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Coiled tubing application and procedure.ppt
- 1. W E LL S E R V I C E S W E L L S E R V I C E S Coiled Tubing Drilling Services
- 2. 2 Outline • Training Objectives •Introduction • Advantages , Limitations and Main Concepts • Main CTD Applications • Over vs Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 3. 3 Objectives • Identify thedifferences between CT Drilling and conventional drilling. • Identify advantages and limitations of CTD. • Point out the main CTD applications. • Identify types of CTD bottomhole assemblies and their functions. • Identify types of surface equipment needed for CTD. • Recognize CTD fluids requirements. • Identify integrated service opportunities that can be provided by Schlumberger. • Identify factors that must be controlled when designing a CTD job.
- 4. 4 Outline • Training Objectives •Introduction • Advantages and Limitations and Main Concepts • Main CTD Applications • Over vs Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 5. 5 Introduction • Important differencesbetween CT Drilling techniques and conventional (rotary) drilling techniques. – The main difference : cannot rotate the pipe : – must use downhole motors, – orienting tools and other special equipment How to focus the balance of pros and cons : -Continuous pumping vs stopping at each connection -Weight : CT can be pushed into the horizontal section with the aid of the Injector Head . (on shallow wells this could be a benefit) - …
- 6. 6 What is CTD? CoiledTubing Drilling • The use of coiled tubing (continuous pipe), stored on a reel at surface, combined with downhole mud motors to turn the bit to deepen a wellbore. • MWD / LWD mud pulse and wired telemetry are available to directionally steer the wellbore to the zone of interest.
- 7. 7 Outline • Training Objectives •Introduction • Advantages , Limitations and Main Concepts • Main CTD Applications • Over vs Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 8. 8 Advantages • CTD presentsseveral advantages over conventional drilling operations: – smaller footprint, – safer drilling operations while drilling underbalanced, especially with multiphase fluids – continuous circulation – faster tripping operations – ability to monitor and subsequently control downhole pressures more efficiently, – real-time downhole measurements of surveys, logging data (GR, CCL), and pressure data at high-data rates using integral wireline inside the CT – superior directional control due to steering at BHA (reduced reactive torque effects)
- 9. 9 Limitations • limited lifeof the CT itself (i.e., cycle fatigue), especially in larger coiled tubing sizes • less industry experience compared with conventional drilling, • additional operating cost due to the need for a downhole motor. • reduced horizontal-reach potential, due to sliding friction
- 10. 10 Rate of Penetration •Optimizing : with CT must be done with limited weight on bit. – No drill collars +helical nature of CT = reduced weight on bit – No rotation = increase in friction and reduce the effective transfer of weight to bit. • The additional weight of CT due to increasing depth is taken up in friction due to helical buckling in the vertical wellbore. – Typically, ROP with CT is controlled by motor/bit selection and the reduction of hydrostatic pressure on the formation (in other words, underbalanced drilling).
- 11. 11 Weight on Bit •Weight on bit = function of well geometry and hook load. • Can be affected by : – Hole tortuosity and – cuttings bed can. • Cannot be calculated from the difference in hook load from off-bottom. • Decreases as drilling is done through the build and horizontal wellbore • Stick-slip = the conversion of slack-off weight at surface is transmitted to the bit unevenly, in jerky movements. – Caused by crossover from static to dynamic friction.
- 12. 12 Integrated Solutions Coiled Tubing Drilling Services DCS Candidate Selection D&M Well Planning Well Services CTD D&MLWD/ MWD/DD RE Wireline Well Completion Services IPM Project Management
- 13. 13 Schlumberger Approach toCTDS • Candidate selection with operator including technical & economic feasibility studies • Utilise world-wide CT presence and expertise from all Schlumberger segments • Develop long-term multi-well projects • Focus on QHSE & training • Continuous R&E efforts (Rapid Response)
- 14. 14 CTD Process • CTDFeasibility Study – CT Parameters – Limited reservoir study – Needs and challenges identified – Equipment recommendations – Preliminary wellplans • Economic Estimate • Resource availability • Recommendations for further study • Detailed Engineering – Well plans – Detailed cost – Logistics – Reservoir evaluation – Risk analysis – QHSE • Execution • Evaluation Initial Study Detailed Analysis
- 15. 15 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 16. 16 Coiled Tubing DrillingApplications • Overbalanced drilling : drilling fluid pressure > bottomhole pressure (pore pressure). Reservoir fluids are not allowed to enter the wellbore. • Underbalanced drilling : BHP < pore pressure of the rock . Reservoir fluids are allowed to enter the wellbore -> separated at surface The underbalanced technique is used to: – prevent formation damage – minimize many drilling-related challenges, such as loss of circulation and differential sticking, – increase rates of penetration, – minimize completion costs, – increase hole-cleaning efficiency, – reduce mud costs, and – improve economics
- 17. 17 Applications • Through tubing operations •Conventional reentry • Under-balanced drilling • Special Applications – Environmentally sensitive – Small footprint • Grass roots / new wells
- 18. 18 Previously-drilled Wells • Coiledtubing drilling in previously-drilled wells can be performed using either: – through-tubing reentry or – casing reentry. • Through-tubing Reentry Sidetrack • The wellbore can be exited either through both the tubing and/or casing or through the casing below the production tubing. • This method eliminates the cost of: – pulling tubing and associated completions equipment and – running production tubing after drilling. • Can be performed with either overbalanced or underbalanced techniques.
- 19. 19 Previously-drilled Wells • CasingReentry Sidetrack • Casing reentry is done to deepen wells or for sidetracking and horizontal drilling. • Coiled tubing is most effective economically when used to: – perform short radius drilling, – when in environmentally sensitive locations, and – offshore on platforms where a full drilling rig is cost prohibitive. • Casing reentries can be performed with either overbalanced or underbalanced techniques.
- 20. 20 New Wells • Anew well = drilled from ground level to the target formation. • CT Drilling is not suitable for all new well applications but can be used effectively to drill small wellbores (up to 12 1/4 in). • To justify the use of CTD for a new well : – shallow, gas pilot wells. Conventional drilling may result in blowout. – Coiled tubing equipment is designed to work in live wells. – In these cases, the CT unit is used to drill the first 1500 to 3000 feet – greatly increased safety factor – with a minimum amount of equipment – NO personnel directly over the well.
