IDP Feb 2015_Revised

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2014 BAKER HUGHES INCORPORATED. ALL RIGHTS RESERVED. TERMS AND CONDITIONS OF USE: BY ACCEPTING THIS DOCUMENT, THE RECIPIENT AGREES THAT THE DOCUMENT TOGETHER WITH ALL INFORMATION INCLUDED THEREIN IS THE

CONFIDENTIAL AND PROPRIETARY PROPERTY OF BAKER HUGHES INCORPORATED AND INCLUDES VALUABLE TRADE SECRETS AND/OR PROPRIETARY INF ORMATION OF BAKER HUGHES (COLLECTIVELY " INFORMATION"). BAKER HUGHES RETAINS ALL RIGHTS

UNDER COPYRIGHT LAWS AND TRADE SECRET LAWS OF THE UNITED STATES OF AMERICA AND OTHER COUNTRIES. THE RECIPIENT FURTHER AGREES TH AT THE DOCUMENT MAY NOT BE DISTRIBUTED, TRANSMITTED, COPIED OR REPRODUCED IN WHOLE OR

IN PART BY ANY MEANS, ELECTRONIC, MECHANICAL, OR OTHERWISE, WITHOUT THE EXPRESS PRIOR WRITTEN CONSENT OF BAKER HUGHES, AND MA Y NOT BE USED DIRECTLY OR INDIRECTLY IN ANY WAY DETRIMENTAL TO BAKER HUGHES INTEREST.

Fundamental of Cementing Services

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Outline What is Cementing?

Objective

API Cement Classification

Additives

Slurry Design

Pre Job Planning

Job Execution

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What is Cementing ???

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What is Cementing ???

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.

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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Classifications of Cementing

Primary

Plug Method

Inner String Method

Stage Cementing

Secondary

Plug Back Cementing

Squeeze Cementing

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Objectives of Primary Cementing

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

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Secondary Cementing

Purpose

Supplementing faulty primary

cement job

Repair casing defects

Stop loss circulation

during drilling

Shut off old perfs for

recompletion

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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API Classification of Cements

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

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)

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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Cement Additives

Shorten thickening time Accelerator

Lengthen thickening time Retarder

To ease mixability at surface Dispersant

Control amount of fluid loss to formation Fluid Loss Additive

Prevent foam production Defoamer

Prevent gas migration Gas Block

Increase slurry density Weighting Agent

Reduce slurry density (maintain strength) Light Weight Agent

Seal off lost circulation zone LCM

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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)

CEMENT ADDITIVES Accelerator

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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

CEMENT ADDITIVES Retarder

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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

Dispersant

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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

CEMENT ADDITIVES Fluid Loss

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CEMENT ADDITIVES

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

Defoamer

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Hydration in place the hydrostatic reduce

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

Gas Block

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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

DITIVES Weighting Agents

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The weight of cement slurry can be reduced by :-

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

Light Weight Additives

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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

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

CEMENT ADDITIVES Lost Circulation Materials

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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Cement Slurry Design

Density Rheology Fluid Loss

Free Water Thickening

Time Compressive

Strength

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CEMENT/SPACER DENSITY

CEMENT SLURRY DESIGN

Co

nsi

der

atio

n

Prevent losses to formation

Prevent flow from permeable formations

Strength development

Slurry stability


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15.8ppg typically used for neat class G based on API recommend water ratio of 44%

RULE OF THUMB : < <

Density of slurry normally 1 ppg higher than mud weight

Density Density

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Time Compressive

Strength

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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

Other models

Rheology

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Influenced by:

Cement density (water contents)

Dispersant

Retarder

Fluid loss additive

Extender

Solids content

Cement fineness

Ratios of cement components

CEMENT SLURRY DESIGN Rheology

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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.

