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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