Cementing Best Practices in Haynesville, Eagleford, and Marcellus Shale Trends

Heath Williams and Roger Keese, SPE, SchlumbergerBased on Papers SPE147330 presented at SPE Annual Technical Conference and Exhibition,

30 October – 2 November, 2011 and CSUG/SPE149440 presented at Canadian Unconventional Resources Conference, 15 – 17 November, 2011.

Agenda for Presentation• Brief Overview of U.S. Shale Market• Challenges with Cementing Horizontal Shale Intervals

– Uncertainty about hole geometry below build section– Different operator perspectives on casing centralization– Drilling fluid properties require “fit-for-purpose” surfactant package– Cement stability hard to maintain at elevated temperature– Longterm isolation challenges

• Interzonal communication• Sustained Casing Pressure (SCP)

• Best Practices for Cementing Horizontal Shale Intervals• Overview of Haynesville practices and field results• Overview of Marcellus practices and field results• Conclusions and Q&A

Overview of US Gas Shale Market

Projected Growth of US Shale Gas Market

Haynesville and Marcellus Shale

Technically Recoverable Shale Gas in U.S. – EIA, 2011

• 750 tcf in lower 48 US States

• 75 tcf from Haynesville

• 410 tcf from Marcellus

750 tcf –U.S.

410 tcf - Marcellus

75 tcf - Haynesville

Horizontal Gas Shale Cementing Challenges

Challenges faced in Haynesville, Eagleford, and Marcellus

Challenge Haynesville Eagleford Marcellus

Mud with elevated Ty (>30 lbf/100ft2)Lack of Centralization

Temperature above 300 degF

Stimulation Pressures above 9,000Substandard Zonal Isolation

Sustained Casing Pressure

Static Gel Strength – Short Transition Time

Challenge Challenge not typically present

Insufficient data collected

Centralization in HaynesvillePrimary Operators in Haynesville

Casing Centralization or Rotation in Haynesville Horizontal Interval

Centralization Rotation

Operator 1

Operator 2

Operator 3

Operator 4

Operator 5

Operator 6

Operator 7

Operators practicing centralization and rotation in Haynesville shale

Challenge Challenge not typically present

Effect of Rotation and Pump Rate on Narrow-Side Annular Velocity

Rotation speed (rpm)

Nar

row

Sid

e Ve

loci

ty (ft

/min

8 bbl/min

10 bbl/min

6 bbl/min

4 bbl/min

2 bbl/min

Limited Carrying Capacity of Polymeric Cement Additives

• Temperatures up to 400 oF• Pressures up to 12,000 psi• Relatively deep, compared with other shale plays

050

100150200250300350400450

0

5

10

15

20

25

30

Temperature (degF)Pressure (kpsi)

Biopolymers (Xanthan gum, etc.)AMPs-based copolymers

• Potential Causes Poor cement placement Initial completions Hydraulic stimulation

Sustained casing pressure (SCP)

Water Aquifer

Results Invasion into aquifer SCP Atmospheric release

Tensile Cracking

Mechanical property analysis with conventional system

Zonal Isolation Challenges with Conventional Cement in Horizontal Shales

Key results• Simulation ramped up to

6,000 psi wellbore pressure

• Passed compression requirements

• Failed tension requirements.

• Passed microannulus requirements

Summary

Compression OK Traction

Failure Microannulus None

Horizontal Shale Cementing Best Practices

Haynesville Cementing Results

Typical Haynesville Production Casing

Typical Well Diagram/Centralizer Placement Program

• Top of Centralization typically around 6,000 ft

• Solid-Body Rigid Centralizers– 1 per 4 joints to Top of Lead– 1 per joint in build section– 1 per 2 joints along horizontal

interval– Centralization is still less than 50%– Other strategies (casing rotation)

are needed

GO/NO GO Test used in Cement Design

Successful Go/No Test Result – No change in BC

Dynamic Settling Test • Highlights of Procedure

– Load slurry in HPHT consistometer cup with modified paddle

– Use ramp-up schedule based on well conditions – Dwell at BHCT for 30 min

– Reduce motor speed down to 25 rpm for 30 min at BHCT

– Cool-down and remove at 190 oF while maintaining in inverted position

– Measure slurry density at top, middle, and bottom of cell

– Cut cone axially along center axis– Measure height of cone at center, mid-point, ends

– record maximum and average height– Acceptance criteria – < 1 ppg difference in density

and 0.5 in. max. cone height.

Dynamic Stability Criteria Based on Cone Height

Cone height>>0.5 in –severe sedimentation with AMPs based copolymer

Cone height~0.5 in –First improvement – results not perfect.

Cone height<0.5 in –System passes and is validated for field placement.

