WELLBORE STABILITY.pdf

Advanced Wellbore Wellbore Stability Model Model (WELLSTAB-PLUS) Dr. William C. Maurer TP00-09

1

DEA-139 Phase I DEA Sponsor: Duration: Start Date: End Date: Participation Fee:

Marathon 2 Years May 1, 2000 April 30, 2002 $25,000/$35,000 $25,000/$35 ,000

Typical Occurrences of Wellbore Instability in Shales

soft, swelling shale brittle-plastic shale brittle shale naturally fractured shale strong rock unit

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

Effect of Borehole Pressures

Effect of Mud Support Pressure on Rock Yielding High Support Pressure max

min

PW

Low Support Pressure max

PW

min

Rock Failure Mechanisms

BRITTLE

PLASTIC

Rock Yielding around Wellbores Laboratory Tests Rawlings et al, 1993

Isotropic Stresses

Anisotropic Stresses

Change In Near-Wellbore Stresses Caused by Drilling Before Drilling In-situ stress state

After Drilling Lower stress within wellbore

sV (overburden)

sHmin

Pw (hydrostatic)

sHmax

sHmin

sHmax

Stress Concentration around an Open Wellbore

z r

r Po

Hmin

z

r

Pw

Hmax

Strength vs Stress Identifying the Onset of Rock Yielding

s s e r t S r a e h Min SStress

sq´ sr´

Stable Stress State

sr´

Max Stress

sq´

Effective Compressive Stress

s s e r t S r a e h S

sq´ sr´

Unstable Stress State sr´

sq´


Effect of Pore Fluid Saturation = z o

= z +p o f

Pf = Fluid Pressure

SOLID ROCK

POROUS ROCK

Effect of Near-Wellbore Pore Pressure Change on Effective Stresses

Yield

s s e r t S r a e h S

No Yield

Po increase r ´

r ´

´


´

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)

Mathematical Algorithms Dr

Martin Chenervert

(Un. Texas)

Dr.

Fersheed Mody

(Baroid)

Jay

Simpson

(OGS)

Dr.

Manohar Lal

(Amoco)

Dr.

Ching Yew

(Un. Texas)

Stress State on Deviated Wellbore s3

s

z

a

b

r

tqz q

sq

s1

tzq s

s2

(BP) Linear Elastic Model

(Halliburton) Linear Elastic Model

(Exxon) Elastoplastic Model

(Elf) Pressure Dependent Young’s Modulus

Shale Borehole Stability Tests Darley, 1969

DISTILLED WATER

DIESEL

Montmorillonite Swelling Pressure Powers, 1967 80,000

5000

i s p , E 60,000 R U S S E R P 40,000 G N I L L E W 20,000 S

4000 2

3000

2000

1000

0 4th

3rd

2nd

LAYERS OF CRYSTALLINE WATER

1st

0

m c / g k

Shale Water Adsorption Chenevert, 1970 5

R E T A W % T H G I E W

4

3

2

DESORPTION

1

ADSORPTION 0 0.10

0.20

0.30

0.40

0.50

0.60

0.70

WATER ACTIVITY - a W

0.80

0.90

1.00

Shale Swelling Tests Chenevert, 1970 0.4

% G 0.3 N I L L E 0.2 W S R A E 0.1 N I L

Activity of Internal Phase 1.00 0.91 0.88 0.84 0.75

0 0.25 -0.1 .01

0.1

1.0

TIME - HOURS

10

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+

North Sea Speeton Shale Specimen Exposed at Zero DP to Drilling Fluid

Drilling Fluid: Ionic Water-Base (CaCl2 Brine) Activity = 0.78


Drilling Fluid: Oil-Base Emulsion (Oil with CaCl2 Brine) Activity = 0.78


Drilling Fluid: Non-Ionic Water-Base (Methyl Glucoside in Fresh Water) Activity = 0.78

Principle Mechanisms Driving Flow of Water and Solute Into/Out of Shales Force Flow Fluid (water)

Hydraulic Gradient (P w

Hydraulic Diffusion (Darcy´s Law)

P t1

Po)

Chemical Potential Gradient (Amud Ashale) Chemical Osmosis

t3 t2

H2O

H2O

r H2O

Solute (ions)

Advection

+

H2O

H2O

H2O

+

-

+

H2O

H2O

-

H2O

-

Diffusion (Fick´s Law)

+

Other Driving Forces: Electrical Potential Gradient Temperature Gradient

H2O

H2O

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 )

Water flow direction

Low concentration of dissolved molecules or ions ( = High Aw )

Limitations of Existing Models Do

not handle shale hydration  Very complex Input data not available Limited field verification Cannot field calibrate

Mathematical Algorithms Dr

Martin Chenervert

(Un. Texas)

Dr.

Fersheed Mody

(Baroid)

Jay

Simpson

(OGS)

Dr.

Manohar Lal

(Amoco)

Dr.

Ching Yew

(Un. Texas)

Mechanical/Chemical Property Input

Help Information as Clicking Question Mark

Pore Pressure Input/Predict

Pore Pressure Prediction via Interval Transit Time Log Data

In-Situ Stresses Input/Predict

Correlation to Determine Horizontal Stresses

Output Windows

Safe Mud Weight vs Well Inclination

Safe Mud Weight Distribution by Azimuth

Near-Wellbore Stresses Distribution

Mohr Diagram

Wellbore Stress Distribution

Propagation of Swelling Pressure

Wellbore Stability Design (continued)

Too large inclination


Decrease inclination


Too high mud weight


Decrease mud weight


Not enough salinity


Increase salinity

Wellbore Stability Design (through Mud Weight-Salinity diagram)

Too low mud weight


Increase mud weight


Not enough salinity


Increase salinity


Low Value Membrane Efficiency


High Value Membrane Efficiency

Field Calibration

Field Calibration (continued)

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

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

WELLBORE STABILITY.pdf

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