Cement displacement efficiency

Achievement of turbulent flow

Excessive annular pressure buildup

Excessive pump rate requirements

Potential for lost circulation occurrence

CEMENT SLURRY DESIGN Rheology

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RHEOLOGY

Fann viscometer to determine cement rheology

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Time Compressive

Strength

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CEMENT SLURRY DESIGN Fluid Loss

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Fluid Loss

Low Temperature (

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Time Compressive

Strength

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CEMENT SLURRY DESIGN Free Water, Sedimentation & Segregation

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CEMENT SLURRY DESIGN Free Water Control

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Free Water Test Setup with 250 ml

Graduated Cylinder

Free Water

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Time Compressive

Strength

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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

Calculating Cement Volumes:

Thickening Time

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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

Ensure sufficient time to perform:

Slurry mixing and pumping

Shutdowns: Drop plugs, change tanks

Displacement

Safety margin: AT LEAST 1 hour

Rates dependent

CEMENT SLURRY DESIGN Thickening Time Calculation

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High Pressure Consistometer

PRESSURIZED CONSISTOMETER

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Consistometer Chart

THICKENING TIME CHART

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Time Compressive

Strength

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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

Ultrasonic cement analyzer (UCA)

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

Compressive Strength

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Compressive Strength (Destructive Method)


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Compressive Strength (Destructive Method)


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Compressive Strength (UCA)


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Compressive Strength Chart


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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

Using ultrafine cement

Compressive Strength

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Minimum Compressive Strengths Preferred for Various Functions

FUNCTION

AXIAL LOAD SUPPORT

DRILLING AHEAD

PERFORATING

KICK OFF PLUG (WHIPSTOCK)

ABANDONMENT PLUG

LOST CIRCULATION PLUG

COMPRESSIVE STRENGTH

500 - 1000 psi

500 - 1000 psi

1200 - 2000 psi

3000 psi

1000 psi

50 psi

SLURRY TYPE/OPERATION

LEAD SLURRIES

TAIL SLURRIES

LINER/PRODUCTION CASING SLURRIES

SIDE TRACK DENSIFIED SLURRIES

TAGGING/DRESSING OFF

THIXOTROPIC SLURRIES

Compressive Strength cont..

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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PRE JOB PLANNING- INFO REQUIRED

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

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JOB CONSIDERATION

State & Federal Regulation

Formation integrity Hole washout, Weak Zone/Thief Zone, High pressure Zone

Gas migration

TOC

Mud displacement

Cement Placement Technique

Slurry Properties

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Objective


Additives

Slurry Design

Pre Job Planning

Job Execution

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JOB EXECUTION

Well Conditioning

Condition mud

Reciprocate or rotate casing

Circulate at highest possible rate

Use fluid caliper to verify hole volume

Monitor bottoms up gas

Monitor returns

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JOB EXECUTION

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

Agenda

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

2012 Baker Hughes Incorporated. All Rights Reserved.3

Possible leakage pathwayscasing 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:

Agenda



SealBond - Benefits

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

Typicalspacer

applied priorcementing

SealBond

applied priorcementing

More Benefits of SealBond

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

CO2

Sealing

Mg2+

H2S SO42-

Cement

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

9 2012 Baker Hughes Incorporated. All Rights Reserved.

MICRO-WASH SystemCleaning Plugged Screens


As received

After MICRO-WASH system

After rinse

MICRO-PRIME SystemSouth Louisiana Operator Case History

First failed competitor displacement 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)


New Microemulsion Spacer

The UltraFlushME 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 300F (149C)

13

MesophaseSpacer

2012 Baker Hughes Incorporated. All Rights Reserved.

Spacer Wettability Apparatus

Used to determine the apparent wettability of cement spacer systemsand clean nonaqueous drilling fluids

Cement will not bond to oil-wet surfaces

When the spacer is properly used: Prevents mud and cement contamination Provides better bonding potential Ensures a proper annular seal Improves displacement efficiency


UltraFlushME SpacerScreening Conductivity

Initial: OBM Post-titration withspacer poured out

Post-water rinse


SSCT with 10-14 ppg SBM

16

Fresh Water Cement Pre-Flush SpacerOil-in-brine emulsionWater-Wet Surfaces

Brine-in-oil emulsionOil-Wet Surfaces

Phaseinversion


Goniometer

A liquid droplet rests on a solid surface and is surroundedby gas. The contact angle, C, is the angle formed by a liquid at the three phase boundary where the liquid, gas,and solid intersect.


