MANAGED PRESSURE DRILLING PRESENTATION

MANAGED PRESSURE DRILLING

1. Oil & Natural Gas Corporation Ltd. Institute of Drilling Technology MANAGED PRESSURE DRILLING (MPD)

2. Presentation overview 2 1 2 Introduction 3 Definition of MPD 4 Categories of MPD 5 Advantages of MPD 6 MPD Techniques 7 MPD Equipments MPD Applications 8 9 Feasibility of MPD in ONGC

3. INTRODUCTION In the most of the drilling operations a considerable amount of money is spent for drilling related problems; including stuck pipe, lost circulation zones, wellbore instability, over pressured formations and excessive mud cost. Managed pressure drilling (MPD) is a new technology that enables a driller to more precisely control annular pressures in the wellbore to prevent these drilling related problems. By solving these problems, drilling cost will fall, therefore enabling the industry to be able to drill wells that were previously uneconomical. 3

4. By applying MPD techniques, it is possible to drill through narrow window formations where pore pressure and fracture pressure is close. The primary difference between conventional drilling and MPD is that in general MPD relies upon a closed circulating system whereby flow and pressure in the wellbore can be controlled. Managed Pressure Drilling uses tools similar to those of underbalanced drilling to better control pressure variations while drilling a well. 4

5. Conventional Drilling In dynamic condition, when the mud pumps are circulating the hole, BHP is a function of hydrostatic mud pressure(MW HH ) and annular friction pressure (AFP). In the static condition(no circulation) bottomhole pressure(BHP) is a function of hydrostatic column’s pressure. BHP control = only pump speed & MW change. The stopping and starting of pumps during pipe connections creates pressure fluctuations in the wellbore which can cause problems when drilling in narrow margins between pore pressure and fracture pressure. 5

6. MANAGED PRESSURE DRILLING Definition An adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly . It is the intention of MPD to avoid continuous influx of formation fluids to surface. MPD does not change the downhole pressure window – pore pressure and fracture gradient remain unchanged. 6

7. In Managed Pressure Drilling In addition to mud weight and annulus friction pressure, backpressure (BP) is applied from surface to maintain the overbalance in the well. BHP DYN = MW HH + AFP + BP The amount of backpressure while circulating is usually close to zero or relatively low. In static conditions, like when the pumps are shut off for connections, more backpressure is applied from surface to account for the loss of AFP. BHP STAT = MW HH + BP This is very beneficial in narrow operating margins where the slightest pressure variation can induce an influx or fracture the formation. By keeping the BHP slightly overbalanced, or as near as balanced as possible, the driller can safely drill through narrow operating windows without having to set the casing prematurely. 7

8. REASON FOR NARROW DRILLING WINDOW Typically in deepwater prospects, pore pressures are abnormally high at relatively shallow depths below the sea floor due to rapid sedimentation and lack of compaction. On the other hand, the fracture pressures are typically low because of less overburden owing to large column of water instead of denser sediments. This results in a narrow window between the pore pressure and the fracture pressure. In such cases, it is standard practice to set numerous casing strings to avoid extensive lost circulation. With the help of the variations of MPD, it is possible to solve such problems by controlling the BHP. 8

9. To alleviate drilling hazards and increase drilling operations efficiencies by reducing nonproductive time (NPT) are the principal objectives of Managed Pressure Drilling. The operational drilling problems mostly related with non-productive time include: Lost Circulation Stuck Pipe Wellbore Instability Well Control Incidents 9

10. CATEGORIES OF MPD Reactive MPD The well is designed for conventional drilling, but equipment like RCD, choke and float valves is rigged up to quickly react to unexpected pressure changes. Proactive MPD The drilling program is designed from the beginning with a casing, fluids, and open hole drilling plan and/or alternate plans that take full advantage of the ability to more precisely manage the wellbore pressure profile. proactive MPD drills: operationally challenged wells economically challenged wells “ undrillable ” wells 10

