Idp Feb 2015_revised

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Fundamental of Cementing Services

1

© 2014 BAKER HUGHES I NCORPORATED. ALL RI GHTS RESERVED. TERM S AND CONDI TI ONS OF USE: BY ACCEPTI NG THI S DOCUM ENT, THE RECI PI ENT AGREES THAT THE DOCUM ENT TOGETHER W I TH ALL I NFORM ATI ON I NCLUDED THEREI N I S THE CONFI DENTI AL AND PROPRI ETARY PROPERTY OF BAKER HUGHES I NCORPORATED AND I NCLUDES VALUABLE TRADE SECRETS AND/ OR PROPRI ETARY I NF OR M ATI ON OF BAKER HUGHES (COLLECTI VELY "I NFORM ATI ON"). BAKER HUGHES RETAI NS ALL RI GHTS UNDER COPYRI GHT LAW S AND TRADE SECRET LAW S OF THE UNI TED STATES OF AM ERI CA AND OTHER COUNTRI ES. THE RECI PI ENT FURTHER AGREES TH AT THE DOCUM ENT M AY NOT BE DI STRI BUTED, TRANSM I TTED, COPI ED OR REPRODUCED I N W HOLE OR I N PART BY ANY M EANS, ELECTRONI C, M ECHANI CAL, OR OTHERW I SE, W I THOUT THE EXPRESS PRI OR W RI TTEN CONSENT OF BAKER HUGHES, AND M A Y NOT BE USED DI RECTLY OR I NDI RECTLY I N ANY W AY DETRI M ENTAL TO BAKER HUGHES’ I NTEREST.

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

2

Outline

Job Execution

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What is Cementing ???

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What is Cementing ???

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￭ Oil well cementing is a process of mixing a slurry of cement and water and pumping it through the casing pipe into the annulus between the casing pipe and the drilled hole.

4

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

5

Outline

Job Execution

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Classifications of Cementing

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Primary

Secondary

Plug Method

Plug Back Cementing

Inner String Method

Squeeze Cementing

Stage Cementing

Objectives of Primary Cementing •

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•

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Main objectives of primary cementing are :

to support the casing pipe



to restrict the movement of formation fluids behind the casing

Cement also provides the following advantages :-



seal off zones of lost circulation (fractured formation)



protect the casing from shock loads during drilling deeper section



protect casing from corrosion

Secondary Cementing Supplementing faulty primary cement job

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Shut off old perfs for recompletion

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Purpose

Stop loss circulation during drilling

Repair casing defects

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

9

Outline

Job Execution

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API Classification of Cements

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

API provides specs covering eight classes of oil well cement designated as class A, B, C, D, E, F, G and H



The most common cement used in Malaysia??

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API Class G Cement

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API Class G Cement

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

Considered as basic cement; Can be modified by adding accelerator or retarder to suit wide range of depth and temperature (etc: deep wells, HPHT, lost circulation zones)



Intended for use from surface up to 8000 ft depth



The recommended water to cement ratio according to API for class G cement is 44% (5 gal/sack or 18.9 ltr/sack)

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

13

Outline

Job Execution

Cement Additives Accelerator

• Shorten thickening time

Retarder

• Lengthen thickening time

Dispersant

• To ease mixability at surface

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Fluid Loss Additive • Control amount of fluid loss to formation

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Defoamer

• Prevent foam production

Gas Block

• Prevent gas migration

Weighting Agent

• Increase slurry density

Light Weight Agent • Reduce slurry density (maintain strength) LCM

• Seal off lost circulation zone

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Accelerator CEMENT ADDITIVES

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•

The accelerator is used to reduce the thickening time and set the cement faster by accelerating the hydration of chemical compound of cement.

•

Common Accelerators used are Sodium Chloride, Calcium Cholride and Calcium Sulphate (gypsum)

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Retarder CEMENT ADDITIVES

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•

The retarder will increase the thickening time or prolong the time of cement to set.

•

It is necessary since more time is needed to place cement in deeper wells or to combat the thickening time reduction in high temperature environment

•

Common retarder are saturated NaCl, lignosulfonate and its derivatives, cellulose derivative and sugar derivatives

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Dispersant

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•

Primary effect  to reduce viscosity. As a result, higher pumping rates are possible.

•

Secondary effect  lengthens thickening time requirement

•

Common dispersants are synthetic sulfonate polymers, lignins

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Fluid Loss CEMENT ADDITIVES

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•

Fluid loss additives are used to control amount of liquid loss from cement slurries to the surrounding environment.