Measurement of Angle of Deflection

UltraFlushME Cleaning Spacers

Cement preflush spacers Water-wets casing and formation ahead of cement Improves cement bond

Brine in oil emulsion(invert emulsion)oil-wet surfaces

Phase transition Oil in brine emulsion(direct emulsion)

water-wet surfaces

Transition phases for mesophase cleaning solutions

Contact angle 74


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) thatis 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 aneccentric 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 narrowside of the same annulus


Effective Laminar Flow (ELF)

If all four hierarchies are met for both the spacer/mud interface andthe cement/spacer interface, then even in the case of laminar flow inan eccentric, inclined annulus, ELF displacement is possible


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


Fluids Data RheologyCementing 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



Main Minerals of Set API Cement

Portlandite = Ca(OH)2C-S-H phases

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

Source: TUM

Portlandite in the Cement Matrix

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

Source: Blaschke, R. 1985

CO2 Attack in conventional API Cement

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

1.27 cm

Thin sectionSee next slide

Slicedintohalf

Cutintohalf2.54 cm

CO2 attack in cement

I. unalteredset cement

III. carbonatedcement

IV. poroussilica (soft)

CO2 +

H2O

H2CO3

H+ +

HCO3-

V. corrosivefluid

Leaching frontCarbonation front

C-S-H phases

Ca(OH)2dissolve

Ca2+aqOH-aq

precipitates dissolves

Ca2+aqH+aqHCO3-aq

CaCO3

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

Design criteria: pozzolanic reaction

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

cured at 200 F,3000 psi

Slurrydensity(lbs/gal)

Waterpermeability

(microdarcy)

Ca(OH)2portlandite

content(%)

Compressive strength72 hrs (psi)

Tensilestrength72 hrs(psi)

Improved Systems 15.8 0.002Not

detectable 4,674 459Set API Class G 15.8 2.100 9.5 4,807 378

PortlanditeCa(OH)2

Improved Set API Class G

cured at 200 F,3000 psi

Slurrydensity(lbs/gal)

Waterpermeability

(microdarcy)

Ca(OH)2portlandite

content(%)

Compressive strength72 hrs (psi)

Tensilestrength72 hrs(psi)

Improved extended 14.0 0.15Not

detectable 2,529 272Set API Class G 14.0 10.80 9.2 1,633 170

Improved vs API Class GPortlanditeCa(OH)2

Improved Set API Class G

Improved vs. API Class G (96 hrs curing)

ConventionalImproved

CO2 Lab Testings

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

Improved Conventional

CO2

HTHP curing chamber

Effect of CO2 on Cements MechanicalProperties

Cementsystem

density(ppg)

Youngsmodulus

(Mpsi)Confining

Stress: 1000psi

Poissonsratio

ConfiningStress:

1000 psi

Compressivestrength

(psi)Confined

Tensilestrength

(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

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

Improved cement Conventional API cement

Durability in 1 M HCl (24 hrs)

Dissolving attack:

2 H+ + Ca(OH)2 Ca2+ + 2 H2O

12 H+ + C6-S5-H6 6 Ca2+ + 5 SiO2 + 6 H2O

ConventionalImproved

Conventional

C.S.= 1,520 psiW.P.= 0.00123 mD

fell apart no strength squishy morph.

Durability in 1 M HCl (250 d)

Improved

Cement Sheath Failure Mechanisms

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

Vertical radial cracking: due to tangential stress producing a tensile 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

Testing up to 600 F & 5,000 psi

HTHP Tensiometer

SPE 97967

Testing Cement Tensile Behavior Under Downhole Conditions

Design giving higher Tensile Strength at HPHT

Improved cement

Field proven technology (SPE 143772)

Agenda



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


Real-time Expansion & Shrinkageunder Temperature & Pressure

Expansion / shrinkagemold for cement

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

Example for cement shrinkage

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

-2

0

2

4

6

8

10

12

0 5 10 15 20 25 30 35 40 45 50Elapsed Time (hr)

%Li

near

Expa

nsio

nor

Shr

inka

ge

0

500

1000

1500

2000

2500

3000

3500

4000

Test

Pres

sure

(psi

)and

Tem

pera

ture

(F)

% Linear Expansion

Test Temperature

Test Pressure

Out of ranges (expansion device)

Base-line

The cement was heated in 4 hrs to its final (BHST) temperature and pressure. After 4 hrs, the temp and pres has estabilized.Any test data above the base-line are consider expansion and below are shrinkage.

