2- Kick signs, indicators, shut in procedures.pptx

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1. Kick Warning Signs

2. What is a kick warning sign? A warning sign tells you: The well may be “Underbalanced” Or There is a decrease in your safety margin.

3. Formation Pressure 9.0ppg Mud Weight 10.0 ppg What is happening? Drilling normally pressured shale Overbalance Warning Signs

4. Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs What is happening? As the formation pressure gets closer to the mud weight, we will observe changes in; ROP Hole condition Gas levels Cuttings properties Mud properties

5. Geolograph Chart Increasing Drill Rate (ROP) 9850’ 9855’ 9860’ 9.00 9.15 9.30 Increased drilling rate Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs

6. BIT Increased drill string torque and drag Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs

7. Cuttings size & shape Drilled cuttings Cavings Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs

8. 8 Normally pressured shale: cuttings are small with rounded edges, generally flat. Abnormally pressured shale: cutting are long and splintery with angular edges. As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom. Change in cutting size and shape Warning Signs

9. Flowline Temperature Normal Pressure Abnormal Pressure Temperature Increase Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs

10. Background & connection gas 5% 10% 15% 1.00 2.00 3.00 4.00 5.00 6.00 Hours 1.00 2.00 3.00 4.00 5.00 6.00 Hours Background Gas Connection Gas Mud Weight 10.0 ppg Formation Pressure 10.0ppg Formation Pressure 9.0ppg Pressure and Porosity Increasing Warning Signs

11. Connection Gas PSI 3000 psi BHP= 7114 psi 11 ppg mud Formation Pressure = 7000 psi 12000’ Annulus Pressure Loss = 250 psi Mud Circulating Formation Under Control

12. Connection Gas BHP= 6864 psi Formation Pressure = 7000 psi 12000’ Circulation Stopped Formation Not Under Control PSI Annulus Pressure Loss = 0 psi 11 ppg mud

13. Connection Gas PSI 3000 psi BHP= 7114 psi Formation Pressure = 7000 psi Annulus Pressure Loss = 250 psi Mud Circulating Formation Under Control

14. Connection Gas PSI 3000 psi BHP= 7114 psi Formation Pressure = 7000 psi Annulus Pressure Loss = 250 psi Actions to take: Increase mud weight. Control drilling. Minimize the connection time .

15. Pressure Losses Where does Pump Pressure value come from??

16. Total Pump Pressure PSI = Surface Line friction PSI = Drillstring friction PSI = Bit (jet nozzle) friction PSI = Annulus friction PSI Total Pump Pressure

17. What Effects Pressure Loss PSI PSI 30 SPM 50 SPM

18. PSI PSI 30 SPM 30 SPM 10 ppg 15 ppg What Effects Pressure Loss

19. PSI PSI 50 SPM 50 SPM Large nozzle Small nozzle What Effects Pressure Loss

20. PSI PSI Hole size What Effects Pressure Loss

21. 30 SPM PSI Annulus pressure loss can be quite small. 50 -300 psi This pressure acts on hole wall and bottom Increases with depth, pump speed, hole size and pipe size. What Effects Pressure Loss

22. Effect on Bottom Hole Pressure 90 SPM PSI If Annulus friction = 150 psi. Mud Weight = 11 ppg TVD = 8700 ft What is the pressure on the bottom of the hole? = (11 x .052 x 8700) + 150 = 5126 psi

23. Kick Indicators

24. Paddle Gauge on Driller’s Console Kick Indicators

25. Kick Indicators Gauge on Driller’s Console Paddle

26. Kick Indicators Formation fluid entering the well will displace fluid out of the hole, resulting in a gain in pit volume Gauge on Driller’s Console

27. Kick Indicators Flow – Pump Off:

28. Trip Tank Trip Tank Pump Normal Drop in Level Trip Tank Level Stands Pulled Drop in Trip Tank Level

29. Kick Indicators What are the indicators that the well is flowing? Increase in Flow Rate Increase in Pit Level Well flows with pump is off What Action Should Be Taken? Shut In the Well.

30. Top Hole Drilling

31. The diverter system includes: Diverter - a low pressure annular preventer used to seal the wellbore from the flowline. Vent lines - large diameter piping used to flow the fluids downwind of the rig (port and starboard). Vent line valves - full opening valves used to select and isolate the desired vent line. Hydraulic control system - functions the diverter and automatically opens the selected vent line valve. Drive Pipe or Conductor casing Vent lines Flowline Bell Nipple Vent line Valves Diverter Large diameter drive or conductor pipe is usually installed below the mud line for spudding in an offshore location and a casing string is set and cemented at shallow depth for land locations. This pipe provides a seal capable of supporting the hydrostatic of the mud column from the base of the casing to the flow nipple outlet. The diverter system is installed on the drive or conductor casing. The working pressure of the diverter and vent lines is not of prime importance, rather they are sized to permit high flow rate diversion of wellbore fluids while minimizing wellbore back pressure.

32. Shallow Gas Blowout in the Gulf of Mexico

33. Problems Shallow gas Can cause loss of rig due to explosion. Weak Formation Losing the hole Might require re-spudding in a slightly different location Charged Formations Top Hole Drilling

34. Shallow Gas Incident

35. Shallow Gas Incident

36. What will happen as the formation is penetrated? Shallow Gas

37. Shallow Gas

38. Top hole kick prevention: Drill pilot hole Be careful when hole opening Control drilling Keep hole clean Keep mud weights low to prevent losses Pump out of hole Shallow gas

39. Shut-In Procedures

40. Lined up with remote choke closed Pick up Shut down pumps Check flow - if flowing: Close BOP Open HCR (hydraulic stack valve) Keep remote chock closed Line-up return flow to trip tank Record Pressure / Pit Gain Hard Shut-In While Drilling

41. Lined up with remote choke open Pick up Shut down pumps Check flow - if flowing; Open HCR Close BOP* Close remote choke Line-up return flow to trip tank Record Pressure / Pit Gain Soft Shut-In While Drilling

42. What is different? String is open Valves and crossover required Safety Valves Full opening safety valve Non return valve Kicks While Tripping

43. Full Opening Safety Valve Kelly cock

44. Non-Return Valve Gray valve IBOP

45. Lined up with remote choke closed Install FOSV Close FOSV Close BOP* Open HCR Line up trip tank & Record pressures Hard Shut-In While Tripping

46. Lined up with remote choke open Install FOSV Close FOSV Open HCR Close BOP* Close remote choke Line up trip tank & Record pressure * API soft shut in for BOP (either Ram or Annular ) Soft Shut-In While Tripping

47. Should only be considered on top hole where formation is weak. 1- Stop drilling (keep pumping) 2- Activate Diverter With One Button- this will: - Open vent line - Close flowline/shaker valve - Close diverter 3. Increase pump speed to maximum 4. Pump mud 5. If well is still flowing after mud is pumped, line up and pump water. Diverting