11. MPD SURFACE LAYOUT 11

12. WORKING OF MPD The RCD acts as a primary pressure seal and is mounted on the wellhead, above the annular blowout preventer. The RCD diverts the pressurized mud returns from the annulus to the choke manifold. If the pressure starts to climb above the fracture pressure of the formation, the driller can open the choke to reduce backpressure and bring the pressure down. If the driller needs to increase the pressure throughout the well, closing the choke will increase backpressure When the pumps are turned off, the choke is closed to apply backpressure to replace the lost AFP. As the pumps are turned on and the AFP increases, the choke can be opened to decrease backpressure 12

13. This helps keep pressure profile to remain inside the pressure window throughout the well. By adjusting the mud weight and using backpressure, a driller would be able to keep the pressure inside the pressure window. Applying back pressure while not circulating could keep the pressure above the pore pressure of the formation. The fluid returning through the manifold can go straight to the shale shakers or, if the gas ratio becomes higher than a predetermined limit, the returns can be diverted to the mud gas separator. 13

14. ADVANTAGES OF MPD The primary advantage of Managed Pressure Drilling is to reduce drilling costs by reducing NPT while increasing safety with specialized techniques and surface equipments. Deepwater Drilling. Extending casing points to limit total number of casing strings. Avoiding the Lost Circulation. Avoiding well kick sequence. Limiting The NPT Associated With Differentially Stuck Pipe 14

15. MPD TECHNIQUES Constant Bottom Hole Pressure (CBHP) Friction Management Method Continuous Circulation Method Mud Cap Drilling (MCD) Pressurized Mud Cap Drilling (PMCD) Controlled Mud Cap Drilling (CMCD) Dual Gradient Drilling (DGD) Annulus Injection Method Riserless Dual Gradient Method Return Flow Control (RFC) or HSE Method 15

16. (1) CONSTANT BOTTOM HOLE PRESSURE(CBHP ) 16

17. The fluctuations in bottomhole pressure are caused by stopping and starting of circulation for drillstring connections and they result from a change in equivalent circulating density (ECD) or annulus friction pressure (AFP), which occurs when the pumps are turned on and off. CBHP method is distinctively applicable to drilling in narrow or relatively unknown margins between the pore and fracture gradients. When shut in to make jointed pipe connections, surface backpressure (BP) contributes to the HH pressure to maintain a desired degree of overbalance, preventing an influx of reservoir fluids. 17

18. 18 This can be done by gradually reducing pump speed while simultaneously closing a surface choke to increase surface annular pressure until the rig pumps are completely stopped and surface pressure on the annulus is such that the formation “sees” the exact same pressure it saw from ECD while circulating.

19. 1.1 Friction Management Friction management techniques are used in HPHT or in Extended Reach wells, where the annular pressure is maintained to keep the BHP as constant as possible. In ERD wells, the annular pressure loss often needs to be reduced to achieve the required length and reach of the well. This can now be achieved through the use of an annular pump. The pump is placed in the cased section of the well and pumps annular fluid back to surface thus reducing the annular friction pressures. 19

20. 1.2 Continuous circulation system The continuous circulation system (CCS) is a new technology that enables a driller to make connections without stopping fluid circulation. A CCS enables a driller to maintain a constant ECD by not interrupting circulation during drilling operations. This method is used on wells where the annular friction pressure needs to be constant and/or to prevent cuttings settling in extended reach horizontal sections of the wellbore. When the pump stop, the pressure in the well decreases. This decrease in pressure can cause a kick; formation fluids enter the well bore. The formation could also relax and the formation could collapse on the hole, resulting in stuck pipe. 20

21. CCS connection procedure 21

22. 1 . Lift the pipes 2. Activate the pipe rams and the pipe slips 3 . Pressurize the chamber 4. Connect the snubbing unit 5. Disconnect the pipes 6. Lift the upper pipe 7. Close the blind ram 8. Depressurize the upper chamber 9. Disconnect the snubbing unit and the upper pipe ram 10. Remove the pipe, and add new the pipe joint 11 . Close the pipe ram, and connect the snubbing unit 12. Close the drain valve to the upper chamber 13. Pressurize the upper chamber 14 . Open the blind ram 15. Connect the pipe joint and the drillstring 16. Close the valve to the lower chamber 17. Bleed off the chamber 18. Close the drain valve 19. Disconnect the snubbing unit 20. Disconnect the pipe slips 21. Open the pipe rams. 22