- 21. 21 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 22. 22 Underbalanced Drilling • Reservoirpressure determines the drilling fluid density. Underbalanced drilling is often used to denote: – drilling in the reservoir with inflow – drilling with multiphase fluid, such as nitrified liquid or foam • To achieve UBD and lower hydrostatic fluid column , these methods may be used : – lower density drilling fluid, – nitrified drilling fluid, – air/foam drilling fluid, or – gas lift from the annulus • When underbalance techniques are used, the selection of surface equipment and downhole tools used for data telemetry must be altered accordingly to compensate for aerated fluids.
- 23. 23 Underbalanced Drilling Benefits •The most important benefit : reduction of formation damage , as invasion may cause : – swelling clays, – changes in reservoir wettability, – Emulsions – fines migration, and – other mechanisms. • Usually results in increased rates of penetration • Differential sticking problems are reduced • In sum : – increased drilling performance, – minimized potential for formation damage, – reduced drilling problems, – elimination or minimization of post-drilling stimulation = Better value for the client. = Better value for the client.
- 24. 24 Underbalance Applications When : •reservoirs are subject to damage • reservoirs are depleted or underpressured • reservoirs are susceptible to drilling problems • real-time reservoir evaluation can aid in decision- making
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- 26. 26 Competition Summary • BJS –Holland – Successful 2 well operation for Shell – Recently won bid in APG • Weatherford – Recently awarded 1st CTD contract (France) – Will provide complete package for CTD • Canada – Various CTD providers drilling shallow vertical wells – Precision, CanCoil, BJ, Trican – BJS technical leader drilling UBD in Northern Alberta
- 27. 27 Schlumberger CTDS Evolution 0 10 20 30 40 50 60 70 80 90 100 19911992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Year Number of Wells Non-steered / vertical wells Directional wells
- 28. 28 CTD Statistics 1991-2002 SteeredWell Distribution by OH size 4" - 5" 12% 5" - 7" 3% < 3.25" 16% 3.25" - 4" 69% Depth Distribution 0 100 200 300 400 3000 6000 9000 12000 15000 18000 Depth(ft) Num ber of Wells Non-steered SteeredWells SteeredWell Types 4% 82% 8% 6% Thru-tubing Conventional Well Extension Under- balance
- 29. 29 Why CTD? Financial • Completioncan stay in place • Quick tripping with continuous pipe • Lower mobilization cost • Enhanced production from existing wellheads avoids heavy infill drilling investment & infrastructure upgrade Operational Aspects • Faster mobilization • Increased ROP and no differential sticking (UBD) • Less personnel • Fast wireline telemetry and improved directional control • Ultra short radius and designer wells to avoid hazards Safety and Environment • Improved well control • Operational personnel removed from the well area • Smaller footprint, noise and height Reservoir Issues: Increase Overall Recovery • Reduce skin damage while drilling underbalanced • Reduced pressure surges on formation
- 30. 30 What is neededfor a Success? • Continuous utilization – multi-well • Personnel – experienced CT and drilling, dynamic organization – trained in CTD • Commitment for project • Detailed front end well engineering • Sustained projects • Profitable price structure for customers and SLB – Multiple financial models possible • Technically feasible projects
- 31. 31 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 32. 32 32 M 25 M CTD SurfaceEquipment – (OBD)
- 33. 33 Surface Equipment -Pumps • Various pumps have been used – Problems • Recommend only SPF243
- 34. 34 Surface Equipment Surface equipmentincludes: • coiled tubing equipment, • well control equipment, • returns handling equipment, • pumping equipment, • monitoring and recording equipment, and • a substructure or work platform (which includes makeup tongs, slips, and other handling equipment).
- 35. 35 Surface Equipment Coiled TubingUnit • CT Drilling equipment usually includes the: – coiled tubing and coiled tubing reel, – injector head, – power pack, – coiled tubing blowout preventer (BOP), and – control cab. Well Control Equipment • The well control equipment typically includes: – blowout preventers (ram-type and annular), – accumulator units, – stripper (ram-type or radial), – kill lines, – check valves, and – chokelines and manifolds.
- 36. 36 Surface Equipment Returns HandlingEquipment • The fluid handling equipment can include: – a mud return line (lines between the annular section and return tanks), – mud tanks, – a shale shaker (removes large cuttings), – a centrifuge, – a degasser (poor boy or vacuum), – desander, – desilter, – sample catcher, – a separator (optional), and – a mixing hopper.
- 37. 37 Surface Equipment Pumping Equipment •CT Drilling requires long periods of continuous pumping • Normally not the same conventional operations pumps • Drilling rig pumps are more suitable to these operations – Long hours – Possible abrasive fluids – Needs to be remote operated (less personnel) – Sometime needs to on/off frequently (orienting tool) • Pump Pressure Pump pressure is a function of: – pump rate, – fluid composition, – length of CT – flowing friction inside the coil and in the annulus. • Typically, is approximately 4000 psi.
- 38. 38 Surface Equipment Monitoring andRecording Equipment • CoilCAT* – conventional coiled tubing unit instruments – flow-parameter instruments (monitor rates of return) • Integrated with downhole tool measurements to provide a full monitoring package for efficient operations. • CoilCAT communicates depth, pumping pressures, and surface weight measurements to the IDEAL system (D&M) – where it is combined with downhole measurements : – direction, – inclination, – gamma ray, and – other sensors to provide accurate data for plotting and monitoring the directional drilling progress and geologic correlation to drilled formations downhole.
- 39. 39 CTD Applications Under-balanced Drilling •Drilling into a formation where the pore pressure is greater than the pressure exerted by a column of fluid – Potential Higher Productivity – No Filter Cake / Damage Requiring Stimulation – Faster Rate Of Penetration – Reduced Differential Sticking – Lower WOB required allows for increased penetration – Enhanced Pressure Control
- 40. 40 X M X M CTD SurfaceEquipment – (UBD) • CTU • BOP • UBD Package – Cutting catcher – Cyclone – Heater – Choke – Separator – Knockout vessel – Surge tank – Flare • Substructure • MWD Cabin • Pumping Equipment
- 41. 41 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 42. 42 Coiled Tubing DownholeEquipment • Bottomhole assemblies for coiled tubing drilling applications include: • motor assembly for nonsteered drilling applications • directional drilling assembly for directional drilling • bottomhole assembly for window-milling operations • bottomhole assemblies, such as those used for running liners, whipstocks, scrapers, fishing, etc
- 43. 43 Bottomhole Assembly forNonsteered Drilling Applications • The bottomhole assembly typically consists of : • the coiled tubing connector • drill collars (if needed for vertical wells) • a check valve • a release mechanism • a downhole motor • a bit
- 44. 44 Drill Collars • Normally2 to 3 to help to keep the well straight . • Pendulum effect. • Spiral downhole collars
- 45. 45 Check Valves • Safetybarrier • Prevent back flow into the coiled tubing that could cause plugging of the BHA.