Typical Dynamic Stability Test Result with Polymers above 300 degF

Typical Dynamic Stability Test Result with Haynesville cement system above 300 degF

False DST Result – Sometimes a cone could indicate gelation and NOT sedimentation

0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.090

0.2

0.4

0.6

0.8

1

1.2

1.4Center Cone Height

Dispersant Concentration (gal/sk)

Cent

er C

one

Heig

ht (i

n)

Over-dispersedUnder-dispersed Optimal dispersion

Rheological Hierarchy in HPHT Environment

0

50

100

150

200

250

300

0 50 100 150 200 250 300 350

Dial

Rea

ding

with

R1

-B5-

F1 C

oaxi

al G

eom

etry

RPM

16.0ppg OBM

16.6 ppg Spacer - 1st gen

16.6ppg Spacer 2nd gen

16.8ppg Tail System

Pressure Matching Analysis after Haynesville Production JobsNew cementing approach introduced in Q3 2009

• 400+ jobs since introduction

• 398+ successfully placed

• 2 operational failures – not PSDE-related

• Less scatter in WHP-pressure matching data since introduction

-7000

-6000

-5000

-4000

-3000

-2000

-1000

0

1000

2000

Dec-08 Jul-09 Jan-10 Aug-10 Feb-11 Sep-11

∆P (Max acquired pressure during job - Max simulated pressure) comparison before and after Introduction of PSD-enhanced System in Haynesville Shale

Conventional SystemPSD-Enhanced System

∆P(a

cqui

red

P -

pred

icted

P) in

psi

Haynesville Production Casing Primary Cementing J obs

Before new approach

Pre

ssur

e M

atch

Diff

eren

tial (

psi)

Haynesville Production Cement Jobs

After new approach

Marcellus Cementing Results

Typical Marcellus well program

Challenges to cementing horizontal reach wells

• Drilling fluid selection– Synthetic based mud used in

horizontal interval

• Borehole geometry• Centralization• Mud removal• Cement slurry design

– Rheology– Thickening time– Fluid loss and static gel

strength – Mechanical properties

Marcellus cementing approach tailored to address environmental challenges…

• Flexible, expanding cement system (FECS)• High solids content• Targets multiple casing strings and multiple formations• Key properties

• High solids/low permeability• Mixed continuously or batch-mixed• Acceptable static gel and compressive strength

development• Low Young’s modulus

– To resist fracturing and completion-induced stresses

• Expansion– To close off microannuli

FECS – Testing and design Static gel strength (SGS) development

~30 min transition time meets API Standard 65-2

Transition time<45 min

Maximum fracturing pressure (MWP) before failure

0

1661

3322

4982

6643

8304

Max

imum

Wel

l Pre

ssur

e B

efor

e Te

nsile

Fai

l, ps

i

0 2 3 5 7 9Cement Young Modulus, Mpsi

Max Well Pressure Before Tensile Fail vs. Cement YM

YM

Cem

= Y

M F

orm

atio

n

Marcellus tensile failure does not occur below 6600 psi MWP

Conventional tensile failure occurs below 3000 psi MWP

Compressive and tensile failure envelopes

0

870

1740

2611

3481

4351

5221

6092

6962

7832

8702

Com

pres

sive

Stre

ngth

, psi

0 1Young Modulus, Mpsi

Min Compressive Strengh (500 psi)

CS/YM Failure Curve

Tensile Strength Failure Zone

Compression Failure Zone

Conventional fails in tension

FECS passes

Young’s Modulus vs. Compressive Strength

0

200000

400000

600000

800000

1000000

1200000

1400000

1600000

0 1000 2000 3000 4000 5000 6000 7000 8000

FECS ranging from 13.0 - 15.5 lbm/gal

Non-flexible cement systems ranging from 14.0-16.4 lbm/gal

Compressive Strength (psi)

Youn

g's M

odul

us (p

si)

Favorable YM/CS Mechanical Property Envelope for Optimal Wellbore Integrity

Mechanical property testing results summary

Marcellus cement properties

Density (lbm/gal)

13.0 14.0 14.5 15.0

Temp (degF) 150 200 150 150

Compressive Strength (kpsi)

1.93 2.78 1.52 2.12

Young’s Modulus (kpsi)

450 550 650 740

Poisson’s Ratio

0.23 0.16 0.16 O.16

FECS – Linear expansion dependence at 150 oF

0 2 4 6 8 10 12 14 16 18-0.2

-1.66533453693773E-16

0.2

0.4

0.6

0.8

1

1.213.0 lbm/gal with 2% BWOB expanding agent14.0 lbm/gal with 2% BWOB expanding agent

Curing Time (days)

% L

inea

r Exp

ansio

n Best expansion

• Good cement bonding noticed after placement

FECS – Placement evaluation

Top of cement

Monitoring of SCP after stimulation

• Stimulation maximum working pressure (MWP)– 9,000 psi MWP

• Marcellus well performance after well stimulation with FECS– 40+ strings stimulated since introduction of FECS in 2011– No SCP observed

Conclusions and Way Forward for Haynesville, Eagleford, and Marcellus Shales

• Haynesville and Eagleford shales - More stable, non-polymeric cementing approach introduced – More stability than AMPs-based polymer-stabilized systems– Very stable at 300+ degF in dynamic stability testing

• Marcellus shale – Predicted conventional failure limit ~ 3,000 psi– No SCP with FECS-cemented wells stimulated at ~9,000 psi– Well stimulation in 30+ wells with FECS– No SCP observed after 6+ months

Haynesville and Marcellus shale strategies being introduced into other shale plays

Questions or Comments?