23. 2. PRESSURIZED MUD CAP DRILLING (PCMD) The pressurized mud cap drilling technique (PMCD) is used when dealing with reservoirs (depleted) that could result in a severe loss of circulation. PMCD refers to drilling without returns the surface. The driller can apply optional backpressure if needed to maintain annular pressure control. It may allow safe drilling of these zones where the depleted zone above the target has rock characteristics that are capable of receiving the sacrificial fluid and drilled cuttings. 23

24. It uses two drilling fluids- a heavy, viscous mud is pumped down the backside in the annular space to some height. This “mud cap” serves as an annular barrier, while the driller pumps a lighter, less damaging and less expensive fluid down the drill pipe to drill into the weak zone and the heavier mud forces the fluid and cuttings into the loss zone below the last casing shoe. This method keeps the well under control even though all returns go to the depleted zone. 24

25. The important aspects of PMCD are the RCD, cap mud, and drilling fluid. The RCD enables the operator to pump the cap mud into the annulus and to also keep pressure. A flow spool must be installed below the RCD to allow fluid to be pumped into the annulus. Advantage with a lighter fluid is underbalanced, resulting in less damage to the reservoir. 25

26. 2.1 Controlled Mud Cap Drilling(CMCD) This system is similar to the pressurized mud-cap system, except that the level of the mud cap is adjusted by a mud pump to better manage the bottom hole pressure. A subsea mudlift-pump is connected to the riser by a riser-outlet joint. The pump is connected to the mud pits by a return and a fill line. This allows the pump to increase or decrease the amount of mud in the riser. To determine the level of the mud in the riser, pressure sensors are located throughout the riser. The drilling riser is filled with air above the mud cap. The basic concept of this system is to compensate for ECD and thus manage the BHP. 26

27. CMCD Setup in Offshore Drilling 27

28. 3. DUAL GRADIENT DRILLING(DGD) Mainly applicable in deepwater wells. In offshore applications where liquid overburden is less dense than the typical formation overburden, the drilling window is small because the margin between pore pressure and fracture pressure is narrow. Because of the weak formation strength, deepwater conventional drilling applications usually require multiple casing strings to avoid severe lost circulation at shallow depths using single density drilling fluids. But DGD system should be balanced by filling the marine riser with sea water ,inert gas or other light fluid at a predetermined depth to reduce the hydrostatic mud column hence drillers can accomplish BHP adjustment to avoid collapse. 28

29. Here a small diameter return line is run from the seafloor to circulate the drilling fluid and cutting. A subsea pump is used to lift the drill cuttings and the drill fluid from the wellbore annulus up to the rig floor. The returns are either dumped at the seafloor or returned back to the rig, from the seafloor, through one or more small-diameter return lines. 29

30. Two different fluids produce the overall hydrostatic pressure in the wellbore, which avoids exceeding the fracture gradient and breaking down the formation. This saves drilling operations from spending NPT addressing lost circulation issues and associated costs. 30

31. 3.1 Riserless Mud Return System Riserless mud return (RMR) is a top-hole drilling system that uses a subsea pump to return drilling fluid from the seafloor to the drilling vessel before the marine riser is run, without discharge to the seabed: and is the first dual-gradient drilling system commercially available. The RMR system is used in areas where the top-hole formations present difficult drilling conditions that either prevent the well from being drilled, severely limit the depth to which the casing can be set, or result in high costs due to the loss of drilling fluid in a pump and dump condition. RMR is a closed loop system, which means zero discharge to the environment. 31

32. The RMR system uses a computer to control the speed of the subsea pump, based on a suction-pressure set point that is monitored by the pressure transducer on the SMO (suction module). The suction module attaches to the wellhead and it provides a connection point for the subsea pump, and a pressure transducer located near the pump connection point. 32