- 46. 46 Release Mechanism • Normallyoperated by dropping a ball from surface inside the coiled tubing. Other types of release mechanisms include: • shear pin mechanical releases (not recommended) • multicycle disconnect release
- 47. 47 Downhole Motors • Positive-displacementmotor (PDM) – most common. • Other motors are sometimes used in special applications. Those motors include: • Turbines • vane motors
- 48. 48 Bottomhole Assembly forDirectional Drilling • Typical CTD BHA layout includes: – coiled tubing connector – float sub (check valves) – downhole instrumentation (e.g., downhole pressures, GR, CCL) – nonmagnetic housing for surveying instrumentation with wireline, mud pulser, or electromagnetic telemetry – orienting tool – release tool (optional) – UBHO (universal bent housing orienting) sub (if required) – drilling motor with bent housing – Bit
- 49. 49 Bottomhole Assembly forDirectional Drilling Wireless Telemetry BHA Can be : – mudpulses or electromagnetic signals – Advantages : – Easy assembly (just attach to the end of the CT) and setup receiving sensor on surface – Full access through the CT (drop-ball) , post CTD operations possible Wireline Telemetry BHA Uses a direct wired connection to communicate measurements down the BHA through the CT reel. – much higher data-transmission rates – Special tools needed (disconnect , CV , …) • Both the electromagnetic and wireline systems can be operated while using multiphase flow in the wellbore.
- 50. 50 Bottomhole Assembly • DirectionalDrilling – Wired – Mud pulse • Motors – PDM – ADM – Turbines • Deployment methods – Pressure deployment – NRJ’s • Verify critical parameters Coil Coil Connector Check Valves Hydraulic Disconnect Circulating Sub Non Rotating Joint Top Half Non Rotating Joint Bottom Half MWD Collar Orienter UBHO Mud Motor Bit GR Tool SlimPulse D&I Package Float/Vent Sub Bent Housing
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- 52. 54 Wired Telemetry • Providers –Weatherford – BJS – Baker Hughes Inteq •Fully integrated and modular CTD system •BHA setup can be changed to customer requirement •High speed communication via single conductor wireline •Precise wellbore placement due to bi-directional steering with closed loop automatic steering control •Multiple standard sensors: directional, gamma, temperature, casing collar locator •Optional sensors: WOB, annular and string pressure in the drilling performance sub
- 53. 55 Bits • The twomost common types of bits are: – fixed cutter (sometimes called drag bits) – no bearings and no rotating parts – Most common : – PDC (Polycrystalline Diamond Compact), – TSP (Thermally Stable Polycrystalline), – Diamond – roller-cone bits – Set in a variety of configurations – From 1 to 4 cones , most common is 3 cones. – Most used in CTD is a tricone with sealed journal bearings
- 54. 56 BIT Choices Insert PDCBiCentered
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- 56. 58 Casing Exits Cement Ramp TimeDrilling Specific completions Deviated wellbores Motherbore isolation Openhole KO’s Mechanical Whipstock Single or multiple components Minimum of 2 trips Completions Motherbore isolation requirements
- 57. 59 17 ppg FiberKick Off Plug “One Step Mill” Casing Exit Casing Exit Technology
- 58. 60 Bottomhole Assembly forWindow Milling • In most cases done with : – Whipstock – cement plug – whipstock/cement plug combination
- 59. 61 Special Purpose Bottomhole Assemblies Thereare a number of special purpose bottomhole tools used during coiled tubing drilling operations. These include : – drilling and fishing jars – accelerators underreamers – float subs – overshots or spears
- 60. 62 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 61. 63 Coiled Tubing DrillingFluids Requirements • Drilling fluids issues for CT Drilling are not much different from conventional drilling with a few exceptions: • Cuttings bed buildup = more problematic with CT (no rotation) • Continuous circulation = no settling during connections . • Lower circulating pressure (rates) on the CT when compared to DP
- 62. 64 Fluid Hydraulics • Twomajor factors governing flow rates on CTD : • The downhole motor – By-pass = more flow (on single-phase) • The maximum allowable surface pressure – CT Yield Strength – Pressure drop across Ct and any component of the BHA must be taken into consideration on the design phase
- 63. 65 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 64. 66 Technical Overview 16000 ft 3000ft 50 deg / 100 ft Tubing 3.5 in , 4.5 in Casing 5 in, 7 in, 9.625 in Good MIT Good cement job Isolation Well history Offset data 10 ft window
- 65. 67 Drilling WOB Helical lockup Minimum 600lbs Hydraulics Minimum velocity Pump rates Optimized fluids Rate of penetration Equivalent to rotary rigs Tubing Forces 100 K pull 40 K snub 80% stress 5 fph – rotary rates
- 66.
