2003 SPE/IADC Drilling Conference

1. 2003 SPE/IADC Drilling Conference SPE/IADC 79880 Well Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling February 21, 2003

2. 21.1 Well Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling Dr. Jerome J. Schubert Dr. Hans C. Juvkam-Wold Texas A&M University and Dr. Jonggeun Choe Seoul National University

3. Overview • Introduction to Dual Gradient Drilling • Goal of the SMD Well Control Team • Comparison of Well Control for DGD and Conventional Riser Drilling • Conclusions

4. What is Dual Gradient Drilling? • Novel drilling system where the annulus pressure at the seafloor is reduced to near seawater HSP. • Results in a pressure gradient from the rig to the seafloor near that of seawater HSP, and mud gradient from the seafloor to the bottom of the hole

5. Dual Gradient Concept

6. How is the dual gradient achieved? • Seafloor pumps and an external return line • Shell • DeepVision • SubSea MudLift Drilling • Injecting hollow glass spheres near the seafloor • Maurer Technology

7. Goal of the SMD Well Control Team • Develop Well Control Procedures for the SMD JIP that were at least as safe if not safer than conventional floating drilling operations. • The authors feel that these procedures are applicable for most DGD methods.

8. How was the goal met? • We had to study the state of the art in conventional deepwater drilling • Determine what had to be modified or re-written for the SMD project. • New procedures were written and re-written as the project progressed.

9. How was the goal met? • Perform risk analysis in the form of HAZOP • Modify or re-write procedures based on HAZOP • If the procedure was re-written, a new HAZOP had to be performed

10. How was the goal met? • Finally, most of these well control procedures were proven on a DGD test well.

11. Measurement of KCP • KCP is measured identically for DGD and Conventional • No DSV – rate must be greater than the freefall rate of the mud • W/DSV – must also measure the DSV opening pressure

12. Kick Detection • Kick indicators • Drilling break • Flow increase • Pit gain • Decrease in circulating pressure • Increase in pump speed • Well flow with pumps off • Increase in torque, drag, fill

13. Kick Begins MLP Increase MLP Inlet P Constant DPP Decrease Flow Increase

14. Normal U-tube U-tube + kick Well Flow w/ Pumps Off • No DSV • U-tube makes this much more difficult • Trend analysis is needed 700 gpm 600 500 400 tube Rate, 300 200 - 100 U 0 0 5 10 15 20 25 Time, min

15. Well Flow w/ Pumps Off • With DSV • Shut down Rig Pumps • Continued operation of the Sea Floor Pump will indicate well flow.

16. Pit Gain • W/DSV there is no difference • No DSV – No difference in kick detection. However pit gain after shut-in is equal to the pit gain after complete u-tube less the theoretical u-tube volume.

17. Shut-in on kick • With DSV, SI is very similar to conventional • Shut down rig pumps, • Check for flow • If flowing, shut down MLP • Close BOP • With No DSV, preventing additional influx is difficult during u-tube.

18. Kick Detected Slow MLP Rig Pumps Constant MLP inlet P & DPP Increase Shut-In on Kick

19. Shut-in Procedures • After the MLP and Rig pumps are returned to the pre-kick rates: • Allow the DPP and MLP Inlet P to stabilize • Record stabilized pressures and rates • Continue to circulate at constant Rig Pump Rate and Pressure until kick fluids are circulated out. • DPP is maintained by adjusting MLP Rate

20. SIDPP SIDPP is somewhat different. • W/DSV very similar to measurement of SIDPP with a float and is the • Post kick DSV opening pressure less the Pre kick DSV opening pressure.

21. Upon kick detection, slow MLP to pre-kick rate Record the Stabilized DPP SIDPP – No DSV

22. Calculation of KWM • Conventional • Dual Gradient

23. DPP Pressure Decline Schedule • Calculating ICP is no different • FCP Conventional • FCP=KCP x KWM / OWM

24. FCP DGD

25. Driller’s Kill & Wait & Weight • Essentially the same for DGD and Conventional except for the differences noted earlier in measurement of SIDPP and shut-in. • MLP is used as the adjustable choke

26. Other Kills • Volumetric • Lubrication • Stripping • Procedure have been developed but are not included in this paper.

27. Conclusions • The u-tubing that is expected in DGD causes some difficulties in many aspects of well control – none of them are show stoppers • The use of a DSV eliminates the problems associated with the u-tube phenomenon, but creates some of it’s own

28. Conclusions • The complications from the DSV are outweighed by the benefits • DSV makes well control seem more conventional, but it is not absolutely necessary.