33. The SMO also provides access to the well for the drill pipe and a mud/seawater interface. Once the RMR equipment is in place and drilling begins, the system is started by observing the drilling-fluid/seawater interface using the video cameras on the SMO. This interface is easily seen, and once observed, the pressure measured by the transducer on the SMO can be entered as the set point for the suction control pressure. The computer control system adjusts the speed of the pump to keep the suction pressure constant. Any change in this pressure causes the subsea pump to speed up or slow down to compensate. 33

34. 3.2 Subsea Mud-Lift Drilling System This method involves the use of a pumping system and return lines. During drilling operations the drill string and the annulus are filled with drilling mud while the marine riser is filled with sea water. Just above the subsea pump inlet a Subsea Rotating Device (SRD) is installed, it to provide a mechanical barrier between the return mud in the annulus and the sea water in the marine riser. 34

35. This subsea rotating device diverts the mud flow from the annulus to a cutting processor, which crushes large cuttings into a size small enough to pass through the seafloor pump and up the return lines without clogging. After the mud and cuttings pass through the cuttings processor, the seafloor pump displaces the returns up the return line and back to the rig. When the return mud reaches the drilling rig the separation process is carried out just like in the conventional drilling method. 35

36. 3.3 Hollow Glass Spheres Method Hollow-spheres are used as lightweight additive. Hollow spheres are mixed in a slurry and pumped into the riser at the sea floor. The injected slurry at the sea floor reduces the density of the return mud in the riser. Once the slurry mixture containing mud, cuttings and the hollow-spheres gets to the drilling rig it is transferred to a separator system. The separator system separates the hollow spheres from the mud and these spheres are used again in the cycle. 36

37. 4. Return Flow Control (RFC) / HSE Method For RFC operations, two hydraulic valves, a conventional flow line to the shakers and a flow line to the rig choke manifold are installed. If an influx is taken whilst drilling the well the hydraulically operated valves allow the flow of returns to be diverted the shale shakers to the rig choke manifold where the influx is safely controlled and circulated out of the hole. Typically only an RCD is added to the drilling operation to accomplish this variation. 37

38. MANAGED PRESSURE DRILLING TOOLS 38

39. 1.Rotating Control Device (RCD) 39 An RCD is an excellent supplemental safety device and adjunct to the BOP stack above the annular preventer. A RCD is used to divert the flow to the choke manifold and seal off the annulus. This provides a closed circulation system . The annulus be packed off at the surface while drilling, making connections, and tripping to safely mitigate hydrocarbons escaping from the wellbore to the rig floor. Modern RCD and rotating annular preventers typically operate at pressures up to 5000-psi static and 2500-psi rotating. Depending on MPD variation and rig type, the RCD can be placed either at surface or subsea. The RCD can be divided into two different categories, passive rotating devices and active rotating annular preventers.

40. 1.1 RCD (Passive system) It consicts of ‘’stripper rubber,” which is ½’’ to 7/8’’ (12.7-22.2 mm) diameter undersize to the drill pipe and is force fit onto the pipe. This forms a seal in zero-pressure conditions. The element is exposed to the wellbore pressure and the seal is made stronger by exposing it to annular pressure. The annular seal element rotates with the pipe. The pipe can rotate and move vertically through the RCD while it continuously maintains a seal. The annular seal or stripper element is bolted to a carrier set into a bowl containing the bearing system and locked into place by a quick-connect collar. Spiral drill collars are difficult to seal against and drill pipes with grooves can damage the RCD stripper rubber so both should be avoided during an MPD operation. The bearing pack is lubricated and cooled by a circulating hydraulic oil system. 40

41. 2. Non Return Valve (NRV) MPD operations often require annulus back pressure. To prevent flow up the drill string and keep a positive backpressure during tripping, non-return valves (NRVs) or floats are installed in the Bottom Hole Assembly (BHA), normally above the mud motor. Without these, backpressure applied at the surface might lead to drilling fluid flowing back up the drillpipe , carrying cuttings that can plug the MWD or blow out the drill pipe. The non-return valve, or one-way valve in the drillpipe , was originally called a float. 41