- 67. 69 Outline • Training Objectives •Introduction • Advantages and Limitations • Main CTD Applications • Over vs. Under-balance • Surface Equipment • Downhole Equipment • Fluid Requirements • Technical Overview – Well Example • Design Considerations
- 68. W E LL S E R V I C E S W E L L S E R V I C E S Module CT05 CTD CoilCADE
- 69. 71 CTD CoilCADE • 1st TRUTH: NO REAL CTD GUIDELINES FOR COILCADE • 2ND TRUTH : BEST MODELING IS FROM EXPERIENCE • 3RD TRUTH : RESEARCH , RESEARCH , RESEARCH…
- 70. 72 Attach 01 LiquidRate (bpm ) N2Rate (scfm ) Depth (m MD) Avg.ROP (m /hr) BHPressure (psi) 2.2 6502180-2200 6 2630 1.8 900 2200-2229 8 2360 1.6 1050 2229-2251 7 2150 1.8 900 2251-2299 9 2340 Table 1 - Liquid/Nitrogen Flow Rates
- 71. 73 Real vs PredictedBHP Annulus Pressure Comparison Well 7-C-219HP-BA 2000 2250 2500 2750 3000 650 750 850 950 1050 1150 N2 Flowrate (scf/m) Annulus Pressure (psi) Actual Predicted N2 Rate 650 scfm 900 scfm 1050 scfm Liquid Rate 2.2 bbls/min 1.8 bbls/min 1.6 bbls/min Figure2- CoilCADEPredictedBottomHoleAnnularPressureversusActual
- 72. 74 TFM • Calculate – Reach –Max Predicted Weight on Bit – Compare modeled with realtime
- 73. 75 TFM Real vsModel Adjusted - Alaska -236.52 CT Wt Avg - lbf 0.97 Corr. Depth - ft 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Measured Depth of Tool String - ft -5000 0 5000 10000 15000 W eig h t In d icato r L o ad - lb f Pickup Slackoff RIH - Friction Coeff 0.25, WOB while RIH 1500lbs, at TD 2750lbs before lock up POOH Friction Coef 0.10 CCAT* (c) Schlumberger Dowell 1994-99 Tubing Forces bp MPH-08a Plan 1 Set Whipstock 14 March 01
- 74. 77 TFM Results :Predicted vs Real Available Weight On Bit vs. Depth, MPXXX Plan#X 9000 9250 9500 9750 10000 10250 10500 10750 11000 11250 11500 11750 12000 12250 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 WOB (lbs.) Measured Depth (ft) Design Actual Maximum WOB before lockup 600lbs WOB Predicted MD 11500' KOP 9110' Planned TD 13000' 1000lbs WOB Predicted MD 11250' Possibleto drill withup to600lbs WO B No recom m ended todrillwithless than600lbs WO B Actual TD 11448'
- 75. 78 WBS FOR DRILLING •Will calculate : – Cuttings to surface – Hydraulics dynamically – BHP – Pressures
- 76. 79 CTD Operations Organigram Client CompanyMan Project Manager CTD Engineer CTD Rig Manager Drilling Fluid Engineer Directional Driller Wireline and Testing Engineer CTD Service Supervisor CTD Driller Pump Operator Helpers Mechanic Electronic Technician MWD Engineer Motor Man Third Party Suppliers Wireline and Testing Winchman Wireline and Testing Helpers CTD Assistant Driller
- 77. 80 Summary • CTD isa niche application • Primary markets – Thru-tubing reentries – UBD • Full evaluation mandatory by experienced personnel • Multiple-well campaigns are necessary • QUESTIONS ????
- 78. 81 Schlumberger CTD Achievements CommercialCT drilling and coring (Elf, France - 1991) MWD used on CTD operation (ARCO, Texas - 1992) Thru-tubing horizontal well (ARCO, Alaska - 1993) Offshore well drilled from surface (Lagoven, Venezuela - 1993) CTD air drilling (Texas - 1993) Thru-tubing window milling below tbg (ARCO, Alaska - 1994) KO from cement plug thru casing (ARCO, Alaska - 1994) Large bore, 8.5”, coring with CT (Vico, Indonesia - 1995) Largest hole drilled with CTD, 12 3/4” (Lagoven, Venezuela - 1996) 2 3/8” directional BHA run thru tubing (ARCO, Alaska - 1996) 950 ft of 3 3/4” hole drilled horizontally in 24 hrs (BP, Alaska - 1997) Ran & oriented retrievable whipstock on CT (Statoil, Norway - 1997) Milled window thru both 4-1/2” and 9-5/8” (DPC, UAE - 1997) Drilled Lateral Leg with a 122° inclination (Statoil, Norway -1998) Highest BUR achieved with CTD - 100°/100 ft (CNGT, USA - 1998) 1st and 2nd GOM CTD applications (Amoco, Spirit, GOM – 1998) First applications of Gyro Orienter (Canada – 2000) 10th North Sea CTD project (Talisman, N.Sea – 2001) Cement KO from Vertical well (North Sea – 2002) Deepest window exit – 15,800 ft (Colombia 2002)
Editor's Notes
- #5 Reference: IT Module CT Drilling There are some important differences between coiled tubing drilling techniques and conventional (rotary) drilling techniques. The main difference is that coiled tubing drilling must use downhole motors, orienting tools and other special equipment to circumvent the inability to rotate the pipe. While the advantages of not having to make connections and being able to continuously circulate while tripping into or out of the wellbore are beneficial, these additional benefits are offset somewhat by the additional equipment requirement. With normal drilling operations with drill pipe, circulation of the well needs to be stopped to be able to make the connections. Many problems like lost circulation and stuck pipe can occur during this period. Another significant difference is that coiled tubing drilling can use not only the coiled tubing itself to provide weight on the bit, but can use the injector to apply snubbing forces to the coiled tubing when drilling horizontally. The use of coiled tubing for directional drilling has increased dramatically since 1991. Schlumberger launched its CTD effort in 1991, and from 1991 to 1995, Schlumberger performed more than twice as many CTD operations as all of its competitors combined. In the last few years, competitor activity in Canada and other focused areas has increased drastically.
- #8 Reference: IT Module CT Drilling This minimizes damage to the reservoir by eliminating the need to drill the well as is normally required with a conventional drilling rig. Underbalanced drilling also permits the well to produce while it is being drilled. Although underbalanced drilling can also be performed by certain rigs with jointed-pipe equipment, tripping and completion activities require that the well be killed - significantly impairing any results from underbalanced drilling. Coiled tubing drilling allows the well to be maintained in an underbalanced state throughout the drilling and completion operations, virtually eliminating any wellbore damage and possibly reducing the need for well stimulation afterwards. Another major advantage of coiled tubing or drilling related activities is the ability to install a wireline inside the coiled tubing itself. The insertion and removal of any electric steering tools, packers, logging tools, or the equipment into the well is conducted in an effortless, efficient manner by simply spooling the coiled tubing. This ability to perform trips quickly is a major advantage when performing operations on deep wells. In certain cases, coiled tubing operations may require less personnel than conventional drilling rigs; however, due to the performance of different activities this reduction may not be significant. For example, a well drilled underbalanced may not be cased, and therefore, the casing crews, cementing crews, perforating crews, etc., such as may be needed for normal wells, are not required. The footprint of a coiled tubing drilling unit is usually significantly smaller than a conventional drilling rig. This smaller footprint can be attributed to the use of a reel versus pipe racks with jointed pipe, and the use of an injector versus a derrick and drawworks. However, the main reason for the difference is the fact that most drilling rigs are built to handle larger hole sizes and larger downhole equipment. Coiled tubing drilling is mainly a technique for drilling in the target reservoir formation, although some unique applications utilize CTD to drill large (up to 12 ¾ in) surface and intermediate hole sizes. Research and development of coiled tubing for drilling has proven it to be both technically feasible and economical in the right applications. This makes it a viable alternative to conventional drilling, especially offshore and in environmentally-sensitive areas. Coiled tubing units are used to drill in environmentally-sensitive areas because of the efficiency in using a closed loop system due to no connections. The coiled tubing drilling package also has less exhaust emissions and greatly-reduced noise levels. Due to the small diameter holes being drilled, there are reduced quantities of drilling fluids to be mixed, and less drill cuttings to dispose. The major attraction to coiled tubing drilling in the long-term is the fact that the technology is particularly advantageous when used for underbalanced drilling, short radius, and multilateral applications.