•

Common fluid loss additives are organic polymers, dispersants and synthetic polymers

Defoamer CEMENT ADDITIVES

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• Foam will formed during mixing the cement slurry with the chemicals detrimental to good cement jobs

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Gas Block • Hydration in place the hydrostatic reduce

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• Gas block chemicals- to fill up the pores between the cement particles

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Weighting DITIVES Agents

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•

Weighting materials are used to increase the density of cement slurry depending on the requirement

•

The weight of cement slurries can be increased by adding barite or hematite

Light Weight Additives

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The weight of cement slurry can be reduced by :-

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•

Adding material that increases the water content such as clay and silicate materials

•

Using light weight materials such as microspheres or nitrogen

•

Light weight cement is used on weak formation or loss circulation zones

Lost Circulation Materials CEMENT ADDITIVES •

The lost circulation materials are used to combat cement lost into very permeable, cavernous or fractured formations

•

The lost circulation materials prevent the loss of cement by one or more of the following mechanisms

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•

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

Preventing fracture inducement by reducing hydrostatic pressure as in lightweight cement



Cure the lost circulation by forming a low permeability bridge across the permeable opening

Common LCM can be classified as fibrous, granular and flakes

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

24

Outline

Job Execution

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

Cement CEMENT Slurry SLURRYDesign DESIGN

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Consideration

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CEMENT/SPACER DENSITY

Prevent losses to formation Prevent flow from permeable formations Strength development

Slurry stability

Density Density  15.8ppg typically used for neat class G  based on API recommend water ratio of 44% RULE OF THUMB : 𝝆𝒎𝒖𝒅

< 𝝆𝒔𝒑𝒂𝒄𝒆𝒓 < 𝝆𝒄𝒆𝒎𝒆𝒏𝒕

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 Density of slurry normally 1 ppg higher than mud weight

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

Rheology  Determined using rotational viscometer •

Concentric bob and rotor to shear cement slurry in small gap

•

Shear rate versus shear stress relationship is determined

 Cement is non-Newtonian fluid •

Its flow regime is determined using  Bingham Plastic model  Power Law model

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 Other models

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CEMENT RheologySLURRY DESIGN

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 Influenced by:

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•

Cement density (water contents)

•

Dispersant

•

Retarder

•

Fluid loss additive

•

Extender

•

Solids content

•

Cement fineness

•

Ratios of cement components

CEMENT RheologySLURRY DESIGN  Cement slurries more commonly behaves as Bingham Plastic fluids.

 Common acceptable values: Pv = 100 – 40 cp Yp = 5 – 45 lbf/ft3  Good rheology is important for Mud removal efficiency.

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 Cement displacement efficiency

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•

Achievement of turbulent flow

•

Excessive annular pressure buildup

•

Excessive pump rate requirements

•

Potential for lost circulation occurrence

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RHEOLOGY

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Fann viscometer to determine cement rheology

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

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Fluid Loss CEMENT SLURRY DESIGN

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Fluid Loss

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Low Temperature (<194 deg.F) Fluid Loss Cell

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

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Free Water, Sedimentation CEMENT SLURRY DESIGN & Segregation

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Free Water Control CEMENT SLURRY DESIGN

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Free Water

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Free Water Test Setup with 250 ml Graduated Cylinder

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

Thickening Time  Defined as elapsed time from initial mixing with water to achievement of a final consistency of 100 Bearden Units (Bc)  Thickening times should be designed so that slurries set from the bottom to the top of the well.  Requirements: Slurry Volume, Displacement Volume, Pumping Rates, Logging temperature

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Calculating Cement Volumes:

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CEMENT SLURRY Thickening TimeDESIGN Calculation Excess Cement Volumes:  Does not account for “washouts”  Expressed as % of the slurry required to fill the theoretical volume of the annulus  Excess is based on the OPEN-HOLE ANNULUS volume only REQUIREMENT

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 Ensure sufficient time to perform:

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•

Slurry mixing and pumping

•

Shutdowns: Drop plugs, change tanks

•

Displacement

•

Safety margin: AT LEAST 1 hour

•

Rates dependent

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PRESSURIZED CONSISTOMETER

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High Pressure Consistometer

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THICKENING TIME CHART

Consistometer Chart

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Cement Slurry Design

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Density

Rheology

Fluid Loss

Free Water

Thickening Time

Compressive Strength

CEMENT SLURRY DESIGN Compressive Strength  Test procedures are governed by API Specification 10A and 10B  Cement is cured under downhole conditions

•

Slurry placed at BHST

•

Slurry placed in cube moulds

•

Typically 12 hrs and 24 hrs are used

 Cubes are tested using Carver Press •

Destructive cube crush

•

Unconfined compressive strength (UCS)

•

Pressure applied uniaxial only

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 Ultrasonic cement analyzer (UCA)

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•

Relative strength determined by measuring change in velocity of ultrasonic transmitted through cement

