B Maintain wellbore integrity
B Provide a solids free environment for completion
B Minimize operational costs Minimize operational time
Minimize fluid losses due to contamination
Displacement And CleanupDesign Considerations
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Design Considerations
B Original fluid type and density
B Displacing fluid type and density
B Wellbore geometry
B Wellbore integrity
B Equipment limitations
Displacement And CleanupMethods
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Methods
B Direct Displacement
All three operations are performed by one or more chemical spacers in onecirculation
B Indirect displacement
An intermediary fluid (usually seawater) is introduced to aid in theperformance of the removal of the original fluid and residue.
Displacement And CleanupMethod Advantages/Disadvantages
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Method Advantages/Disadvantages
B Direct Displacement
Advantages Disadvantages
Minimizes pumping time Spacers are typically more expensive
Provides better down hole pressure
control
May generate high downhole
pressures
Protects integri ty of or iginal fluid Places higher importance on pump
capabilities
Minimizes volume of waste fluid
generated
Fluid compatibilities may be more
critical
Mud mobility is cruc ial
Displacement And CleanupMethod Advantages/Disadvantages
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Method Advantages/Disadvantages
B Indirect Displacement
Advantages Disadvantages
Spacer cost minimized Downhole hydrostatic pressures
are reduced
Insures clean hole, beforeintroducing completion fluid
Creates larger amounts of wastefluid
Allows greater tolerance of
mechanical difficulties
Requires more pumping time
Mud mobility requirements are
less crucial
May need to discharge first step
cleaning flu id (seawater)
Displacement And CleanupMethod Selection
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Method Selection
B Indirect Displacement
Preferred method, unless prohibited by circumstances
B Direct displacement Utilized when circumstance prohibit an indirect displacement
Indirect DisplacementPump Schedule
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Pump Schedule
Stage Volume Rate
Seawater Minimum One hole volume Maximum
Caustic Soda 50 barrels Maximum
Seawater 50 barrels Maximum
Surfactant 50 barrels Maximum
Seawater 50 barrels Maximum
Caustic soda 50 barrels Maximum
Seawater One hole volume Maximum
Short Trip Casing Scrapers and Brushes
Rig up to reverse circulate
Seawater One hole volume Maximum
High Vis. Sweep 50 barrels Maximum
Filtered Completion
Fluid
Until returns are clean Maximum
Displacement Systems
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B
TDSP System Balanced displacement
Minimum size, multiple pills
Low pump rates
Generally used in direct displacement
B TETRACLEAN System
Large single pill
Balanced displacement
High pump rates
Utilized in direct and indirect displacement
Direct DisplacementSpacer Design - TDSP System
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Spacer Design TDSP System
B Base Fluid
B TDSP I
B TDSP II
B TDSP III
Direct DisplacementTDSP Spacer Design
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TDSP Spacer Design
B Base Fluid
Base fluid of the mud system being displaced, with no additives.
Included when compatibility is a concern
Acts as a turbulent sweep, helping to clean mud cake from casing interior
Protects integrity of fluid being displaced
Commonly used in SBM and OBM displacement
Volume designed to provide adequate separation of original fluid and TDSP I
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Direct DisplacementTDSP Spacer Design
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S Space es g
B TDSP III
Viscosified intermediate density fluid, usually 11.6 ppg
HEC polymer
HEC/XC polymer
XC polymer
Rheology designed to provide maximum suspension and lifting capabilities Volume designed to provide adequate separation between TDSP II and the
completion fluid
Recommended minimum coverage of 1,000 feet in largest annular space
Recommended minimum contact time is 5 minute.
TETRACLEAN SYSTEM
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B Single multi-function fluid
SOBM
OBM
WBM
B Minimal use of space/tanks/pits
B System can be pre-blended or made on-site
B
Versatile Unbalanced displacement
Balanced displacement
B High Rate displacement
B Environmental Compliance
TETRACLEAN SYSTEMComponents
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Components
B
Blend of Polymers Spacer
Suspend/carrier of solids
B TETRACLEAN 105 & TETRACLEAN 106
Surfactants & Cleaning agents
Remove any remaining solids on casing
Disperse solids
Water wet metal surfaces
B Base Fluid
Water/seawater
Brines
TETRACLEAN SYSTEM
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B SOBM/OBM
Preceded by a base oil pill
Formulation of surfactant/cleaning agents according to mud type
brine
B WBM
Clean up and displacement with TETRACLEAN pill
B Unbalance Displacement
Preceded by Hi-vis push pill & seawater
Clean up with TETRACLEAN pill
B High Flow Rate
Circulating sub in wells utilizing liners
Kill/Choke lines to boost rates in riser
Displacement And Cleanup Products
B Caustic Soda sodium hydroxide
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Cleans by saponification of oils to soap
B TETRA OMD Surfactant and dispersant for water based and diesel based muds
B TETRA O-Sol Blend of surfactants designed for diesel and synthetic based oil muds
B TETRASol Blend of surfactants and solvents to remove hydrocarbons, oil based muds,
pipe dope, asphaltenes and resinsB TETRAClean 103
Flocculate mud, pipe dope, oil, polymers and other solids.