- #9 Reference: IT Module CT Drilling
- #10 Reference: IT Module CT Drilling Optimizing rate of penetration with coiled tubing must be done with limited weight on bit. Due to the absence of drill collars and the helical nature of coiled tubing, weight on bit is reduced. The inability to rotate the coiled tubing also serves to increase friction and reduce the effective transfer of weight to bit. The weight transferred to the bit does come from the weight of the coiled tubing; however, available weight on bit does not increase with increased depth. The additional weight of coiled tubing due to increasing depth is taken up in friction due to helical buckling in the vertical wellbore. Typically, rate of penetration with coiled tubing is controlled by motor/bit selection and the reduction of hydrostatic pressure on the formation (in other words, underbalanced drilling).
- #11 Reference: IT Module CT Drilling Weight on Bit Weight on bit is a function of well geometry and hook load. Hole tortuosity and the existence of a cuttings bed can also detract from the ability to transfer weight to bit. Weight on bit cannot be calculated from the difference in hook load from off-bottom. Some of the hook load weight is lost in friction due to helical buckling. The percentage of hook load weight transferred to the bit decreases as drilling is done through the build and horizontal wellbore. The phenomenon of stick-slip also causes the conversion of slack-off weight at surface to be transmitted to the bit unevenly, in jerky movements. This is due to the crossover from static to dynamic friction. Other factors that affect weight on bit include casing size and hole size.
- #13 In order for CTD to succeed and prove profitable and a value solution for the client the projects that will be developed must meet certain criteria. These criteria are outlined below: The candidate wells must be chosen with technical and economic feasibility in mind. In the past wells have been chosen without sufficient engineering and planning and have not proven a viable solution to either the client or Schlumberger. Though the use of our CTD project managers working closely with the client the appropriate candidates and projects will be developed. The worldwide expertise that Schlumberger has developed over the last 12 years will be brought to each and every project that is undertaken. Schlumberger has drilled wells in just about every climate available on the planet. From the arctic to the jungle, on-land and offshore, on lake and in the desert Schlumberger has paved the way forward for coiled tubing drilling applications. The focus on long term, multi-well contracts brings to bear the learning curve associated with new drilling opportunities. Time and again the plot of efficiency versus the number of wells can be charted to prove that initially CTD may not prove much of a cost savings over conventional rotary rigs. With continued operations (5+) wells the efficiency for the entire operation increases. As illustrated in slides later, a recent program in Indonesia decreased RU/RD time by over 70% and NPT dropped from 7% to 0%. Schlumberger has a steadfast commitment to QHSE. Schlumberger has a track record as a leader in safety, and environmental awareness. Two training centers, one in the US and the other in the UK, provide training for our field and technical staff . One of these centers located in the UK is a combined facility between Drilling and Measurements and Well Services. New technology is the cornerstone of Schlumberger’s image. The SlimPulse directional drilling system is best in class with over 2 million operating hours logged with the technology. New and evolving systems are constantly being developed my our product and engineering centers.
- #16 Reference: IT Module CT Drilling prevent formation damage= caused by entry of damaging drilling fluids to the formation increase hole-cleaning efficiency =due to reservoir inflow improve economics =by providing early reservoir production. Both techniques can be used on new and previously-drilled wells. When drilling in a previously-drilled well, casing reentry may be used (with tubing removed), or reentry can be done through the existing tubing, if the tubing is large enough to accommodate current equipment (3-1/2 inch tbg and larger). Coiled tubing is especially attractive for slimhole applications, due to susceptibility to joint failure in conventional slimhole pipe. Overbalanced drilling is drilling with a fluid that exerts sufficient bottomhole pressure to exceed that of the pore pressure in the rock surrounding the wellbore. Reservoir fluids are not allowed to enter the wellbore. Underbalanced drilling is drilling with a bottomhole pressure below that of the pore pressure of the rock surrounding the wellbore. Reservoir fluids are allowed to enter the wellbore and are separated at the surface from the drilling fluid. The underbalanced technique is used to: prevent formation damage minimize many drilling-related challenges, such as loss of circulation and differential sticking, increase rates of penetration, minimize completion costs, increase hole-cleaning efficiency, reduce mud costs, and improve economics
- #17 Coiled tubing drilling Is a niche application. CTD is not a direct alternative for rotary drilling. In order for a CTD campaign to proceed one or more of the following drivers must be valid. Through tubing or conventional operations Under-balanced drilling Drilling in limited access areas or under environmental constraints Grass root / new wells
- #18 Reference: IT Module CT Drilling Through-tubing reentry means that the coiled tubing reenters the wellbore through existing production tubing. This method requires the entire bottomhole assembly to be able to pass through the tubing. This method is used to deepen wells and for directional sidetrack to increase flow area or access new reservoir targets. The wellbore can be exited either through both the tubing and/or casing or through the casing below the production tubing. This method eliminates the cost of: pulling tubing and associated completions equipment and running production tubing after drilling.
- #19 Reference: IT Module CT Drilling Casing Reentry Sidetrack With casing reentry, the coiled tubing reenters the wellbore through the casing - any production tubing or packers are removed prior to initiating the wellbore exit. Casing reentry is done to deepen wells or for sidetracking and horizontal drilling.