42. 2.1 Basic Piston Type Float Drilling fluid pressure forces the valve open against the spring when circulating; and when the pump is turned off, the spring and any well bore pressure force the valve closed. The valve is housed in a special sub above the bit, and it is common and prudent for critical wells to use dual NRVs. The primary problem with the type-G Baker float are that it blocks the drillpipe for wireline . 42

43. 2.2 Pump-Down check valve It is seated in a sub above the bottomhole assembly and acting as a check valve against upward flow. It is used when there were objections to running an NRV at the bit because of the chance of increasing lost circulation. Once run, it is not retrievable. 43

44. 2.3 Wireline Retrievable NRV NRV can be changed out or removed on wireline, without tripping the drillstring or killing the well. The WR-NRV which is placed in the drill string sub. It provides elimination of unnecessary time caused by complete pull out of hole in case of logging. 44

45. 3. MPD Choke Manifold A MPD choke manifold is used to control the annular backpressure by regulating the opening of the choke. The choke must be installed in the return flow line to allow back pressure to be applied during the drilling process. The chokes are normally H 2 S rated with equipment used for MPD normally set for 10,000-psi maximum operating pressure. If there is no flow, the choke needs to close quickly in order to trap the pressure. The choke needs to be fast, accurate and highly reliable with a closing time not exceeding 30 seconds. When making connections, the choke needs to be gradually closed while the rig pump rate is gradually reduced. As the choke closes, the backpressure imposed on the annulus increases along with the BHP. 45

46. There are three choke options in the applications of MPD; manual choke, semi-automatic choke and PC controlled automatic choke. Fully automatic mode incorporates a Programmable Logic Controller (PLC) which automatically controls the choke opening to setpoints computed by a dynamic hydraulic flow model. 46

47. 4.Downhole Deployment Valve Downhole Deployment Valve (DDV) is a downhole valve which allows tripping without killing the well. This valve run as an integral part of casing that is to be set above the formation of interest. The outer diameter (OD) is such that the DDV tool can be installed inside standard casing strings, and the ID allows for full bore passage. The tool is operated from the surface by two hydraulic control lines, which are run external to the casing. The tool is run into the well as part of the casing, with the flapper in the locked open position. 47

48. When making a trip out of the hole, the pipe is stripped out until the bit is just above the DDV valve. Then, the flapper on the DDV valve is closed by the application of pressure to the “close’’ control line. The upper annular pressure is bled off, and the pipe tripped normally. Going back in the hole, the pipe or tubing is run in to just above the valve. The rams are closed and the upper well bore is pressurized up to equal to the annulus below DDV valve. 48

49. 5. ECD Reduction Tool This is a downhole tool which is installed on the drillstring and can reduce the ECD in the wellbore by as much as 10 bar. The circulating fluid enters the turbine motor at the top and comes back into the string after driving the turbine motor. The pump is driven by the turbine motor and it pumps return fluid up in the annulus. The tool does not rotate with the drillstring and has annular seals to ensure that the flow passes through the tool. The tool is activated by fluid flow and deactivated when the flow stops. It can handle densities up to 1.8 SG, including cuttings, and run inside 9 5/8” to 13-3/8” casings. 49

50. 6. Coriolis Flow Meter This flowmeter is installed on the return line and can measure mass flow, volumetric flow, density and temperature. The coriolis flowmeter can detect mud losses of less than 0.5 bbl. By oscillating a flow tube and measuring the time it takes to complete one oscillation, the coriolis flowmeter can measure density quickly and accurately. 50

51. 7. Continuous Circulation Valve This valve enables continuous circulation during connections. The 3-way valve is installed on top of each stand of drill pipe. It has a sideport that can be connected to a hose and the flow from the mud pumps will then be switched from the top inlet to the side inlet, and top drive can then be disconnected and a new stand installed. 51

52. MPD APPLICATIONS Tight Pore Pressure- Fracture Pressure “Windows”. Depleted Reservoir Drilling Severe Drilling Fluid loss-Fractured or Vugular Formation’s. Kick control (Influx control). Differential Sticking- Stuck pipe-Twist off. Deeper Target depths Unstable Wellbore (Wellbore Instability). Ballooning / Breathing formation. Deep water Marine Drilling. Drilling unknown pore pressure Zones. HPHT (High Pressure High Temperature) Drilling. 52