Examples for cement expansion

Design expansion carefully:

Compensate shrinkage

Slight expansion to support bond

Too much expansion results in cracks

Agenda



Case history 1: Middle EastWell for an EOR-CO2 project, 07/22/2011

Depth: 2,672 meters (8,765 feet)Job Type: 7 LinerBHST: 121 C (250 F)BHCT: 82 C (180 F)Cement: Expanding improved cement (84 bbl)Density: 2002 kg/m (16.7 ppg)Yield: 0.691 m/tonneWater: 0.180 m/tonneThickening Time: 5:05 hr:mn (70Bc)Compressive strength@24 hrs at 250 F: 5800 psiRheology @ 80 F (180 F)PV (cps): 240 (144)YP (lbf/100 sqft): 13 (10)Fluid loss: 18 cc/30 minutesFree fluid: 0.0 %

Case history 1: Middle East

Cementation of a 7 liner for an EOR-CO2 project

7 liner run in 8-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 7x8 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


Results look good for entire interval

>8480 ft. attempt to log in a csg x csgenvironment picking up reflection ofthe outer csg string

Reason for the large quantity of dataerrors seen in the evaluation, whichare presented as green on the log

Some interference in the csg tracks tothe left side that appear to look likestripes on the log

These errors are transmitted acrossthe entire log & are not reflective ofthe cement quality in the interval



In the open hole - no issues thatwould lead to believe there are anyisolation problems

In several places cycle skip on thelog, indicating excellent dampening ofthe signal

Some minor issues with tooleccentering, but not significant

Results of the evaluation show a wellisolated interval


Case history 2: CO2 Capture StorageSpain: 09/10/2012

Depth: 2071 meters (6790 feet)Job Type: 9 5/8" & 7 CEMENTINGBHST: 50C (122F)BHCT: 45C (113F)Cement: tail slurryDensity: 15.86 ppg (1.90 g/cc)Thickening Time: 5:28 hr:mn (100Bc)Rheology300 rpm: 231200 rpm: 165100 rpm: 976 rpm: 113 rpm: 4Fluid loss: 24 cc/30 minutesFree fluid: 0.0 %Compressive Strength:3.5 MPa (500 psi): 8.00 hours24 hours: 40.6 MPa (5890 psi)

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 wellsNatural CO2/ H2S producer (Neuqun, Argentina), July 2011

Depth (MD=TVD): 3,300 meters (10,827 feet)Job Type: 9 5/8intermediateBHST: 81C (178F)BHCT: 76C (169F)Cement: Improved cement (batch-mixed)Density: 1680 kg/m (14.0 ppg)Yield: 1002 m/tonne (1,509 ft3/sk)

Thickening Time: 5:20 hr:mn (Bc)Rheology (76C)300 rpm: 255200 rpm: 191100 rpm: 108

6 rpm: 123 rpm: 10

Fluid loss (76C): 12 cc/30 minutesFree fluid: 0.0 %

Case history 3: CO2 wellsNatural CO2/ H2S producer (Neuqun, Argentina), July 2011

Case history 4: CO2 wells8 wells EOR: 4 prod. + 4 inj. (Middle East), 07/15/2011

Depth (MD=TVD): 2,275 meters (7,465 feet)Job Type: 4 1/2 LinerBHST: 104C (220F)BHCT: 65C (149F)Cement: Improved cement (25 bbl, batch-mixed)Density: 1953 kg/m (16.3 ppg)Yield: 0.604 m/tonne (0.91 ft3/sk)Water: 0.133 m/tonne (1.50 gal/sk)Thickening Time: 7:30 hr:mn (100 Bc)

Rheology (149F)PV (cps): 228YP (lbf/100 sqft): 42Fluid loss: 35 cc/30 minutesFree fluid: 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 welldrilled in an eight-well enhanced oil recovery (EOR) CO2 project, whichwill eventually consist of four producers and four injectors. Improvedcement was selected as the customers preferred cementing medium forthe 4-in. liner sections. The liner was run in 6-1/8-in open hole to adepth of 7,465 ft with the top of the liner placed at 6,731 ft. The previous7-in liner shoe was at 7,051 ft. The mud was a water-based systemweighted to 10.5 pounds per gallon (ppg) with calcium carbonate. A totalvolume of 25 barrels of the improved cement was batch-mixed for the joband pumped at a density 16.3 ppg. The client expressed satisfaction withthe entire operation, including technical support and operationalexecution.

