Drilling Engineering Association Project Proposal DEA #113 – Phase 2

1. Drilling Engineering AssociationProject ProposalDEA #113 – Phase 2 “Drilling Gumbo Shale – A Study of Environmentally Acceptable Muds to Eliminate Shale Hydration and Related Borehole Problems”

2. Some Aspects of Non-Aqueous Drilling Fluids • Advantages • Can prevent problems caused by hydration of shale, such as drill-string balling and borehole instability. • Can provide excellent filtration control, lubricity and stability at high temperatures. • Disadvantages • Can result in excessive loss of mud because of low fracture extension pressures. • Are subject to stringent environmental regulations, and can result in costly liabilities.

3. Limitations of Commonly Used Laboratory Tests of Shale Hydration • Inadequate procedures such as swelling and dispersion tests utilizing unconfined, unstressed shale. • Use of weathered shale core, cuttings or particles containing air or water vapor in the exposed pore spaces. • Exposure of shale to muds at ambient temperature.

4. Unique Features of the OGS Downhole Simulation Cell • Preserved downhole shale core can be restored to in situ stresses and temperature prior to being drilled with the drilling fluid to be studied. • Artifacts, such as air in shale pore spaces or introduction of an arbitrary simulated pore fluid, can be avoided. • Fluid transfer between drilling fluid and shale can be measured. • Effects of drilling fluid on shale strength and stability can be observed. • Changes in shale composition can be observed.

5. Downhole Simulation Cell System Components

6. Downhole Simulation Cell Cross Section

7. Downhole Simulation Cell

8. Reports of Prior DSC Studies of Pleistocene Shale from the Gulf of Mexico • Gas Research Institute report, “Effects of Drilling Fluid/ Shale Interactions on Shale Hydration and Instability,” GRI 99/0213. • Drilling Engineering Association Project #113 report, “Drilling Gumbo Shale – A Study of Environmentally Acceptable Muds to Eliminate Shale Hydration and Related Borehole Problems.” • Both reports are available from the OGS Laboratory, Inc. website: www.ogslab.com .

9. Differential Pressure • The differential between the borehole pressure and the formation pore pressure is a driving force affecting transfer of fluid from drilling mud to shale. • Raising mud weight can contribute to shale hydration.

10. Chemical Osmosis • Chemical osmosis is a driving force determined by the relative water activities of the drilling mud and the shale pore fluid at downhole conditions. • Water tends to escape from a dilute solution (higher water activity) to a more concentrated solution (lower water activity). • The chemical osmotic force and resulting transfer of fluid is dependent upon the efficiency of the semipermeable membrane at the drilling mud/shale interface in blocking passage of ions and molecules while allowing water molecules to pass.

11. Diffusion Osmosis • Diffusion osmosis is determined by the differences in the concentrations of the individual solutes in the drilling mud and in the shale pore fluid. Ions and molecules of each species tend to move from the high to low concentration. • The flow of solute and associated water is dependent upon the solute selectivity of the drilling mud/shale interface at downhole conditions for each individual solute. • When using a water-based mud, diffusion osmosis opposes chemical osmosis. A lightly compacted shale having large pore throats favors diffusion osmosis, while a more compacted shale favors chemical osmosis.

12. Importance of Drilling Mud / Shale Membrane • Non-aqueous based muds (diesel, mineral, synthetic) can provide an ideal semipermeable membrane that prevents diffusion of ions and molecules, eliminating diffusion osmosis. • Water-based muds do not provide an ideal semi- permeable membrane. Even if chemical osmosis predominates and is extracting water from a shale, diffusion osmosis can cause solutes from water-based mud to invade the shale and create instability.

13. Company Sponsors of DEA #113 – Phase 1 Amoco Prod. Co. Mobil E&P Tech. Arco E&P Tech. National Silicates Baker Hughes Inteq Newpark Drlg. Fluids Baroid Drlg. Fluids Schlumberger Tech. Chevron Pet. Tech. Shell E&P Tech. Exxon Prod. Res. Texaco E&P Tech. Gas Research Ins. Unocal Tech. & Oper. M-I Drlg. Fluids

14. Criteria for Muds to be Tested in DEA #113 • Environmentally suitable for discharge in U.S. waters of the Gulf of Mexico • Mud characteristics such as rheology, filtration control, temperature stability and suspension of weighting material suitable for drilling in the Gulf of Mexico • Mud to contain 20 lb/bbl of ground Pierre shale as simulated drill solids

15. Parameters for DEA #113 DSC Tests of Gulf of Mexico Pleistocene Shale Axial Stress 3,450 psi Confining (Horizontal) Stress 2,650 psi Sandpack (Pore) Pressure 2,000 psi Borehole (Drilling Fluid) Pressure 2,000 or 2,200 psi Shale Temperature 150 °F Drilling Fluid Temperature Drilling 120 °F Circulating 150 °F (Sandpack fluid: Chloride solution having water activity of 0.89 and cations in the same ratios as the cations in the exchange sites of the shale)

16. Fresh-Water Lignosulfonate Water Activity of Drilling Fluid 1.00 Fluid Transfer into Shale, mL/hr 0.85 Relative Shale Stability, psi 1,500 Distance from Borehole Surface 1/8” ½” 1–¼” Initial Shale Moisture, % 29 20 15 12 Shale Hardness 0 0 20 90

17. Fresh-Water Lignosulfonate

18. Potassium / Lime Water Activity of Drilling Fluid 1.00 Fluid Transfer into Shale, mL/hr 1.20 Relative Shale Stability, psi 1,550 Distance from Borehole Surface 1/8” ½” 1–¼” Initial Shale Moisture, % 25 14 14 12 Shale Hardness 30 30 30 90

19. Potassium / Lime

20. Synthetic Water Activity of Drilling Fluid 0.74 Fluid Transfer into Shale, mL/hr -0.40 Relative Shale Stability, psi 2,000 Distance from Borehole Surface 1/8” ½” 1–¼” Initial Shale Moisture, % 16 13 12 11 Shale Hardness 0 55 55 90

21. Synthetic

22. Guidance for DEA #113 – Phase 2 • Only one water-based mud in Phase 1 was successful in extracting fluid from the Gulf of Mexico Pleistocene Shale • Two muds having similar compositions allowed hydration and weakening of the shale • Technical Representatives of Sponsors of Phase 1 identified several mud compositions that warranted further study

23. DEA #113 – Phase 2 • Preserved downhole Pleistocene shale core from the Gulf of Mexico is available for further DSC studies. • Each company participating in Phase 2 can select a mud composition for DSC testing. • Cost of DEA #113 – Phase 2 is $20,000. • Five Sponsors are required to initiate the program and work can begin as early as April, 2002. • Deliverables are comparisons of mud performance under the best laboratory evaluation procedures available to the industry.