- #20 Reference: IT Module CT Drilling A new well is a well that is drilled from ground level to the target formation. Coiled tubing drilling is not suitable for all new well applications but can be used effectively to drill small wellbores (up to 12 1/4 in). Many times coiled tubing drilling techniques are used to perform drilling operations that cannot be done with conventional rotary drilling. One such application is the use of CTD to drill shallow, gas pilot wells. Conventional drilling operations are performed under balanced conditions using the weight of the mud as the primary pressure barrier. Drilling shallow overpressured gas pockets may result in blowout. Coiled tubing equipment is designed to work in live wells. In these cases, the coiled tubing unit is used to drill the first 1500 to 3000 feet of a known shallow gas area. The reason for this is the greatly increased safety factor using the CTU, with a minimum amount of equipment and NO personnel directly over the well. After casing has been set over the shallow gas zone, a conventional rig can be brought in to finish drilling the well.
- #22 Reference: IT Module CT Drilling When underbalanced drilling is required, reservoir pressure determines the drilling fluid density. Underbalanced drilling is often used to denote drilling in the reservoir with inflow from the reservoir and also to define drilling with multiphase fluid, such as nitrified liquid or foam, even though bottomhole pressure may be above pore pressure. Depending upon certain conditions, When underbalance techniques are used, the selection of surface equipment and downhole tools used for data telemetry must be altered accordingly to compensate for aerated fluids.
- #23 Reference: IT Module CT Drilling When underbalanced drilling is required, reservoir pressure determines the drilling fluid density. Underbalanced drilling is often used to denote drilling in the reservoir with inflow from the reservoir and also to define drilling with multiphase fluid, such as nitrified liquid or foam, even though bottomhole pressure may be above pore pressure. Depending upon certain conditions, lower density drilling fluid, nitrified drilling fluid, air/foam drilling fluid, or gas lift from the annulus may be used to reduce the hydrostatic fluid column inside the well and achieve underbalance. When underbalance techniques are used, the selection of surface equipment and downhole tools used for data telemetry must be altered accordingly to compensate for aerated fluids.
- #24 Reference: IT Module CT Drilling reservoirs are subject to damage (such as a formation with clay that would be sensitive to water), reservoirs are depleted or underpressured (so that the reservoir can be drilled through without extreme losses of drilling fluids) reservoirs are susceptible to drilling problems such as loss of circulation and differential sticking, a reservoir is relatively competent and drilling performance can benefit from increased rates of penetration, and real-time reservoir evaluation can aid in decision-making (for example, prematurely abandoning a wellbore due to water production to save money on evaluation and completion).
- #32 This surface layout will vary depending on the requirements of the specific job and the equipment available. At the very minimum the required equipment will be a crane truck, CTU, pump system, fluids handling equipment and MWD cabin. The location size can be as small as 8000 sq ft. The standard equipment for the coiled tubing unit will be an injector capable of pulling 80K lbs, and a open loop high pressure powerpack. The reel should be capable of handling the amount and OD of the coiled tubing needed to TD with 1000 ft additional CT. The types of pumps used are fracturing or cementing pumps with remote control capability and flow rates from 0.5 bpm to 8 bpm. The fluids system can vary significantly and it is avdised to coordinate with a local mud conditioning company to determine the requirements for each specific job. At a minimum tanks are needed with a sufficient volume as per Standard 22a, a degasser, a centrifuge and a mixing hopper.
- #34 Reference: IT Module CT Drilling The well control equipment typically includes: blowout preventers (ram-type and annular), accumulator units, stripper (ram-type or radial), kill lines, check valves, and chokelines and manifolds. 5.3 Returns Handling Equipment The fluid handling equipment can include: • a mud return line (lines between the annular section and return tanks), • mud tanks, • a shale shaker (removes large cuttings), • a centrifuge, • a degasser (poor boy or vacuum), • desander, • desilter, • sample catcher, • a separator (optional), and • a mixing hopper. Normally, there are three functions that are needed for mud tanks: • a settling tank for mud from the well and the shaker, • an active tank for mud going into the well, and • a reserve tank for new or heavier mud. Separators are used if gas or oil is produced while drilling and are positioned so that all flow returning from the well must first pass through the separator. 5.4 Pumping Equipment Coiled tubing drilling requires long periods of continuous pumping of drilling fluids and doesn't normally employ the same high- and low-pressure pumping equipment used in other Schlumberger applications. Plunger pumps capable of pumping drilling fluid for long, uninterrupted periods of time are used, similar to those used in conventional drilling operations. In order to reduce personnel required, mud pumps are positioned with controls in the coiled tubing cabin so that the operator can start and stop the pumps as may be required to operate orienting tools and other downhole equipment. 5.4.1 Pump Pressure Pump pressure is a function of: • pump rate, • fluid composition, • length of coil, and • flowing friction inside the coil and in the annulus. Typically, pump pressure is reduced through the use of multiphase fluid. A maximum desired pumping pressure for pipe that does not remain on the reel is approximately 4000 psi. 5.5 Monitoring and Recording Equipment In addition to the conventional coiled tubing unit instruments, coiled tubing drilling requires drilling-parameter instruments for information about activities downhole and flow-parameter instruments to monitor rates of return. The CoilCAT* system is normally used for monitoring and recording drilling parameters from the coiled tubing unit, and is integrated with downhole tool measurements to provide a full monitoring package for efficient operations. The CoilCAT system communicates depth, pumping pressures, and surface weight measurements to the IDEAL system (Anadrill) where it is combined with downhole measurements of direction, inclination, gamma ray, and other sensors to provide accurate data for plotting and monitoring the directional drilling progress and geologic correlation to drilled formations downhole.
- #36 Reference: IT Module CT Drilling Normally, there are three functions that are needed for mud tanks: a settling tank for mud from the well and the shaker, an active tank for mud going into the well, and a reserve tank for new or heavier mud. Separators are used if gas or oil is produced while drilling and are positioned so that all flow returning from the well must first pass through the separator.
- #37 Reference: IT Module CT Drilling Pumping Equipment Coiled tubing drilling requires long periods of continuous pumping of drilling fluids and doesn't normally employ the same high- and low-pressure pumping equipment used in other Schlumberger applications. Plunger pumps capable of pumping drilling fluid for long, uninterrupted periods of time are used, similar to those used in conventional drilling operations. In order to reduce personnel required, mud pumps are positioned with controls in the coiled tubing cabin so that the operator can start and stop the pumps as may be required to operate orienting tools and other downhole equipment. Pump Pressure Pump pressure is a function of: pump rate, fluid composition, length of CT flowing friction inside the coil and in the annulus. Typically, pump pressure is reduced through the use of multiphase fluid. A maximum desired pumping pressure for pipe that does not remain on the reel is approximately 4000 psi.