53. FEASIBILITY OF MPD IN ONGC 1) Well No: RO#51 (West Tripura) Target Depth : 4800m Drilled Depth : 3457m The well is terminated at 3457m due to heavy mud loss, caving, water influx and every time the drill string is getting differentially stuck and the drill string has been pulled out within casing shoe again & again 53

54. Recommendations From the above graph pore and fracture pressure gradient window is narrow from about 3500 m to 4600 m (TD) Hence; MPD with an automatic choke can be used in 8½”section to maintain constant BHP and avoid complications such as mud loss, caving, stuck drill pipe, tight pull, influx etc. When an influx took place, more back pressure was applied and a quick control was obtained. 54

55. 2) Well No: RO#1 (West Tripura) Target Depth : 5300m Drilled Depth : 4600m During drilling in 8½” hole section (3601m-4260m) and 6” hole section (4260m- 600m), activities such as Tight pull, hold up and stuck drill pipe and mud loss are observed. 55

56. Recommendations High pressure charged formations observed with loss zones, suggesting narrow margin between PP and fracture pressures in depth intervals of 3065-3285¸ 3395- 4120. So MPD can be used in 8 ½” hole section to avoid complications and 9 ⅝” should be lowered with Annular Isolation Valve or Down hole Isolation valve for safe and fast tripping for drilling 8 ½” hole section with MPD. ONGC has also decided to implement MPD in Mumbai High to drill depleted L-III layer and to exploit unconventional reservoir, basal clastic and basement, where there is narrow margin between pore pressure and fracture pressure. 56

57. CONCLUSION Managed pressure drilling is a new technology that will improve the economic drillability of wells. It can help solve many of the NPT problems that result from pressure variations in the formations that occur mainly in offshore drilling. It will increase reserves for companies by enabling drilling of areas that were previously economically undrillable . MPD uses tools similar to those that are being used for underbalanced drilling; this could mean a smoother transition for companies to begin using MPD technology. Many variations of MPD are available, but more research is necessary to determine which variation is best to be used in specific drilling situations. MPD would help reduce costs and improve assets held by companies.Recently , pressure management - MPD- can be defined as one of the ultimate problem solvers until a better way is discovered. 57

58. FUTURE OF MPD The challenge for the future of MPD is to convince the industry of its benefits. The best way to do this is to have companies run tests out in the offshore environment to prove that these techniques work. The main problem in instituting MPD is that companies think that their way works well enough and do not want to take the risk of trying a newer method. This is similar to situations that occurred when underbalanced drilling and horizontal drilling were first introduced. It is just going to take time for MPD to become an accepted method and be used in regular drilling operation. 58

59. REFERENCES Hannegan D., “Managed Pressure Drilling,’’ SPE Advanced Drilling Technology & well construction textbook, chp.9.section 10 IADC Glossary of MPD terms,www.iadc.org,11/2005 Coker, I.C: “Managed Pressure Drilling Applications Index,’’ paper OTC 16621 presented at the 2004 offshore Technology conference, Houston, 3-6 May Hannegan , D., “Managed Pressure Drilling Fills a Key Void in the Evolution of Offshore Drilling Technology”, presentation at the Offshore Technology Conference held in Houston Texas USA, 16624, 3-6 May 2004. Hannegan , D.M., “Managed Pressure Drilling: A new way of looking at drilling hydraulics… Overcoming conventional drilling challenges”, SPE Distinguished Lecturer Series, 2007, 1-29. 59

60. THANK YOU 63

61. MPD is departure from the conventional drilling processes and the following elements are key to the success of the project: Specialized procedure development for MPD operations and emergency situations. Training of rig crews and service personnel for MPD operations and procedures. Effective strategy for capturing lessons during drilling process for future well planning. Drill pipe tool joint should have smooth hard banding to enable the rubber sealing elements last longer. Separate pump for surface circulation of the MPD system. A Quantitative Risk Assessment(QRA) is to be done on MPD processes performed on Rig.

62. MPD Surface Layout