29. Conclusions • Well control for DGD has been developed to a point where it is at least as safe if not safer than conventional riser drilling. • A well control training program for DGD will be essential for safe and efficient operations.

30. IADC/SPE 79880 The End

31. DGD with Seafloor Pumps

32. Recent Advances in Ultra-deepwater Drilling Calls for New Blowout Intervention Methods Speaker:Ray Tommy OskarsenCo-authors:Jerome Schubert Serguei Jourine

33. Sponsors and Participants • Phase 1 • Texas A&M University • Cherokee Offshore Engineering • Global Petroleum Research Institute • Offshore Technology Research Center • Minerals Management Service

34. Drilling in ultra-deep water • Window between pore pressure and fracture pressure gets narrower • High pore pressures and low fracture pressures lead to more casing strings • More casing strings leads to more time spent on location • This leads to larger wellheads, even larger and heavier risers, and finally to bigger and more expensive rigs • With a standard BOP and many casing strings, you may not reach target. • Well control is more difficult - because of the pore pressure / fracture pressure proximity, and long choke lines with high frictional pressure drops

35. Deepwater drilling projects • Dual Gradient Drilling • Casing Drilling • Expandable Casing • SX-riser

36. Blowout Containment Procedures? • The most recent blowout containment procedures can be found in the “DEA – 63, Floating Vessel Blowout Control,” which was released September 1990. • DEA - 63 considered deep water up to 1500’ • Envisioned “future work” in water as deep as 3500’

37. DEA-63 Cont. • Focus on capping measures • No Dual Gradient Drilling • Concluded with recommendations for more work Are We Ready?

38. Safety Pyramid Fatality 1 29 LTA 300 OSHA Recordable 3000 At-Risk Behaviors Albert H. Schultz - DuPont

39. Statistics • Podio Study of OCS Blowouts, 1996 • 1 Blowout for every 285 wells drilled • 2.7% of the wells studied deeper than 15,000 ft • These accounted for 8% of the blowouts • Wylie and Visram, 1990 • 1 Blowout for every 110 kicks • SINTEFF Deep Water, 2001 • 52 kicks for every 100 wells drilled • 79% of kicks had significant problems • At least 21% of kicks resulted in loss of all or part of the well • 1992 to 2001 we drilled 1015 wells in water >1500 feet deep

40. Blowout Pyramid 1 Blowout 20 Well Bore Losses 80 Significant Well Control Problems 110 Kicks ? At Risk Operations 200+ Wells Drilled

41. Are wells in deep water likely to occur more frequent? • Higher pore pressure gradients • Difficulties in handling highly compressed gas • Increased exposure time • Longer open hole sections • More tripping time • Increased risk of lost circulation Odds are not in our favor!

42. Deep Water Blowouts Proposed practical solutions: • capping, • injecting solidified reactive fluids, • dynamic kill/momentum kill, • inducing bridging

43. 11 7% 15% 4% 9 9 10% 5 14% 19 36% 39 % 14% 5 3 0-1 hour 1 hour-1 day Bridging BOP 1-3 days Cement Depletion 3 days-1 week Equipment Mud 1 week- 1 month Relief Well Missed > 1 month Missed Fastest and Least Expensive Mode of Control Duration FOR MORE INFO... SPE 53974, IADC/SPE 19917, http://www.boots-coots-iwc.com /references/ 02_Ultra-deepwater %20blowouts.htm

44. Bridging Scenarios

45. 1. Wellbore and Reservoir Performance Relationships 2. Stress and Pressure Distributions 3. Stress-Strength Relationships Flow and Geomechanics Models 1 3 2 1. Well is out of Control

46. 3. Stress-Strength Relationships 4. Solid Production Potential Wellbore Stability Model 4 Unstable 3 Moderate Stable 2. Wellbore Instability

47. 4 Massive Solid Production 5 4. Solid Production Potential 5. Actual Solid Production Solid Production Model Negligible Solid Production Stable Fluid Flow Blowout 3. Solid Production Concentration Time, sec Distance, m

48. Wellbore Bridging Total Wellbore Collapse Massive Solid Production 6 5 5. Actual Solid Production 6. Outflow Performance with Actual Solid Load Negligible Solid Production Flow and Geomechanics Models 4a. Wellbore Collapse

49. 6 7 6. Outflow Performance with Actual Solid Load 7. Bridge and Formation Stability Flow and Geomechanics Models Stable Fluid-Solid Flow Blowout 4b. Bridge Formation Bridge

50. Wellbore Bridging 7 7. Bridge and Formation Stability Flow and Geomechanics Models Formation Failure Bridge Failure Underground Blowout Blowout 5. Bridge Stability