•

As strength develops, transit time through cement decreases, allowing relative strength to be calculated

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Compressive Strength (Destructive Method)

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Fann viscometer to determine cement rheology

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Compressive Strength (Destructive Method)

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Fann viscometer to determine cement rheology

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Compressive Strength (UCA)

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Fann viscometer to determine cement rheology

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Compressive Strength Chart

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Fann viscometer to determine cement rheology

CEMENT SLURRY DESIGN Compressive Strength  Increasing cement densities typically increases CS •

Reduces water: cement ratio

 Can also be enhanced without increasing densities: •

Adding solid content in cement slurry

•

Grinding the cement particles into finer grinds

•

Typical practices:  Adding silica fume additive  Adding colloidal silica additive  Adding silica flour

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 Using ultrafine cement

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Compressive Strength cont..

Minimum Compressive Strengths Preferred for Various Functions

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FUNCTION

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COMPRESSIVE STRENGTH SLURRY TYPE/OPERATION

AXIAL LOAD SUPPORT

500 - 1000 psi

LEAD SLURRIES

DRILLING AHEAD

500 - 1000 psi

TAIL SLURRIES

PERFORATING

1200 - 2000 psi

LINER/PRODUCTION CASING SLURRIES

KICK OFF PLUG (WHIPSTOCK)

3000 psi

SIDE TRACK DENSIFIED SLURRIES

ABANDONMENT PLUG

1000 psi

TAGGING/DRESSING OFF

50 psi

THIXOTROPIC SLURRIES

LOST CIRCULATION PLUG

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

54

Outline

Job Execution

PRE JOB PLANNING- INFO REQUIRED

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      

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MD/TVD/Liner hanger Accurate log temperature - depth of log and time since circulation Trajectory Hole size Pressure Plot Casing/ Liner size & weight Type of mud – spacer planning

JOB CONSIDERATION  

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    

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State & Federal Regulation Formation integrity  Hole washout, Weak Zone/Thief Zone, High pressure Zone Gas migration TOC Mud displacement Cement Placement Technique Slurry Properties

Additives API Cement Classification

Slurry Design

Pre Job Planning

Objective

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What is Cementing?

57

Outline

Job Execution

JOB EXECUTION Well Conditioning



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• • • • • •

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Condition mud Reciprocate or rotate casing Circulate at highest possible rate Use fluid caliper to verify hole volume Monitor bottoms up gas Monitor returns

JOB EXECUTION 

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• • • • • • •

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Cement Mixing Accurately measure density Control density fluctuations Use both top and bottom plug Use preflush or compatible spacer Mix and displace at the designed rates Monitor fluid returns Monitor job parameters using D.A.U.

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Q&A

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CEMENTING METHODS AND SYSTEM FOR THE CO2 WELL

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Agenda • Challenges for CO2 wells • SealBond & Ultraflush Micro Emulsion spacer • Improved cementing systems for CO2 • Expansion feature • Case histories

3

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Possible leakage pathways casing and cement casing and cement cement matrix casing fractures cement and formation SOURCE: Celia et al. (2004)

Results From Field Studies • Portland cement degradation due to CO2: <10 mm / 30 yrs (J.W. Carey et al. 2007)

• Degradation mainly occurs along existing / induced pathways (B. Kutchko et al. 2009)

• Pozz/Portland cement inhibit CO2 migration after carbonation (W. Crow et al. 2009)

 Leakage only due to CO2 attack very unlikely  Cements ability to resist CO2 attack is secondary  Important: Good initial cement bond

Agenda • Challenges for CO2 wells • SealBond & Ultraflush Micro Emulsion spacer • Improved cementing systems for CO2 • Expansion feature • Case histories

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SealBond - Benefits Typical spacer applied prior cementing

SealBond applied prior cementing

• Prevents formation breakdown & fall back of cement tops • Strengthens wellbore for improved cement slurry placement • SPE 140723

More Benefits of SealBond

CO2

Mg2+

H2 S

SO42-

Sealing

Cement

• SealBond sealing acts like a “condom” • Potentially protects cement sheath towards corrosive fluids

Microemulsion Spacer Technology • The MICRO-WASH™ high-definition remediation system

– Removes OBM filter cake damage – Water-wets surface – Requires no energy – Solubilizes oil phase • The MICRO-CURE™ E2 cased-hole remediation system: nonaromatic solvent – Cleans sand surfaces easily – Improves fluid mobility – Removes in situ emulsions – Increases water-wettability – Mobilizes most asphaltene and paraffin • The MICRO-PRIME™ spacer system: mesophase spacer – Cleans casing and tools – Provides ultralow interfacial tension – Provides fast phase inversion – Provides excellent rheological compatibility

