Technology Transfer Stuck Pipe

1. Technology TransferStuck Pipe Craig S. Clark IPM NSA QHSE Manager Schlumberger

2. 12 11 1 10 2 3 9 4 8 5 7 6 Technology TransferStuck Pipe Prevention & Cure

3. 12 11 1 10 2 3 9 4 8 5 7 6 Handover $250 - $500 million is spent on stuck pipe each year! BP Research found that 60 – 70% of stuck pipe events occur within 2 hours of a shift change. Another second “window of vulnerability” exists at the 3 and 9 hour breaks.

4. Who is Responsible? We all are!! A consolidated, integrated Schlumberger Oilfield Services group applying technology and expertise creating synergy, precise communications and excellence in delivery of services Proper planning, good drilling practices and an effective mud system all help to ensure that the hole is in the best possible condition BUT PROBLEMS DO OCCUR There is only one person who can proactively manage the problem from becoming a STUCK PIPE event The IPM Well Site Supervisor

5. Causes of Stuck Pipe • Differential sticking • Mechanical sticking

6. Differential Causes of Stuck Pipe • High Differential Pressure • Permeable Formations • Thick Filter Cake

7. Differential Sticking #1 Mud Cake Borehole Wall • Permeable formations adjacent to BHA • High differential pressure (>1500 psi) • Thick mud cake (high water loss/high solids content) • Large contact area (drill collar O.D., wellbore diameter) Mud pressure Contact area Formation Pressure

8. Differential Sticking #2 The magnitude of differential pressure sticking is enormous Overpull = (mud pressure – formation pressure) x contact area x friction factor Where: Overpull – (lbs), mud pressure – (psi), formation pressure – (psi), contact area – (sq. in.), friction factor – (no unit) Example: Overbalance = 1500 psi, contact area = 5 inches, Sand thickness = 30 ft., friction factor = 0.3 Overpull = 1500 psi x 30 ft. x 12 in./ft. x 5 in. x 0.3 = 810,000 lbs. = 810 klbs

9. Differential Sticking #3 Formation of a Bridge Over Time • High torque/overpull when BHA is held motionless • Situation gets worse with time • Contact area increases • Water seeps out of mud cake, friction factor increases Mud Cake Bridging Mud pressure Contact area Formation Pressure

10. Differential Sticking #4 Filter Cake Buildup Rate of buildup depends on • Differential pressure • Mud filtrate/solids content • The thickness of the filter cake Permeable Formation Filter Cake Filter Cake Mud Pressure Formation Pressure Filtrate Filtrate

11. Differential Sticking #5 The effect of drill solids on filter cake thickness High Mud Solids Cause • More permeability in cake • More contact area for differential sticking • Faster rate of cake growth High Drill Solids Mud Pressure Low Drill Solids Mud Pressure Pore Pressure Permeable Formation Pore Pressure Permeable Formation Mud Solids Drill Solids

12. Differential Sticking #6 Filter Cake Erosion It is sometimes possible to avoid differential sticking by • Control of mud solids/filtrate (OBM or polymer muds) • Not giving the filter cake enough time to build • Frequent wiper trips • Rotate at connections Drill Pipe Erosion Wiper Trip Reaming

13. Differential Sticking #7 Filter Cake Buildup Filter cake increases between wiper trips until differential sticking occurs Time in open hole (hours) 0 5 10 15 20 25 30 35 40 45 50 55 4000 5000 6000 7000 8000 9000 6 hrs 12 hrs 12 hrs 12 hrs Casing Shoe Sand pore pressure = 9 ppg Wiper trip #2 Mw=11 ppg WL=5 ml Overpull = 60 Klbs Depth (ft.) Wiper trip #4 Mw = 13 ppg WL = 10 ml Overpull = 200 klbs STUCK Wiper trip #1 Mw = 11 ppg WL = 5 ml Overpull = 40 Klbs Wiper trip #3 Mw = 11 ppg WL = 10 ml Overpull = 100 Klbs

14. Differential Sticking #8 Setting casing to minimize differential pressure across a sand Casing option 1: Set casing at 12,900 ft. Differential pressure at Sand = 6 ppg Casing option 2: Set casing at 10,200 ft. Differential pressure at Sand = 2.1 ppg Mud weight equivalent (ppg) 8 9 10 11 12 13 14 15 16 17 18 19 20 0 2000 4000 6000 8000 10000 12000 14000 16000 Surface casing Csg option 1 Csg option 2 Pore Pressure Sand pore pressure = 9 ppg True vertical depth Fracture gradient

15. Mechanical Causes of Stuck Pipe • Inadequate hole cleaning • Chemically active formations • Mechanical stability • Overpressured formations • High dip sloughing • Unconsolidated formations • Mobile formations • Under-gauge holes • Key seating

16. Zone 2 Zone 1 Zone 4 Zone 3 Increasing annular velocity Zone 5 0 30 60 90 Well inclination (degrees) Hole Cleaning #1 Cuttings flow patterns in deviated wells (from BP research) • Cuttings beds start forming at angles above 30° • Hole angles between 50 ° and 60 ° are hardest to clean Zone 1 - Efficient hole cleaning Zone 2 - Good hole cleaning with moving cuttings beds Zone 3 - Slow removal of cuttings Zone 4 - Some hole cleaning, cuttings bed formed Zone 5 - No hole cleaning (see Hole Cleaning presentation)

