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

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TP DEA-139 Phase I DEA Sponsor: Marathon Duration: 2 Years Start Date: May 1, 2000 End Date: April 30, 2002 Participation Fee: $25,000/$35,000

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TP 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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TP Cost of Wellbore Instability Problems $500 million/year, before 1992 G.M. Bol, SPE SPE European Petroleum Conference $92 million, BP 1997 $38 million, BP 1998 first quarter J. Kijowski, BP-Amoco Downhole Talk, Issue 80

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TP Wellbore Stability Problems 8 8High Torque and Drag 8 8Bridging and Fill 8 8Stuck Pipe 8 8Directional Control Problem 8 8Slow Penetration Rates 8 8High Mud Costs 8 8Cementing Failures and High Cost 8 8Difficulty in Running and Interpreting Logs

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TP Wellbore Failure Mechanisms MAURY et al., 1987

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TP Effect of Borehole Pressures

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TP PWPW PWPW max min High Support PressureLow Support Pressure Effect of Mud Support Pressure on Rock Yielding

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TP Rock Failure

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TP Rock Failure Mechanisms PLASTIC BRITTLE

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TP Rock Yielding around Wellbores Laboratory Tests Rawlings et al, 1993 Isotropic StressesAnisotropic Stresses

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TP Change In Near-Wellbore Stresses Caused by Drilling V (overburden) Hmin Hmax Hmin Hmax P w (hydrostatic) Before Drilling In-situ stress state After Drilling Lower stress within wellbore

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TP Stress Concentration around an Open Wellbore PwPw PoPo Hmin Hmax zz rr zz rr r

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TP Strength vs Stress Identifying the Onset of Rock Yielding Shear Stress Shear Strength r´r´ Effective Compressive Stress Stable Stress State q´q´ r´r´ Shear Stress Shear Strength r´r´ Effective Compressive Stress Unstable Stress State q´q´ r´r´ q´q´ Min Stress Max Stress q´q´

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TP Effect of Pore Fluid Saturation

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TP Effective Stresses Partioning of Total Stress between Mineral Grains and Pore Fluids PoPo ´ = - P o ´ - effective stress - total stress P o - pore pressure - Biot Coefficient ( 1 for weak, porous rocks)

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TP Effective Rock Stress z = o - p f o = Overburden Stress z = Matrix Stress p f = Pore Fluid Pressure

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TP Effect of Near-Wellbore Pore Pressure Change on Effective Stresses Shear Stress No Yield Yield Shear Strength Effective Compressive Stress r´r´ ´´ r´r´ ´´ P o increase

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TP

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TP MEI Wellbore Stability Model: (mechanical model, does not include chemical effects) 8Linear elastic model (BP) 8Linear elastic model (Halliburton) 8Elastoplastic Model (Exxon) 8Pressure Dependent Young’s Modulus Model(Elf)

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TP Mathematical Algorithms 8Dr Martin Chenervert(Un. Texas) 8Dr. Fersheed Mody(Baroid) 8Jay Simpson(OGS) 8Dr. Manohar Lal(Amoco) 8Dr. Ching Yew(Un. Texas)

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TP Stress State on Deviated Wellbore zz rr zz zz

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TP

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TP (BP) Linear Elastic Model

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TP

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TP (Halliburton) Linear Elastic Model

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TP

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TP (Exxon) Elastoplastic Model

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TP

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TP

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TP

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TP

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TP (Elf) Pressure Dependent Young’s Modulus

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TP

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TP Shale Borehole Stability Tests Darley, 1969 DIESEL DISTILLED WATER

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TP Montmorillonite Swelling Pressure Powers, ,000 60,000 40,000 20, th3rd2nd1st SWELLING PRESSURE, psi kg/cm 2 LAYERS OF CRYSTALLINE WATER

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TP Shale Water Adsorption Chenevert, WEIGHT % WATER WATER ACTIVITY - a W DESORPTION ADSORPTION

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TP Shale Swelling Tests Chenevert, 1970 TIME - HOURS LINEAR SWELLING - % Activity of Internal Phase

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TP Effect of K+Ions on Shale Swelling Baroid, 1975 Ca++ K+ Na+ Cs+ Na+ Ca++ Li+ K+ Rb+ Cs+ Na+ Mg++ Na+ 10A° Na

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TP Effect of Swelling Strains on Wellbore Stability Soft, Swelling Shale Hole Closure due to Swelling Strains Most Likely Scenario for Soft Reactive Shales in Low Stress Settings

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TP North Sea Speeton Shale Specimen Exposed at Zero DP to Drilling Fluid Drilling Fluid: Ionic Water-Base (CaCl 2 Brine) Activity = 0.78