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MICRO-WASH™ System Cleaning Plugged Screens As received

After MICRO-WASH™ system

After rinse

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MICRO-PRIME™ System South Louisiana Operator Case History

First failed competitor displacement

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Same tools after MICRO-PRIME system

Purpose of Cement Spacers • Cement spacers are designed to:

– Effectively displace the drilling fluid in the annulus – Convert an oil-wet surface to a water-wet surface – Provide a clean and water-wet surface to which cement can strongly bond • Success in the field is defined by: – Shoe test – Cement bonding logs (CBL)

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New Microemulsion Spacer • The UltraFlush™ ME microemulsion spacer system

– Based on the microemulsion surfactant in MICRO-PRIME technology • Provides ultralow interfacial tension • Provides a fast phase inversion • Provides rheological compatibility – With S/OBM – With cement – Completely removes SBM quickly • Solubilizes the oil • Cleans and water-wets solid surfaces – Stable at temperatures to 300˚F (149˚C)

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Mesophase Spacer

Spacer Wettability Apparatus • Used to determine the apparent wettability of cement spacer systems

and clean nonaqueous drilling fluids Cement will not bond to oil-wet surfaces • When the spacer is properly used:

– – – –

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Prevents mud and cement contamination Provides better bonding potential Ensures a proper annular seal Improves displacement efficiency

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UltraFlush™ ME Spacer Screening Conductivity

Initial: OBM

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Post-titration with spacer poured out

Post-water rinse

SSCT with 10-14 ppg SBM Fresh Water Cement Pre-Flush Spacer Oil-in-brine emulsion Water-Wet Surfaces

Brine-in-oil emulsion Oil-Wet Surfaces

16

Phase inversion

Goniometer

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Measurement of Angle of Deflection • A liquid droplet rests on a solid surface and is surrounded by gas. The contact angle, θC, is the angle formed by a liquid at the three phase boundary where the liquid, gas, and solid intersect.

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UltraFlush™ ME Cleaning Spacers • Cement preflush spacers

– Water-wets casing and formation ahead of cement – Improves cement bond Transition phases for mesophase cleaning solutions

Brine in oil emulsion (invert emulsion) oil-wet surfaces Contact angle 74°

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Phase transition

Oil in brine emulsion (direct emulsion) water-wet surfaces Contact angle < 30°

Effective Laminar Flow (ELF) • First ELF rule governs fluid density hierarchy

– Each displacing fluid should be at least 10% heavier than the fluid it is displacing • Second ELF rule governs friction hierarchy – Each displacing fluid should exert a friction pressure gradient (dP/dz) that is at least 20% higher than the fluid it is displacing • Third ELF rule governs minimum pressure gradients – Each displacing fluid has to be able to break the gel strength of the displaced fluid on all sides of the annulus, even the smaller side of an eccentric annulus, in either a vertical or nonvertical wellbore • Fourth ELF rule governs differential velocity – The velocity of the displacing fluid in the wide side of an eccentric annulus should not exceed the velocity of the fluid being displaced in the narrow side of the same annulus

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Effective Laminar Flow (ELF) • If all four hierarchies are met for both the spacer/mud interface and

the cement/spacer interface, then even in the case of laminar flow in an eccentric, inclined annulus, ELF displacement is possible

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Optimize Flow Regime • Fluid friction pressure curves

– Better design tool insures viscosity and density hierarchy in fluid sequences – Up to four charts with reference temperatures

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Fluids Data – Rheology Cementing Simulator & Modules

• Allows users to enter up to 12 shear rates – Using more realistic shear rates (300-10 rpm) • Auto calculates best fit model, reports r2 • Results tie into mud removal calculations and ECDs

Agenda • Challenges for CO2 wells • SealBond & Ultraflush Micro Emulsion spacer • Improved cementing systems for CO2 • Expansion feature • Case histories

27

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Main Minerals of Set API Cement Source: TUM

C-S-H phases

Portlandite = Ca(OH)2

• C-S-H grab onto another (e.g. zipper) causing high strength • Portlandite does not contribute to the strength (weak point): Disruptive, easy to be leached out & increase brittleness

Portlandite in the Cement Matrix

Source: Blaschke, R. 1985

Polarization microscopy of the set API Cement light: Ca(OH)2 - dark: C-S-H phases or clinker

CO2 Attack in conventional API Cement Sliced

Cut

into

into

half

2.54 cm

half

1.27 cm Thin section See next slide

• API class G / silica flour (15.8 ppg) • Exposed to CO2-loaded water (650 psi & 250ºF) • Static conditions for 30 days