17. Hole Cleaning #2 Cuttings around BHA increase overpull • Excessive overpull at connections and trips • Reduced overpull when pumping • Long periods of no cuttings followed by burst of cuttings • Pump pressure spikes as hole momentarily bridges Cuttings bed On low side of hole Cuttings accumulate Above bit and stabilizers When pulling up

18. Stabilizer redrills cuttings Hole Cleaning #3 Effects of poor hole cleaning while cleaning • Reduced weight/torque transmission at end of joint • Weight/torque transmission improves after a connection • Insufficient cuttings on shakers for ROP (judgement) • Erratic and increasing torque while drilling

19. Hole Cleaning #4 Other Warning Signs • High ROP/large hole size/low annular velocities • Pump pressure increases • Presence of washouts in openhole • Stabilizers and bit packed off with cuttings

20. 2700 2600 2500 Pulses Standpipe Pressure (psi) Spikes 12:30 13:00 13:30 14:00 Time Pressure & Torque Pressure pulses and torque spikes are warning indicators of inadequate hole cleaning 30 20 10 0 Torque (klb/ft)

21. Hookload & Torque Hookload and torque are warning indicators of increasing hole friction 400 300 200 100 Pick-up Reciprocate string Hookload (klb) Slack-off 30 20 10 0 On Bottom Excessive Torque Torque (klb/ft) Off Bottom 10 12.5 15 17.5 20 Minutes after 14:00 hrs.

22. Hookload & Elevator Position This and the previous two MDS* figures are a good example of a mechanical sticking event due to inadequate hole cleaning 400 300 200 100 Sticking Stuck Hookload (klb) 30 20 10 0 -10 Elevator Position (m) String stretch 0 5 10 15 20 25 30 35 Time (mins)

23. Chemically Active Formations Swelling shale will slough into the hole and will tend to pack off BHA Clay balls Water from mud absorbed by formation Mud Rings Sloughed shale packs-off BHA • Large clumps of Gumbo coming out of the hole • BHA packed off with Gumbo • ROP will tend to decrease as less weight gets to the bit

24. Mechanical Stability #1 Insufficient mud weight to keep the hole from contracting • Rock may not support extra stress • Borehole contracts slightly • Large pieces of rock break off • Hole fill after trips • Hole cleaning problems Side Stress Side Stress Side Stress Mud Weight Side Stress

25. Mechanical Stability #2 Overburden stress orientation in vertical and horizontal wells Vertical Well Horizontal Well Overburden Stress Overburden Stress

26. Comparison of Stresses Stresses on a typical wellbore cross section for a vertical and a horizontal well Vertical Well Horizontal Well Side stress (0.75 psi/ft) Overburden Stress (1.0 psi/ft) Side stress (0.75 psi/ft) Mud weight (0.465 psi/ft) Mud weight (0.465 psi/ft) Side stress (0.75 psi/ft) Side stress (0.75 psi/ft) Overburden Stress (1.0 psi/ft) Side stress (0.75 psi/ft)

27. 0 max psi 0 max psi Overpressured Formations Rock pore pressure > mud hydrostatic = heaving shale 0 max psi Fault Warning signs Remedies • Large brittle concave – shaped cavings • Hole fill after trips • Underbalanced condition • Recently crossed a fault • Drilling long section without permeable formations • Unusually high ROP for strength of shale • Maintain 200 psi overbalance at bit • Clean the hole • Correlate, watch the faults • Check flow at drilling rates

28. High Dip Sloughing #1 Comparison of a high and low dip with regard to hole sloughing Horizontal Dip Highly Inclined Dip • Hole fill after trips • Large, flat cuttings • Proximity to a salt dome • Known high dip/fractured area Weakest Fracture Direction For clay platelets Weakest Fracture Direction For clay platelets Mud flow Gravity

29. Unconsolidated Formation Unconsolidated Formations Can collapse into the wellbore forming a bridge • Warning Signs • Unconsolidated, uncemented sands at shaker • Increase in pump pressure due to bridging or packing – off • Torque will be erratic but may improve with circulation • Inadequate hole cleaning symptoms • Downward pipe movement may be affected due to hole fill • Shaker screens will tend to blind • Remedies • Follow hole cleaning procedures • Drill a few feet, circulate and check drag

30. Salt Formation Mobile Formations Flow into Wellbore • Warning Signs • Drilling break • Drastic increase in mud chlorides • Salt in cuttings sample • Pump pressure increase as annulus is blocked • Often a time delay before formations flow • Remedies • Salt saturated or oil based mud • Eccentric PDC bit – overgauge hole • Increase mud weight • Drill a few feet, circulate and evaluate drag

31. Abrasive/Undergauge Hole Flow into Wellbore • Warning Signs • Undergauge bit and stabilizers • Abrasive formation • Tight hole on trip in • Low ROP due to weight not getting to the bit • Directional control difficult • Remedies • Trip in slowly • Ream to bottom • Run roller reamer above bit Abrasive formation

32. Doglegs – BHA Design A stiff BHA creates the appearance of tight hole and can lead to sticking. A flexible assembly can snake around doglegs.