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TP North Sea Speeton Shale Specimen Exposed at Zero DP to Drilling Fluid Drilling Fluid: Oil-Base Emulsion (Oil with CaCl 2 Brine) Activity = 0.78

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TP 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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TP Principle Mechanisms Driving Flow of Water and Solute Into/Out of Shales Force Flow Fluid (water) Solute (ions) Hydraulic Gradient (P w P o ) Chemical Potential Gradient (A mud A shale ) Hydraulic Diffusion (Darcy´s Law) Advection Diffusion (Fick´s Law) Chemical Osmosis H2OH2O H2OH2O H2OH2O H2OH2O t1t1 t2t2 t3t3 P r Other Driving Forces: Electrical Potential Gradient Temperature Gradient H2OH2OH2OH2O H2OH2OH2OH2O H2OH2O H2OH2O H2OH2O

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TP Osmotic Flow of Water through Ideal Semi-Permeable Membrane Ideal Semipermeable Membrane - permeable to water - impermeable to dissolved molecules or ions Water flow direction High concentration of dissolved molecules or ions ( = Low A w ) Low concentration of dissolved molecules or ions ( = High A w )

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TP Effect of Osmotic Flow on Near-Wellbore Pore Pressure for a Balanced Bottomhole Pressure Condition Osmotic flow from mud to shale Pore Pressure Decrease Osmotic flow from shale to mud r a mud a shale PP r PWPW P fm PWPW P Pore Pressure Increase

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TP Water Acitivity in Salt Solution Salt Concentration, % w/w Water Activity CaCl 2 NaCl KCl Water Activity in Brine at Room Temperature

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TP A Critical Issue: How Efficient Are Shale ²Membranes² ? Laboratory Measurements, Chenevert, 1998 Membrane Efficiency of Speeton Shale when Exposed to Various Water-based Fluids de-ionized water 0.78 a w CaCl a w CaCl a w KCOOH 0.78 a w Glycerol Osmotic Membrane Efficiency

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TP

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TP Limitations of Existing Models 8Do not handle shale hydration 8Very complex 8Input data not available 8Limited field verification 8Cannot field calibrate

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TP Mathematical Algorithms 8Dr Martin Chenervert(Un. Texas) 8Dr. Fersheed Mody(Baroid) 8Jay Simpson(OGS) 8Dr. Manohar Lal(Amoco) 8Dr. Ching Yew(Un. Texas)

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TP Mechanical/Chemical Property Input

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TP Help Information as Clicking Question Mark

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TP Pore Pressure Input/Predict

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TP Pore Pressure Prediction via Interval Transit Time Log Data

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TP In-Situ Stresses Input/Predict

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TP Correlation to Determine Horizontal Stresses

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TP Output Windows

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TP Safe Mud Weight vs Well Inclination

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TP Wellbore Stability Design (through Mud Weight-Inclination diagram)

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TP Safe Mud Weight Distribution by Azimuth

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TP Near-Wellbore Stresses Distribution

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TP Mohr Diagram

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TP Wellbore Stress Distribution

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TP Propagation of Swelling Pressure

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TP Effect of Concentration of Salt in Mud

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TP Effect of Membrane Efficiency

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TP Too large inclination Wellbore Stability Design (continued)

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TP Wellbore Stability Design (continued) Decrease inclination

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TP Wellbore Stability Design (continued) Too high mud weight

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TP Wellbore Stability Design (continued) Decrease mud weight

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TP Not enough salinity Wellbore Stability Design (continued)

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TP Increase salinity Wellbore Stability Design (continued)

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TP Wellbore Stability Design (through Mud Weight-Salinity diagram) Too low mud weight

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TP Wellbore Stability Design (continued) Increase mud weight

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TP Wellbore Stability Design (continued) Not enough salinity

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TP Increase salinity Wellbore Stability Design (continued)

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TP Wellbore Stability Design (continued) Low Value Membrane Efficiency

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TP Wellbore Stability Design (continued) High Value Membrane Efficiency

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TP Field Calibration

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TP Field Calibration (continued)

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TP Effect of Concentration of Salt in Mud

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TP Multi-Depth Data/Calculation Display

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TP Microsoft Word Report

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TP Microsoft PowerPoint Presentation

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TP Project Tasks 8Distribute Wellbore Stability Model (WELLSTAB) 8Develop Enhanced Model (WELLSTAB-PLUS) 8Add time dependent feature to model 8Hold workshops 8Conduct field verification tests 8Write technical reports

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TP Field Verification Goals 8Determine model accuracy 8Improve mathematical algorithms 8Field calibrate model 8Make models more user-friendly 8Convert wellbore stability from an art into a science

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TP Benefits Accelerate Technology Implementation Affordable Software Compound R & D Funds Technical Interchange Unbiased Information Schools and Forums

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