CO2 attack in cement I. unaltered set cement

III. carbonated IV. porous silica (soft) cement

CO2 +

C-S-H phases Ca(OH)2

V. corrosive fluid

dissolve

CaCO3

precipitates

Ca2+aq OH-aq

Carbonation front

H2O ⇌

dissolves Ca2+aq H+aq HCO3-aq

Leaching front

H2CO3 ⇌ H+ +

HCO3-

Design criteria: pozzolanic reaction Reducing the amount of portlandite by adding: • selected pozzolanic materials:“SiO2” (“Al2O3”) Ca(OH)2 + “SiO2” (“Al2O3”) → C-S-H (C-A-S-H) phases → Cement matrix will become denser

Improve the Resistance of Cement 1. CO2 / corrosive fluids preferentially react with the Portlandite => Eliminate the Portlandite in set cement

2. Carbonation / corrosion of C-S-H phases also takes place => Partly substitution of API cement with inert material

3. Corrosion reactions are diffusion controlled processes • Lower permeability of set cement = slower corrosion => Reduce the permeability

Improved vs API Class G Portlandite Ca(OH)2

Set API Class G

Improved

cured at 200° F, 3000 psi

Water Ca(OH)2 Slurry permeability portlandite Compressi density (micro content ve strength (lbs/gal) darcy) (%) 72 hrs (psi)

Improved Systems

15.8

0.002

Not detectable

Set API Class G

15.8

2.100

9.5

Tensile strength 72 hrs (psi)

4,674

459

4,807

378

Improved vs API Class G Portlandite Ca(OH)2

Set API Class G

Improved

cured at 200° F, 3000 psi

Water Ca(OH)2 Slurry permeability portlandite Compressi density (micro content ve strength (lbs/gal) darcy) (%) 72 hrs (psi)

Improved extended

14.0

0.15

Not detectable

Set API Class G

14.0

10.80

9.2

Tensile strength 72 hrs (psi)

2,529

272

1,633

170

Improved vs. API Class G (96 hrs curing) Improved

Conventional

CO2 Lab Testings • HTHP curing chamber Improved

Conventional

CO2

• Specimens pre-cured at 3,000 psi & 300 °F for 96 hrs • Exposure to CO2 loaded water at 3,000 psi & 300 °F

Effect of CO2 on Cements’ Mechanical Properties

Cement system

density (ppg)

Young’s modulus (Mpsi) Confining Stress: 1000 psi

Poisson’s ratio Confining Stress: 1000 psi

Compressive strength (psi) Confined

Tensile strength (psi) Unconfined

After 96 hrs curing at 3,000 psi / 300 °F (before CO2 exposure) Improved

15.0

1.52

0.32

>5,800

354

Conventional

15.0

2.07

0.33

>5,860

258

After 30 days exposure to CO2 at 3,000 psi / 300 °F Improved

16.1

0.85

0.26

>5,850

468

Conventional

16.5

1.17

0.23

>5,850

438

After 6 Months Exposure to CO2 Improved cement

Conventional API cement

Cement specimen flaked off (diameter =-0.6 mm) Cement bond failure / migration pathways => Loss of zonal isolation

Durability in 1 M HCl (24 hrs) Improved

Conventional

Dissolving attack: 2 H+ + Ca(OH)2

Ca2+ + 2 H2O

12 H+ + C6-S5-H6

6 Ca2+ + 5 SiO2 + 6 H2O

Durability in 1 M HCl (250 d) Improved

Conventional • fell apart • no strength • squishy morph.

C.S.= 1,520 psi W.P.= 0.00123 mD

Cement Sheath Failure Mechanisms Vertical radial cracking: • due to tangential stress • producing a tensile failure

Bonding failure: • due to excessive radial stress • producing a compressive failure

Tensile Strength Test Methods

Direct Uniaxial TensileStrength (UTS) : ASTM C190-85

HTHP Tensiometer Gato do mato field, Campus basin (off shore Brazil), 11/04/2010

Patent: US 7,191,663 B2 Available only from BAKER HUGHES

HTHP Tensiometer

• Testing up to 600 F & 5,000 psi • SPE 97967 Testing Cement Tensile Behavior Under Downhole Conditions

Design giving higher Tensile Strength at HPHT

Improved cement

Field proven technology (SPE 143772)

Agenda • Challenges for CO2 wells • SealBond & Ultraflush Micro Emulsion spacer • Improved cementing systems for CO2 • Expansion feature • Case histories

48

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Split ring test – accurate method?