Case history 5: CO2 wellsOff shore Brazil, 11/04/2010

Depth: 5850 meters (19,193 feet)Job Type: 7 linerBHST: 108C (227F)BHCT: 92C (197F)Cement: Improved cementDensity: 1797 kg/m (15.0 ppg)Yield: 0.846 m/tonneWater: 0.378 m/tonneThickening Time: 6:12 hr:mn (70Bc)Rheology BHCT (ambient)300 rpm: 180 (202)200 rpm: 137 (137)100 rpm: 78 (80)YP 21.9 (13.3)Fluid loss: 18 cc/30 minutesFree fluid: 0.0 %


British Columbia

Depth: 1010 meters (3310 feet)Job Type: production casingBHST: 37C (99F)BHCT: 31C (88F)Tail Cement: Improved cementDensity: 1770 kg/m (14.8 ppg)Yield: 0.809 m/tonneWater: 0.432 m/tonneThickening Time: 4:43 hr:mn (100Bc)Rheology300 rpm: 249200 rpm: 171100 rpm: 906 rpm: 8Fluid loss: 10 cc/30 minutesFree fluid: 0.0 %


British Columbia

Depth: 1600 meters (5250 feet)Job Type: production casingBHST: 56C (133F)BHCT: 38C (100F)Tail Cement: Improved cementThickening Time: 4:41 hr:mn (100Bc)


North eastern British Columbia

Depth: 2071 meters (6790 feet)Job Type: intermediate casingBHST: 117C (243F)BHCT: 60C (140F)Cement: Improved cementThickening Time: 4:53 hr:mn (100Bc)Rheology300 rpm: 141200 rpm: 100100 rpm: 586 rpm: 13Fluid loss: 8 cc/30 minutesFree fluid: 0.0 %Compressive Strength:0.35 MPa (50 psi): 5.10 hours0.7 MPa (100 psi): 5.13 hours3.5 MPa (500 psi): 5.30 hours24 hours: 15.5 MPa (2250 psi)

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SELF HEALING CEMENT A SIMPLE SOLUTION FOR

COMPLEX WELL

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)

Causes

High-compressive strength vs. lower compressive

strength compressible systems

Poor cement bonding

Cement best practices

Cement failure

Pressure changes

Temperature changes

Reservoir changes


What Do We Do Today

Follow best practices

Centralization

Spacers

Displacement rates

Pipe movement

Set for Life cementing system designs

DuraSet system

Low Youngs Modulus

Higher Poissons ratio

Improved tensile to compressive strength ratio

IsoVision software modeling application

What if assumptions are incorrect


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


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


00.002

0.004

0.006

0.008

0.01

0.012

0.014

0.016

0

100

200

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400

500

600

700

800

900

0 50 100 150 200

DS

BO

LT a

nd

PIS

TON

TR

AV

EL (i

nch

es)

FRA

CTU

RIN

G P

RES

SUR

E (p

si)

ELAPSED TIME (seconds)

CLASS H cement + Self-Healing Additives mixed at 15.2 ppgCuring Time = 96 hrs, room temp, 3000 psi

Fracturing Test, C-Frac WIDTH = 0.013", Crude oil

DS bolt adjusted to

= 0.013 "

max PISTON

TRAVEL = 0.0142"

max Frac Pressure

= 760 psi

Self-Healing Cement


05

10

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20

25

0

100

200

300

400

500

600

700

0 100 200 300 400 500 600 700 800 900

CR

UD

E O

IL F

LOW

(cc

)

Pre

ssu

re t

o B

REA

K S

EAL

(psi

)

ELAPSED TIME (secs)

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

max Pressure to Break-Seal= 654 psi.

Crude Oil Flow

Self-Healing Cement


Self-Healing Cement

979

894 880

791

357

250

0

200

400

600

800

1000

1200

0 1 2 3 4 5 6 7

Test

Pre

ssu

re (

psi)

Ageing Time (days)

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

Crack

Initiation

Pressure

Break-Seal # 1

Break-Seal # 2

Break-Seal # 3

Break-Seal # 4

Break-Seal # 5


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 Fig # 3: The picture is showing the induced Crack Width of 0.003across 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


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


Questions


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Q & A

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THANK YOU

IDP Feb 2015_Revised

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Transcript of IDP Feb 2015_Revised