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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
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
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
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
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
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
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