B TETRAClean 105 Surfactant component of TETRAClean system
B TETRAClean 106 Cleaning booster for TETRAClean 105 used in non-calcium displacement
pills
Direct DisplacementPump Schedule
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Stage Stage Volume Cumulative Volume Rate Returning Fluid
TDSP I 25 25 2.5 Mud
TDSP II 50 75 2.5 Mud
TDSP III 25 100 2.5 Mud
Completion Fluid 185 285 4.25 Mud
Completion Fluid 250 535 5.5 Mud
Completion Fluid 25 560 5.5 TDSP I
Completion Fluid 50 610 5.5 TDSP II
Completion Fluid 25 635 5.5 TDSP III
Completion Fluid 435 1070 5.5 Completion Fluid
Short Trip Casing Scrapers
Completion Fluid Until Clean Max. Rate Completion Fluid
DeepDesignDisplacement Modeling Software
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DeepDesign
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B Database management of input data
B Hydraulic calculation on the exact configuration of the well Subsea completion
Pipe joints
Eccentricity
Tool configuration
B Fluids Density and rheology corrected as a function of temperature & pressure
Track fluid properties as a function of circulating or static mode.
Displacement Summary
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Variables Flow
rate
(bpm)
Pump
P (psi )
Pump
HP (HP)
P @ TD
(psi)
ECD
@ TD
(ppg)
ECD @
TOL
(ppg)Maxi.
value
8.00 7689 1507. 17873 17.85 18.57
Mini. value 3.57 0 0. 15631 15.61 8.62
Maxi. @
time (min)
0.0 40.9 40.9 48.5 48.5 181.2
Mini. @
time (min)
218.4 120.0 120.0 61.2 61.2 205.2
PRESSURE @TD
DeepDesign Output
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7800
8000
8200
8400
8600
8800
9000
9200
9400
0 500 1000 1500 2000 2500
PRESSURE@TD,PSI
CUMULATIVE VOLUME, BBL
PRESSURE @TD
DeepDesign Output
PUMP PRESSURE
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0
500
1000
1500
2000
2500
3000
0 20 40 60 80 100 120 140 160 180
PUMPP
RESSURE,PSI
ELAPSED TIME, MIN.
PUMP PRESSURE
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DOWNHOLE FLUID LOSS CONTROL
Fluid Loss Control
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B Pre-plan FLC options
First option FLC pill
Contingency option pill
Reduction of fluid density
B Fluid loss rates
Seepage less than 10 bbl/hr
Moderate fluid loss
High fluid loss
Lost circulation rate of lost fluid is greater than pump fluid rate
Selection Criteria
FLUID LOSS PILLS
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Fluid Loss P il l Requi rements Operational Requi rements
Polymer Pill
Polymer Crosslinked Pill
Solids Free Pills
Sized Salt Pill
Sized Carbonate Pill
PayZone MagmaFiber
Solids Laden Pills
Discharge
Clean Up
Environmental & Safety
Monovalent halide CBF
Divalent Halide CBF
Formate CBF
Base Brine System
Final Working FLC Specification
Reservoir Data
FLUID LOSS PILLS
Fluid Loss PillSelection Criteria
B Reservoir dataP bilit f i
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Permeability of reservoir Determines the applicability of polymer pills
Sizing of bridge solids Porosity
Determines the depth of pill invasion
Dictate size of pill & clean up
Bottom hole temperature Determines the applicability of polymer pills
Determines the additive package
Determines the pill component
Formation water Compatibility with base brine & clean up chemicals
Lithology of reservoir Compatibility with base brine & Clean up chemicals
Pore pressure ECD consideration
Fracture pressure ECD consideration
Fluid Loss PillSelection Criteria
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B Fluid loss pil l properties Desired final density
May opt to decrease density to lower hydrostatic column
Base brine fluid
B Operational Requirements Time interval for performance of FLC pill
Well design Aperture restriction in tools
Pumping limitation
Rig equipment limitation
Mode of Clean up if required Acids
Enzymes
Oxidizers flowback
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Final FLC Specification
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B Density
B Length of time for FLC performance @ temperature
B Clean up option
Types of FLCSolids-Free Pil ls
B Polymer FLC
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B Polymer FLC Density range: 8.5 19.2 ppg
Mechanism: Bulk viscosity with HEC polymer
Banking & Gel Strength with XC polymer
Advantage Low residual
Least formation damaging
Degrades naturally over time with sufficient temperature Disadvantages Limited to reservoirs with permeability less than 1 darcy
Temperature limitations HEC approximately 200 deg. F
s XC 220 240 deg. F
Greater invasion into formation
Types of FLCSolids-Free Pil ls
B TETRA Flex pill
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B TETRA Flex pill
Pre-crosslinked polymer gel in CBF
Solids-free FLC
Density range: 8.5 ppg to 14.0 ppg
Mechanism
Crosslinked gel function as a bridging material
Advantages
Low residual, less formation damaging than solids laden FLC Easily degraded by acid
Can be extended to higher density fluid with a viscosified carrier brine
Disadvantages
Limited to reservoir formation of less than 2.5 darcy
Temperature limitation of 240 deg. F
Types of FLCSolids-Laden Pills