- #38 Reference: IT Module CT Drilling Monitoring and Recording Equipment In addition to the conventional coiled tubing unit instruments, coiled tubing drilling requires drilling-parameter instruments for information about activities downhole and flow-parameter instruments to monitor rates of return. The CoilCAT* system is normally used for monitoring and recording drilling parameters from the coiled tubing unit, and is integrated with downhole tool measurements to provide a full monitoring package for efficient operations. The CoilCAT system communicates depth, pumping pressures, and surface weight measurements to the IDEAL system (Anadrill) where it is combined with downhole measurements of direction, inclination, gamma ray, and other sensors to provide accurate data for plotting and monitoring the directional drilling progress and geologic correlation to drilled formations downhole.
- #43 Reference: IT Module CT Drilling
- #44 Reference: IT Module CT Drilling For vertical wellbores, a small amount of drill collars (typically 2 or 3) can be used to assist in maintaining a straight wellbore. The size and exact length varies with the hole size being drilled. The resulting "pendulem" effect is most effective when drilling softer formations or when minimal weight on bit can be used to drill effectively. No stabilizers are normally run during coiled tubing drilling. Spiral downhole collars are preferred due to their reduced sticking tendencies.
- #45 Reference: IT Module CT Drilling Check valves are run to prevent back flow into the coiled tubing that could cause plugging of the BHA. They also provide an internal safety barrier for the coiled tubing in the event of a well control event
- #46 Reference: IT Module CT Drilling The hydraulic release mechanism (or joint) is operated by dropping a ball from surface inside the coiled tubing. When the ball reaches the fishing tail, the pressure rises because the ball seats against a piston, which stops the flow. This pressure then shears a set of brass pins holding the piston in place, the piston shifts, and the joint is released. Other types of release mechanisms include: shear pin mechanical releases (generally not used, as the torque and vibrations during the drilling operation tend to weaken the pins) multicycle disconnect release (movement of the CT string above the stuck BHA element is used to operate the release mechanism)
- #47 Reference: IT Module CT Drilling The most commonly used downhole motor is a positive-displacement motor (PDM). The PDM is driven by the drilling fluid that passes through the motor. The fluid passes through a rotor/stator section (similar to a spiral) and causes rotation of the inner rotor. Other motors are sometimes used in special applications where extreme temperature or other parameters are unfit for a PDM. Those motors include: turbines vane motors Here is a positive-displacement motor. These motors come in different configurations of rotor/stator ratios and number of stages which affect their speed and torque capabilities. Typically, higher-torque motors are preferred for coiled tubing drilling. In positive-displacement motors, there are two types of bearing sections: Turbines produce high speed; however, they can be used with gear reductions to reduce speed and increase torque. Turbines employ multiple sections of rotating blades that are activated by fluid passing through the motor. Due to the multiple sections, turbine motors typically operate at pressures three to four times higher than PDM motors. Vane motors are typically made of metallic and ceramic/composite materials, and require very clean fluid to operate. They use vanes, similar to the design concept in a rotary engine that turn via high-pressure and low-pressure areas due to injection/exhaust ports Some are fluid lubricated by leaking small amounts of the drilling fluid through them. Some contain sealed bearings, which do not require drilling fluid for lubrication.
- #48 This illustration shows a typical bottomhole assembly for directional drilling. From the bottom up, a typical directional-drilling bottomhole assembly could include the following: coiled tubing connector float sub (check valves) downhole instrumentation (e.g., downhole pressures, GR, CCL) nonmagnetic housing for surveying instrumentation with wireline, mud pulser, or electromagnetic telemetry orienting tool release tool (optional) UBHO (universal bent housing orienting) sub (if required) drilling motor with bent housing Bit
- #49 General types of Bottomhole Assemblies Two general types of bottomhole assemblies are used to perform directional drilling operations: wireless telemetry and wireline telemetry 4.2.1.1 Wireless Telemetry BHA Wireless telemetry can be performed using either mudpulses or electromagnetic signals to communicate measurements from the BHA to the operator at the surface. Both systems are convenient, in that the directional drilling assembly can simply be attached to the end of the coiled tubing and sensors placed at the surface to receive the data at the surface. Full access through the coiled tubing is possible, so many of the drop-ball activated tools used with non-steered BHA's are useable. 4.2.1.2 Wireline Telemetry BHA Wireline telemetry, as the name implies, uses a direct, wired connection to communicate measurements down the BHA to operators at the surface. These "e-line" systems use a hardwired connection from the downhole tool, through the coiled tubing reel, and through a collector ring on the coiled tubing reel, which allows much higher data-transmission rates than either of the wireless telemetry systems. Because a wireline now passes through the BHA and coiled tubing, special tools are needed to disconnect and perform other functions downhole. Both the electromagnetic and wireline systems can be operated while using multiphase flow in the wellbore.
- #51 This slide shows performance specifications for the SlimPulse MWD system and a tool diagram. While it is important to emphasize several points about the SlimPulse MWD tool (servo pulser anti-jamming feature, battery power conservation technology, hot hole capability to 175 degC, configuration adaptability for battery on top or bottom) the Curvature specification deserves some explanation. Essentially the collars that are used to house the SlimPulse MWD tool will dictate the build rate capability … collars are the limiting factor to consider. But before we tell all our clients that a SlimPulse CTD BHA can be used for a 100 deg / 100 foot curve (and this is true when considering the SlimPulse MWD by itself), we need to consider that two of the other essential elements of the CTD BHA cannot drill at these build rates. Specifically the SLB 3-1/8” Drilling Connector has shown good performance up to 40 deg / 100 feet but beyond this we have noticed some stress cracks in the internal 2.06” stub acme pins. Efforts are currently underway to change to 2-3/8” API connections within the 3-1/8” Drilling Connector which should safely allow build rate capability to 50 deg/ 100 feet. The other BHA component that should be considered is the mechanical orienter currently provided by Sperry Sun and Weatherford in Prudhoe Bay. Each of these orienters have shown operational difficulties at higher build rates and applications above 40 deg / 100 feet should not be attempted without considerable scrutiny. Fortunately the TORC system, meant to replace these mechancal orienters is designed for build rates exceeding 50 deg / 100 feet.
