Brine School Starfish

7/27/2019 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


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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B Solids Free Fluid Low pumping pressures

No solids to obstruct wellbore operations

Avoid density stratification


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B Formation Damage - Overview

Permeability - fluid flow

Porosity - pore volume

Production


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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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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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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


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


Mechanism:

Forms an impermeable filter cake

Advantages


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


Mechanism: Forms an impermeable matted filter cake

Advantages:


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

Documents

Brine School Starfish