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B Characteristics of Solids-laden pil ls
Contains bridging solids
Contains a polymer with solids suspension property
May contain starch component for additional filtrate control
All degradable under appropriate conditions and treatment
Types of FLCSolids-Laden Pills
B Sized Salt pil ls
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Bridge solids suspended in polymer
Ideal density range: 10.5 to 13.0 ppg
Mechanism:
Forms an impermeable filter cake with NaCl
Advantages
Very effective in controlling fluid loss
Capable of spanning a wide range of reservoir permeability
Bridge solids are water soluble
Disadvantages
Size salt may dissolve prematurely
May be damaging to formation
Temperature limitation is function of polymers used
Optimal applications is limited to sodium halide CBF
Usage in non-sodium CBF can lead to unpredictable bridge solids sizing &dissolution
Types of FLCSolids Laden Pill
B Sized Carbonate Pill
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Bridge solids suspended in polymer
Density range: 8.7 ppg to 19.2 ppg
Mechanism:
Forms an impermeable filter cake
Advantages
Very effective in controlling fluid loss
Capable of spanning a wide range of reservoir permeability
Bridge solids are highly acid soluble
Wider range of density pill available than sized salt pills
Disadvantages
Acidization is required for removal of bridge solids
May be damaging to formation
Temperature limitation is a function of polymers used in pill
Types of FLCSolids Laden Pills
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B Fiber Bridging Solid
PayZone MagmaFiber fiber-like bridge solids in viscosified base brine
Density range: 8.6 ppg to 19.2 ppg
Mechanism: Forms an impermeable matted filter cake
Advantages:
Very effective in controlling fluid loss
Effective in controlling losses in fracture face and vugular formations due to thefiber like bridge solids
PayZone MagmaFiber are acid soluble
Wide range of density available, similar to sized carbonate pills
Disadvantages:
Acidization is required to remove bridge solids
Residuals of FLC may contribute to formation damage
Temperature limitation is a function of polymers used in pill
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Polymer Products
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B TETRA Vis HEC polymer
B TETRA Vis L low concentration liquid HEC product
B TETRA Vis L Plus High concentration liquid HEC product
B BioPol - Biopolymer
B BioPol-L (liquid) Biopolymer
B BioPol HT High temperature biopolymerB PseudoPol (liquid) Synthetic polymer
B PseudoPol D Synthetic polymer
B PseudoPol HT High temperature synthetic polymer
B Payzone HPS Starch for fi ltrate control
Thermal Extender
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B Formate CBFs
B TETRA Buff-10
pH stabilizer
B PayZone 750
Anti-oxidant
Prevents oxidation of polymer
Bridge Solids
B Sized Sodium Chloride, 25 to 50 ppb TETRA SS-Fine, particle size ranging from1.0 800 mand D50 of 48 m
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TETRA SS Fine, particle size ranging from 1.0 800 m and D50 of 48 m
TETRA SS-Medium, particle size ranging from 100 1500 m and D50
of 500 m
TETRA SS-Coarse, particle size ranging from 1000 10,000 m
B Sized Calcium Carbonate, 25 to 50 ppb PayZone Carb-Prime, particle size ranging from 2.0 150 m and D50 of 12 m
PayZone Carb-Ultra, particle size ranging from 1.5 20 m and D50 of 4 m
TETRACarb Fine, particle size ranging from 10 500 m and D50 of 55 m
TETRACarb Medium, particle size ranging from 85 1200 m and D50 of 370 m TETRACarb Coarse, particle size ranging from 1000 3500 m and D50 of 1800 m
TETRACarb Flake, flat sheet like shaped solid
B PayZone 530 & 532, 8 to 30 ppb PayZone 530 Regular grade
PayZone 532 Fine grade
Well PlanningFLC
S f C
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B Size of FLC pill
Typically 1.5 to 2.0 times the wellbore section that requires sealing off
Solids-Free Pills will require a larger volume than typical due to volumelosses from invasion into formation
Sized Salt pills will require a larger volume than typical to limit losses of sizedbridge solids
B
Develop guidelines for application of FLC and contingencyFLC pil l
Rate of fluid losses to the application of FLC pills
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FILTRATION
Filtration Applications
Filt ti f CBF
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B Filtration of CBFs
Removal of suspended solids in brines
Removal of fisheye in viscosified pills
B Oil Removal
CBF
Produced water
FiltrationClear Brine Fluids
B t il bl t h l f t ti th d ti i t f
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B Best available technology for protecting the productivi ty of
reservoir Meet hydraulic requirements of well
Meet working environments of well
Least formation damaging fluid to the formation
B In order to maintain the integrity of CBF, fluid fi ltration isessential
B Fluid fil tration is part of CBFs daily maintenance
QA/QC Filtration PerformanceMethods
B Turbidity Generally used by most operators Nephelometric method light deflected at 90 deg.
