Wellbore Stability Design (continued)
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Transcript Wellbore Stability Design (continued)
Advanced Wellbore Stability Model
(WELLSTAB-PLUS)
Dr. William C. Maurer
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DEA-139 Phase I
DEA Sponsor:
Duration:
Start Date:
End Date:
Participation Fee:
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Marathon
2 Years
May 1, 2000
April 30, 2002
$25,000/$35,000
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Typical Occurrences of Wellbore
Instability in Shales
soft, swelling shale
brittle-plastic shale
brittle shale
naturally fractured shale
strong rock unit
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Wellbore Stability Problems
High Torque and Drag
Bridging and Fill
Stuck Pipe
Directional Control Problem
Slow Penetration Rates
High Mud Costs
Cementing Failures and High Cost
Difficulty in Running and
Interpreting Logs
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Effect of Borehole Pressures
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Effect of Mud Support Pressure
on Rock Yielding
High Support Pressure
smin
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Low Support Pressure
smax
smax
PW
PW
smin
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Rock Failure Mechanisms
BRITTLE
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PLASTIC
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Rock Yielding around Wellbores
Laboratory Tests
Rawlings et al, 1993
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Isotropic Stresses
Anisotropic Stresses
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Change In Near-Wellbore Stresses
Caused by Drilling
Before Drilling
In-situ stress state
After Drilling
Lower stress within wellbore
sV (overburden)
sHmin
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Pw (hydrostatic)
sHmax
sHmin
sHmax
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Stress Concentration around
an Open Wellbore
s
sz
sq
sr
r
sz
sr
Po
sHmin
sq
Pw
sHmax
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sq´
s r´
Min
Stress
Stable
Stress State
sr´
Max
Stress
sq´
Effective Compressive Stress
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sq´
Shear Stress
Shear Stress
Strength vs Stress
Identifying the Onset of Rock Yielding
s r´
Unstable
Stress State
s r´
sq´
Effective Compressive Stress
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Effect of Pore Fluid Saturation
so=sz
so=sz+pf
Pf = Fluid Pressure
SOLID ROCK
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POROUS ROCK
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Effect of Near-Wellbore
Pore Pressure Change
on Effective Stresses
Shear Stress
Yield
No Yield
Po increase
s r´
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s r´
s q´
Effective Compressive Stress
s q´
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MEI Wellbore Stability Model:
(mechanical model, does not include chemical effects)
Linear elastic model (BP)
Linear elastic model
(Halliburton)
Elastoplastic Model (Exxon)
Pressure Dependent Young’s
Modulus Model(Elf)
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Mathematical Algorithms
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Dr Martin Chenervert
(Un. Texas)
Dr. Fersheed Mody
(Baroid)
Jay Simpson
(OGS)
Dr. Manohar Lal
(Amoco)
Dr. Ching Yew
(Un. Texas)
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Stress State on Deviated Wellbore
s3
a
sz
b
q
tzq
sr
tqz
s2
sq
s1
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(BP)
Linear Elastic Model
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(Halliburton)
Linear Elastic Model
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(Exxon)
Elastoplastic Model
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(Elf)
Pressure Dependent
Young’s Modulus
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Shale Borehole Stability Tests
Darley, 1969
DISTILLED WATER
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DIESEL
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Montmorillonite Swelling Pressure
Powers, 1967
5000
4000
60,000
3000
40,000
kg/cm2
SWELLING PRESSURE, psi
80,000
2000
20,000
0
4th
1000
3rd
2nd
1st
0
LAYERS OF CRYSTALLINE WATER
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Shale Water Adsorption
Chenevert, 1970
WEIGHT % WATER
5
4
3
2
DESORPTION
1
0
0.10
ADSORPTION
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
WATER ACTIVITY - aW
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Shale Swelling Tests
Chenevert, 1970
LINEAR SWELLING - %
0.4
0.3
Activity of Internal Phase
1.00
0.2
0.91
0.88
0.84
0.75
0.1
0
0.25
-0.1
.01
0.1
1.0
10
TIME - HOURS
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Effect of K+Ions on Shale Swelling
Baroid, 1975
Cs+
K+
Na+
Na+
-
-
K+
10A°
Ca ++
-
K+
Na+
-
-
-
Ca++
Na+
Rb+
-
Cs+
K+
Mg++
Li+
Na+
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North Sea Speeton Shale Specimen
Exposed at Zero DP to Drilling Fluid
Drilling Fluid:
Ionic Water-Base
(CaCl2 Brine)