- #52 These are the summary bullet points for the SlimPulse MWD system. For further information please refer to the following URL on the SLB Hub: http://www.hub.slb.com/index.cfm?id=id12301
- #55 Reference: IT Module CT Drilling Fixed cutter bits have no bearings and no rotating parts. They use a shearing action similar to machining to cut the rock and have cutting edges that cut as they are rotated by the motor above. The most common drag bits are PDC (Polycrystalline Diamond Compact), which are used for soft-to-medium formations TSP (Thermally Stable Polycrystalline), which are used for medium-to-hard formations Diamond, which are used for hard formations PDC refers to the cutter that is mounted on posts. TSP uses synthetic diamonds set in a matrix. They are typically less aggressive than PDCs but can withstand harder, more abrasive formations. The gauge protection on a PDC bit is typically made from thermally-stable diamond or tungsten carbide inserts. Fixed cutter bits can be rebuilt (or redressed) and used again. 4.1.6.2 Roller-cone bits come in a variety of configurations. They can be found with as few as one cone to as many as four on larger bits; however, the most common configuration is the three-cone, or tri-cone, bit. The teeth are either milled steel or tungsten carbide inserts with various nozzle configurations to assist in debris removal. Many of the new designs can also be found with diamond-coated cutters to aid in wear resistance. Bearings range from nonsealed roller bearings to sealed journal bearings. Typically, the sealed journal bearings are recommended for most coiled tubing drilling applications, with the exception of some vertical deepenings and scale-cleanout operations where short drilling times are anticipated. Gauge protection is important when using these bits in horizontal wellbores.
- #60 Reference: IT Module CT Drilling Window milling refers to cutting casing to begin directional drilling. As discussed above, this can be done conventionally or through tubing. Typically, mills are used to mill steel (either windows or junk or scale, etc.), but are generally poor for drilling most formations. Mills can also be used to mill cement, such as for cement plug kickoffs. Here is a typical whipstock. The whipstock is a hard metal device set in the casing that guides the mill into the side of the casing. The mill produces a cut or window in the casing. Here is a cement plug kickoff. In this case, a very hard tough cement plug is set. The plug usually contains fibers to maintain its integrity when drilled. A pilot hole is then drilled, and the string is pulled out of hole. A bent housing motor and directional drilling assembly is then used to drill through the casing by using a "time drilling" technique. This technique, along with specially designed wells to assist in cutting the casing, has proven to be a reliable alternative when whipstocks cannot be used. Drilling can then continue through the window - care must be used when passing the bit and BHA through the window to prevent damaging the remaining cement around the exit window. This is also a combination cement plug and whipstock configuration. This illustration shows both the side-cutting mill, or "speed mill", used to cut the casing and the "watermellon mill" used to expand and dress the window. This illustration shows a typical window-milling bottomhole assembly with whipstock, watermelon mill, and speed mill, compared with a conventional bottomhole assembly. After milling the window through the casing of the well, the directional drilling assembly is then used to continue drilling in the formation to the reservoir target.
- #61 Special Purpose Bottomhole Assemblies There are a number of special purpose bottomhole tools used during coiled tubing drilling operations. These include drilling and fishing jars (which give extra pull by means of a "hammer" - type action when stuck or fishing) accelerators (which "accelerate" or increase the force of the jarring effect in either direction while absorbing the shock to the BHA or coiled tubing) underreamers (which have expandable cutting arms to create a hole with a wider diameter than the inside diameter of the tubing or casing string that must be passed through) float subs (which are check valves in the BHA) overshots or spears (which are used for fishing)
- #63 Reference: IT Module CT Drilling Coiled Tubing Drilling Fluids Requirements Drilling fluids issues for coiled tubing drilling are not much different from conventional drilling with a few exceptions: • Cuttings bed buildup can be more problematic with coiled tubing because of the lack of mechanical agitation normally provided by drill pipe rotation. • Coiled tubing has the ability to maintain continuous circulation and thus avoid the settling of cuttings that can be associated with discontinuation of circulation. • Circulating rates through the coiled tubing and associated BHA are usually lower than can be obtained with drill pipe, and this reduction in rates similarly affects the ability to lift and remove cuttings in some sections of the wellbore. These differences can be quite important when considering fluid design, particularly in horizontal wellbores. Drilling fluids with high gel strengths and carrying capacity are excellent for lifting cuttings in vertical wellbores; however, it is more difficult to achieve turbulent flow conditions, which are required to minimize cuttings-bed buildup in the horizontal wellbore. Drilling fluids that can achieve turbulent flow conditions easier are preferable for cleaning the horizontal wellbore; however, these drilling fluids are susceptible to cuttings dropout in the build section. The ability to maintain continuous circulation aids in minimizing this problem; however, this is still an area that is being studied and warrants improvement. In through-tubing coiled tubing drilling applications it is necessary to keep both the tubing and any casing below clean of cuttings buildup. This can be particularly challenging to accomplish with a single drilling fluid.
- #64 Reference: IT Module CT Drilling Fluid Hydraulics When drilling with coiled tubing, the flow rates are especially important, as they relate to the hole-cleaning requirements of the wellbore and the bottomhole assembly flow capacity. Some motors are equipped with a bypass (a port milled through the middle of the rotor) to increase fluid flow. These can work well when single-phase fluids are employed; however, they add significant complication to the use of multiphase fluids and are not recommended to be used in these applications. Motor specifications for fluid flow must be carefully considered during the job-design phase. The maximum allowable surface pressure of the coiled tubing and the pressure drop through the motor and other bottom hole assembly elements must be taken into consideration during the design phase to ensure sufficient hole-cleaning parameters are available with a given coiled tubing and well geometry.
- #70 Introduction to module The purpose of this module is to get attendees familiar with the general CTD Design and Planning Best Practices . Reference: CT operators Manual (See Monograph) Homework: YES - Homework is to be handed out at the end of the class on accumulator sizing NOTE: BOP & Stripper Assembly & Disassembly is required to be done to complete this module on OTS1 & STEP1
- #72 The table shows the comparison of varying the BHP by changing liquid and N2 rates , and how that affects the ROP . Not always the lowest BHP will translate in faster ROPs.