• A split, expandable ring placed between flat metal plates with a screw • Slurry poured in assembly and allowed to initial set • Measurement across the 2 points, spanning the split in the ring

=> Assembly cooled and de-pressurerized => Only single point-in-time test result => Cured samples undergo stresses & pot. dimensions altering effects => Cannot quantify linear expansion in an uninterrupted downhole environment 49

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Real-time Expansion & Shrinkage under Temperature & Pressure

Expansion / shrinkage mold for cement

Modified curing chamber: • continuous “in-situ” measuring • at downhole conditions

Example for cement shrinkage

Examples for cement expansion

Right Sample: Class G cement + 35% S-8 + 5.0% EC-2 + 0.8% FL-25 + 0.6% CD-32 + 0.5% R8 mixed at 16.7 ppg, Yield = 1.40 cu ft/sk and fresh water = 5.02 gal/sk 4000

12 Test Pressure

3500

10

Design expansion carefully: • Compensate shrinkage • Slight expansion to support bond

% Linea r Ex pansion or Shrinka ge

3000

2500

6 2000

% Linear Expansion

4

1500

Test Temperature

2

Base-line 0

500

0

• Too much expansion results in cracks

1000

5

10

15

20

25

30

35

40

45

50

Ela psed Time (hr) 0

-2 The cement was heated in 4 hrs to it s final (BHST) temperature and pressure. After 4 hrs, the t emp and pres has est abilized. Any test data above the base-line are consider expansion and below are shrinkage.

Te st Pre ssure(psi ) and Tempe rature(°F)

Out of ranges (expansion device)

8

Agenda • Challenges for CO2 wells • SealBond & Ultraflush Micro Emulsion spacer • Improved cementing systems for CO2 • Expansion feature • Case histories

53

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Case history 1: Middle East Well for an EOR-CO2 project, 07/22/2011 Depth: Job Type: BHST: BHCT: Cement: Density: Yield: Water: Thickening Time: Compressive strength @24 hrs at 250 F: Rheology @ 80 F (180 F) PV (cps): YP (lbf/100 sqft): Fluid loss: Free fluid:

2,672 meters (8,765 feet) 7” Liner 121 °C (250 °F) 82 °C (180 °F) Expanding improved cement (84 bbl) 2002 kg/m³ (16.7 ppg) 0.691 m³/tonne 0.180 m³/tonne 5:05 hr:mn (70Bc) 5800 psi 240 (144) 13 (10) 18 cc/30 minutes 0.0 %

Case history 1: Middle East • Cementation of a 7” liner for an EOR-CO2 project • 7” liner run in 8½-in. hole to 8,765 ft; prev. 9-5/8” csg shoe at 8,480 ft • Drilling fluid was a non-damaging fluid (NDF) weighted to 10.4 ppg • 48 bbls of expansive cement system batch-mixed at 16.7 ppg • Pumped & displaced into 7”x8½” annulus w/o any operational incidents • Customer: very satisfied w/ technical support, operational performance & excellent slurry properties witnessed on site • 7'' liner USIT LOG available with excellent cement bond results

Case history 1: Middle East • Results look good for entire interval • >8480 ft. attempt to log in a csg x csg

environment picking up reflection of the outer csg string • Reason for the large quantity of data

errors seen in the evaluation, which are presented as green on the log • Some interference in the csg tracks to

the left side that appear to look like stripes on the log • These “errors” are transmitted across

the entire log & are not reflective of the cement quality in the interval 56

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Case history 1: Middle East • In the open hole - no issues that

would lead to believe there are any isolation problems • In several places cycle skip on the

log, indicating excellent dampening of the signal • Some minor issues with tool

eccentering, but not significant • Results of the evaluation show a well

isolated interval

57

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Case history 2: CO2 Capture Storage Spain: 09/10/2012 Depth: Job Type: BHST: BHCT: Cement: Density: Thickening Time: Rheology 300 rpm: 200 rpm: 100 rpm: 6 rpm: 3 rpm: Fluid loss: Free fluid: Compressive Strength: 3.5 MPa (500 psi): 24 hours:

2071 meters (6790 feet) 9 5/8" & 7” CEMENTING 50°C (122°F) 45°C (113°F) tail slurry 15.86 ppg (1.90 g/cc) 5:28 hr:mn (100Bc) 231 165 97 11 4 24 cc/30 minutes 0.0 % 8.00 hours 40.6 MPa (5890 psi)

Case history 2: CO2 Capture Storage

Case history 2: CO2 Capture Storage

Case history 2: CO2 Capture Storage

61

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Case history 2: CO2 Capture Storage • 7” production liner cementing job • CBL/VDL shows a good zonal isolation throughout the annulus

• Contamination at TOL because job was performed w/o any wiper plugs • Explains the CBL/VDL not very good in upper part of the section at TOL • For the rest the client was very happy about the operation, especially since no surface release plugs system was used

Case history 3: CO2 wells Natural CO2/ H2S producer (Neuquén, Argentina), July 2011 Depth (MD=TVD): Job Type: BHST: BHCT: Cement: Density: Yield:

3,300 meters (10,827 feet) 9 5/8“intermediate 81°C (178°F) 76°C (169°F) Improved cement (batch-mixed) 1680 kg/m³ (14.0 ppg) 1002 m³/tonne (1,509 ft3/sk)

Thickening Time: Rheology (76°C) 300 rpm: 200 rpm: 100 rpm: 6 rpm: 3 rpm: Fluid loss (76°C): Free fluid:

5:20 hr:mn (Bc) 255 191 108 12 10 12 cc/30 minutes 0.0 %

Case history 3: CO2 wells Natural CO2/ H2S producer (Neuquén, Argentina), July 2011

Case history 4: CO2 wells 8 wells EOR: 4 prod. + 4 inj. (Middle East), 07/15/2011 Depth (MD=TVD): Job Type: BHST: BHCT: Cement: Density: Yield: Water: Thickening Time:

2,275 meters (7,465 feet) 4 1/2” Liner 104°C (220°F) 65°C (149°F) Improved cement (25 bbl, batch-mixed) 1953 kg/m³ (16.3 ppg) 0.604 m³/tonne (0.91 ft3/sk) 0.133 m³/tonne (1.50 gal/sk) 7:30 hr:mn (100 Bc)

Rheology (149°F) PV (cps): YP (lbf/100 sqft): Fluid loss: Free fluid:

228 42 35 cc/30 minutes 0.0 %

Case history 4: CO2 wells 8 wells EOR: 4 prod. + 4 inj. (Middle East), 07/15/2011 The first job in (Middle East) was performed on the first oil-producer well drilled in an eight-well enhanced oil recovery (EOR) – CO2 project, which will eventually consist of four producers and four injectors. Improved cement was selected as the customer’s preferred cementing medium for the 4½-in. liner sections. The liner was run in 6-1/8-in open hole to a depth of 7,465 ft with the top of the liner placed at 6,731 ft. The previous 7-in liner shoe was at 7,051 ft. The mud was a water-based system weighted to 10.5 pounds per gallon (ppg) with calcium carbonate. A total volume of 25 barrels of the improved cement was batch-mixed for the job and pumped at a density 16.3 ppg. The client expressed satisfaction with the entire operation, including technical support and operational execution.

Case history 5: CO2 wells Off shore Brazil, 11/04/2010 Depth: Job Type: BHST: BHCT: Cement: Density: Yield: Water: Thickening Time: Rheology BHCT (ambient) 300 rpm: 200 rpm: 100 rpm: YP Fluid loss: Free fluid:

5850 meters (19,193 feet) 7” liner 108°C (227°F) 92°C (197°F) Improved cement 1797 kg/m³ (15.0 ppg) 0.846 m³/tonne 0.378 m³/tonne 6:12 hr:mn (70Bc) 180 (202) 137 (137) 78 (80) 21.9 (13.3) 18 cc/30 minutes 0.0 %

Case history 6: CO2 wells British Columbia Depth: Job Type: BHST: 37°C (99°F) BHCT: 31°C (88°F) Tail Cement: Density: Yield: Water: Thickening Time: Rheology 300 rpm: 200 rpm: 100 rpm: 6 rpm: Fluid loss: Free fluid:

1010 meters (3310 feet) production casing

Improved cement 1770 kg/m³ (14.8 ppg) 0.809 m³/tonne 0.432 m³/tonne 4:43 hr:mn (100Bc) 249 171 90 8 10 cc/30 minutes 0.0 %

Case history 7: CO2 wells British Columbia Depth:

1600 meters (5250 feet)

Job Type:

production casing

BHST:

56°C (133°F)

BHCT:

38°C (100°F)

Tail Cement:

Improved cement

Thickening Time:

4:41 hr:mn (100Bc)

Case history 8: CO2 Capture Storage North eastern British Columbia Depth: Job Type: BHST: BHCT: Cement: Thickening Time: Rheology 300 rpm: 200 rpm: 100 rpm: 6 rpm: Fluid loss: Free fluid: Compressive Strength: 0.35 MPa (50 psi): 0.7 MPa (100 psi): 3.5 MPa (500 psi): 24 hours:

2071 meters (6790 feet) intermediate casing 117°C (243°F) 60°C (140°F) Improved cement 4:53 hr:mn (100Bc) 141 100 58 13 8 cc/30 minutes 0.0 % 5.10 5.13 5.30 15.5

hours hours hours MPa (2250 psi)

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SELF HEALING CEMENT A SIMPLE SOLUTION FOR COMPLEX WELL

62

Agenda • Issue • Causes • Solutions

• Why Self Healing • Test Apparatus • Results

• When to Use • Summary

2

© 2011 Baker Hughes Incorporated. All Rights Reserved.