33. Formation of a key seat • Warning Signs • Large doglegs at shallow TVD compared to TD • Sticking will occur while tripping out • Overpull erratic as tool joints pass through key seat • Remedies • Open hole/ream doglegs • Run key seat wiper • Avoid aggressive assemblies at shallow depths 1 2 3 Section A-A • Rotating pipe creates groove • Groove deepens see section A-A • BHA can become wedged in grooves Key Seating

34. Proactive vs. Reactive The project team has to be proactive Proactive – being prepared for future events Reactive – being controlled by past events The proactive drilling team is prepared for trouble spots and communicates The reactive drilling team responds professionally without hesitation

35. 12 11 1 10 2 3 9 4 8 5 7 6 Handover $250 - $500 million is spent on stuck pipe each year! BP Research found that 60 – 70% of stuck pipe events occur within 2 hours of a shift change. Another second “window of vulnerability” exists at the 3 and 9 hour breaks.

36. Synergy and Integration Synergy = the combined effect of working together Integration = to combine separate parts into a complete whole Future Contractor Prime contractor Expanded workscope Utilizing subcontractors Integration Many contractors Limited specialized workscopes Footage/Turnkey Products Performance/Quality Bonus/Malus Dayrate Service Today Operator Return to Core Business Supervise Coordinate Many Specialists Manage fewer Contractors for Quality assurance The stuck pipe problem is most effectively confronted through synergy and integration

37. Hookload While Tripping Overpull Pull out of hole baseline Up drag Surface Weight Off-bottom Rotating baseline Down drag Run in hole baseline Set down

38. Overpull at Connection Increasing overpull at connections results in stuck pipe 300 250 200 150 100 50 0 Hookload while Pulling up at conection (Klbs) STUCK Total Hookload Overpull at connections 1200 1300 1400 1500 1600 1700 Depth (ft.)

39. Trends – Hookload, Pressure and Torque Monitoring trends is a key element for stuck pipe prevention 1400 POOH 1300 RIH kN 1200 1100 Hookload 1000 7 8 9 10 11 12 13 14 15 Time (hrs) 2700 Standpipe pressure psi 2500 50 Torque kN.m 0 7.0 7.5 8.0 13.0 13.5 14.0

40. Freeing Stuck Pipe Fast reactions required • Move pipe in opposite direction prior to becoming stuck. • Jar in opposite direction as soon as possible. • Work drill string to the limits. These limits should be posted on the floor. • If differential sticking is suspected then work in right hand torque and slump the pipe. If bit is on bottom continue working the pipe by pulling up and jarring. • Have the chemicals and mud pits ready to make up a pill.

41. Freeing Stuck Pipe Questions we need to ask: • Is there a potential well control problem? • What was the operation when the pipe became stuck? • What does the Geolograph or the Mudlogger show? • Have there been any recent changes to the mud properties? • What has been the history of the hole? • Where has the pipe become stuck?

42. Freeing Stuck Pipe Guide to Sticking Causes Lithology Gamma Specific Indicators Probable cause of sticking • Large differential pressure • Not enough cuttings on shakers • Individual sand grains • Differential pressure sticking • Inadequate hole cleaning • Unconsolidated formations Reservoir • Not enough cuttings on shakers • Brittle concave cuttings, high gas background • Large clumps of gumbo cuttings dissolve into water • Inadequate hole cleaning • Overpressued formation • Chemically active formation • Mechanical stability Shale • Mobile formation Salt • Abrasive formation tripping in • BHA at dogleg tripping out • Undergauge hole • Key seating Any Formation

43. Yes Yes Yes Yes Yes Yes No No No No No No No No No Elf Flowchart Work drillingstring; jar up and down Spot surfactant Free string? Reduce hydrostatic pressure by circulating light mud or water with blowout preventer closed to maintain well control Risk of flowing well Free string? Decrease hydrostatic pressure Reduce hydrostatic pressure by bleeding off drill pipe Free string? Free string? Backoff Jarring Free string? DST Free string? Washover Free string? Sidetrack

44. Pipe free? Pipe free? Pipe free? Diesel base pill justified (almost always when TF45) Fishing justified Texaco Decision Flowchart Pipe sticks Attempt to work pipe and jar for up to 3 hours Continue operations Determine TR, calculate RFC using ps Area-Specific Information available To change decision? Spot diesel base pill as soon as possible Soak for ESTL – 30 hours in straight hole, 24 hours in directional Continue operations Calculate RFC for fishing operations using TFK45 Ps=0.037 46-65 Ps=0.250 >65 Ps=0.833 Area – specific Information available To change decision? Back off and make one attempt To free pipe with fishing jams Continue operations Plug and abandon, plug back or sidetrack

45. 12 11 1 10 2 3 9 4 8 5 7 6 Good Communications are Free