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Indirect measurement of solids in fluid
Standards utilized by operators can range from 10 NTU to higherB Gravimetric measurements used by operators requiring tighter
solids control Absolute weight of solids retained by pre-determined size filter Standards utilized by operators can range from 10 mg/l to higher
B Particle Counts Most stringent method ut ilized by operators wi thhighly sensitive formation
Typically utilize laser particle counters Monitor particle size and concentration Standards utilized by operators can range from specified maximum particle size,
minimum particle count reduction and maximum particle concentrations
B All the above methods has been implemented successfully byTETRA
Formation DamageCompletion Fluid Contamination
B Problems Created by Solids in Completion Brine
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B Problems Created by Solids in Completion Brine
Skin Damage by particle invasion to reservoir Pore throat blocking thereby reducing permeability
Reduction of overall porosity
Contributes to overall loss of net production
Operational problems Plugging of perforations
Plugging of slots in liner
Plugging of gravel pack
Obstruction downhole that may lead to inoperable tools
Settlement of solids on packer that could lead problems in removal of packer inworkovers.
Loss in value of completion brine Brine cannot be used as packer fluid
Brine cannot be used in another well
Formation Damage
Particle invasion
0.8
1
/Ki)
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0
0.2
0.4
0.6
0 25 50 75 100 125 150 175 200
Cummulative Throughput, PV
Permea
bility
Change
(k2.5 md
7.3 md
39.1 md
Completion brine contaminated with 100 mg/l hydrated API bentonite through well core samples
Graph illustrates the magnitude in reduction of permeability due to loss of completion brinecontaminated with 100 mg/l of solids. The core sample with an initial permeability of 39 md lostmore than 80% of its original permeability after a flow of 26 pore volume into the core. The pore
volume is fairly low since it is the equivalent measured pore space in the core sample.
PACKER FLUID
1000
1200
DS
,cm
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0
200
400
600
800
0 100 200 300 400 500 600 700 800 900 1000 1100 1200
TOTAL SUSPENDED SOLIDS, mg/l
HEIGHTOFSETTLEDSO
LID
15,000 FT (4572 M) 9 5/8 IN CASING
5,000 FT (1,524 M) 7 5/8 IN CASING
2 7/8 IN TUBING
This graph illustrates the amount of settled solids that will occur when packer fluids are not filtered.
The height of settled solids is a function of the level of solid contamination in the brine. Settled solidson a packer can prevent its removal at a future date without a milling operation.
DE Brine FiltrationStandard of the Industry
B TETRA - DE Plate & Frame Filtration
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B TETRA DE Plate & Frame Filtration
Sizes: 600 ft2, 1100 ft2, 1300 ft2 and 1500 ft2 Capacity to filter brines with densities ranging from 8.5 ppg to 19.2 ppg
Filter media diatomaceous earth
Cake filtration
Flow rates: 5 to 20 bpm, dependent upon size of filtration unit & brine density
Cartridge Pod units
Placed immediately downstream of SafeDEflo DE unit
Primary function is a guard unit to prevent solids bypass in the DE unit Dual pod with 64 cartridge capacity
TETRA C2 Pleated Cellulose Filtration Cartridges
TETRA PP2 Polypropylene Filtration Cartridges
Resin Bonded Filtration Cartridges
Cartridge Filtration
B Utilized as guard fi ltration in DE fil tration Insures fluid clarity in the event of tears in the filter cloth
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DE filter aid grade should be match with cartridge rating such that solids areremoved by DE
B Utilized to f ilter viscosi fied pill Solids-free fluid loss pill
XC polymer
HEC polymer
Remove fisheyes Fisheyes are partially or un-hydrated polymer
Fisheyes are a source of formation damage
B Oily water reclamation Special cartridges made of material to absorb oil
Design to meet Oil & Grease discharge regulations