Challenge • Sustained casing pressure – Observed in more than 11,000 casing strings in 8,000 wells in OCS – Magnitude of leak rate is as important as magnitude of pressure when determining potential hazard

Gulf of Mexico Wells (LSU Study, 2002)

3

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Causes • High-compressive strength vs. lower compressive

strength compressible systems • Poor cement bonding – Cement best practices

• Cement failure – Pressure changes – Temperature changes – Reservoir changes

4

© 2012 Baker Hughes Incorporated. All Rights Reserved.

What Do We Do Today • Follow best practices – Centralization – Spacers – Displacement rates – Pipe movement • Set for Life™ cementing system designs – DuraSet system • • • •

Low Young’s Modulus Higher Poisson’s ratio Improved tensile to compressive strength ratio IsoVision™ software modeling application

• What if assumptions are incorrect 5

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Simple Solution to a Complex Problem • Self-healing cement system – Must be easily blended and mixed in cement – No negative effect on other cement properties – Works over a wide range of temperatures – Must be capable of plugging flow of hydrocarbons • Through cement matrix • Through microannulus

– Capable of healing multiple times – Able to define size of cracks in matrix or microannulus capable of healing

6

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Test Apparatus • Test apparatus designed and built – Cement cured under temperature and pressure – Adjustment of desired crack or microannulus width – Cement hydraulically cracked under temperature – Capable of controlling, measuring and recording developed crack size – Test through cracked cement matrix or induced microannulus – Measure and record flow and pressure – Capable of testing with gas, oil or other fluids 7

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Self-Healing Cement CLASS H cement + Self-Healing Additives mixed at 15.2 ppg Curing Time = 96 hrs, room temp, 3000 psi Fracturing Test, C-Frac WIDTH = 0.013", Crude oil 900

0.016

800

0.014

0.012

600

max PISTON TRAVEL = 0.0142"

500

max Frac Pressure = 760 psi

400

0.008

0.006 300

DS bolt adjusted to = 0.013 " 0.004

200

0.002

100

0

0 0

8

0.01

50

© 2012 Baker Hughes Incorporated. All Rights Reserved.

100 ELAPSED TIME (seconds)

150

200

DS BOLT and PISTON TRAVEL (inches)

FRACTURING PRESSURE (psi)

700

Self-Healing Cement Class H cement + Self-Healing Additive mixed at 15.2 ppg Curing time = 96 hrs, room temp, 3000 psi BREAK-SEAL TEST, C-FACTURE WIDTH = 0.013" , fractured with Crude Oil 700

25

max Pressure to Break-Seal = 654 psi.

600

20

Crude Oil Flow 15 400

300 10

200 5 100

0

0 0

100

200

300

400

500

ELAPSED TIME (secs)

9

© 2012 Baker Hughes Incorporated. All Rights Reserved.

600

700

800

900

CRUDE OIL FLOW (cc)

Pressure to BREAK SEAL (psi)

500

Self-Healing Cement Fracturing - Break and Seal test Controlled crack width = 0.003", curing time = 96 hrs, Heal Time = 24 hrs, rm temp 1200

979

1000

Test Pressure (psi)

894

880 791

Crack Initiation Pressure

800

Break-Seal # 1

600

Break-Seal # 2

400

357

Break-Seal # 3

250 Break-Seal # 4

200

Break-Seal # 5 0 0

10

1

© 2012 Baker Hughes Incorporated. All Rights Reserved.

2

3 4 Ageing Time (days)

5

6

7

Results • Material easily mixed and blended in cement at effective

concentrations • No negative effects on cement properties – Enhanced mechanical properties

• Tests being performed over a wide

temperature range • Sealed cracks up to .006” • Capable of sealing multiple times • Ready for field trials in Q3/Q4 2012

11

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Fig # 3: The picture is showing the induced Crack Width of 0.003”across entry and exit port.

When To Use • Every Well? • Fields with a history of sustained casing pressure • High tectonic stress areas

• Risk mitigation – Unable to follow all of best practices • Less than optimal centralization • No pipe movement

• Gas storage wells • Plug and Abandonment

12

© 2011 Baker Hughes Incorporated. All Rights Reserved.

Summary • Sustained casing pressure is a concern • Improvements have been made but there are still issues • Developed test apparatus that can measure – Size of crack – Flow rate and pressure – Look at cement matrix and microannulus

• Product capable of sealing multiple times • Not for every well but when used correctly, it can be

effective • Simple solution to a complex problem

13

© 2012 Baker Hughes Incorporated. All Rights Reserved.

Questions

14

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© 2014 Baker Hughes Incorporated. All Rights Reserved.

Q&A

60

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THANK YOU

61