Activity = 0.78
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North Sea Speeton Shale Specimen
Exposed at Zero DP to Drilling Fluid
Drilling Fluid:
Oil-Base Emulsion
(Oil with CaCl2 Brine)
Activity = 0.78
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North Sea Speeton
Shale Specimen
Exposed at Zero DP to
Drilling Fluid
Drilling Fluid:
Non-Ionic Water-Base
(Methyl Glucoside in
Fresh Water)
Activity = 0.78
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Principle Mechanisms Driving
Flow of Water and Solute
Into/Out of Shales
Force
Flow
Fluid
(water)
Hydraulic Gradient (Pw Po)
Hydraulic
Diffusion
(Darcy´s Law)
P
t1
Chemical Potential
Gradient (Amud Ashale)
Chemical
Osmosis
t3
t2
H2O
H2O
H2O
H2O
r
H2O
Solute
(ions)
Advection
+
H2O
H2O
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H2O
+
-
+
H2O
H2O
-
H2O
Diffusion
(Fick´s Law)
+
Other Driving Forces: Electrical Potential Gradient
Temperature Gradient
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Osmotic Flow of Water through
Ideal Semi-Permeable Membrane
Ideal Semipermeable Membrane
- permeable to water
- impermeable to dissolved
molecules or ions
High concentration
of dissolved molecules
or ions ( = Low Aw )
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Water flow direction
Low concentration
of dissolved molecules
or ions ( = High Aw )
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Limitations of Existing Models
Do not handle shale hydration
Very complex
Input data not available
Limited field verification
Cannot field calibrate
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Mathematical Algorithms
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Dr Martin Chenervert
(Un. Texas)
Dr. Fersheed Mody
(Baroid)
Jay Simpson
(OGS)
Dr. Manohar Lal
(Amoco)
Dr. Ching Yew
(Un. Texas)
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Mechanical/Chemical Property Input
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Help Information as Clicking Question Mark
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Pore Pressure Input/Predict
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Pore Pressure Prediction
via Interval Transit Time Log Data
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In-Situ Stresses Input/Predict
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Correlation to Determine
Horizontal Stresses
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Output Windows
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Safe Mud Weight vs Well Inclination
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Safe Mud Weight Distribution by Azimuth
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Near-Wellbore Stresses Distribution
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Mohr Diagram
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Wellbore Stress Distribution
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Propagation of Swelling Pressure
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Wellbore Stability Design (continued)
Too large inclination
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Wellbore Stability Design (continued)
Decrease inclination
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Wellbore Stability Design (continued)
Too high mud weight
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Wellbore Stability Design (continued)
Decrease mud weight
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Wellbore Stability Design (continued)
Not enough salinity
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Wellbore Stability Design (continued)
Increase salinity
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Wellbore Stability Design
(through Mud Weight-Salinity diagram)
Too low mud weight
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Wellbore Stability Design (continued)
Increase mud weight
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Wellbore Stability Design (continued)
Not enough salinity
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Wellbore Stability Design (continued)
Increase salinity
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Wellbore Stability Design (continued)
Low Value Membrane Efficiency
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Wellbore Stability Design (continued)
High Value Membrane Efficiency
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Field Calibration
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Field Calibration (continued)
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Project Tasks
Distribute Wellbore Stability Model
(WELLSTAB)
Develop Enhanced Model
(WELLSTAB-PLUS)
Add time dependent feature to
model
Hold workshops
Conduct field verification tests
Write technical reports
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Field Verification Goals
Determine model accuracy
Improve mathematical
algorithms
Field calibrate model
Make models more user-friendly
Convert wellbore stability from
an art into a science
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