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7'' liner running and cementing

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A summary presentation of a 7" Liner job, demonstrating different components, mechanisms of liner hanger and other string components. Then a quick hint about cementing operation and some extra components involved in the job like the Handling equipment, VAM HT, ...etc.

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7'' liner running and cementing

  1. 1. With Eng. Ayman Rashad, WSL Eng. Ahmed Hamdy, NWSL
  2. 2. SCAB liner Backup slides Liner hanger OHL Casing handling equipment Casing accessories Cementing
  3. 3. Agenda • • • • • • • • • • • • • • • Float/reamer shoe Ball catcher Landing collar Liner hanger [flex-lock hydraulic rotating liner hanger] Liner setting mechanism Running tool & Releasing mechanism TD-2 rotating cement manifold [ball dropping sub, plug releasing lock & flag] Pump down plug & Wiper plug ZXP packer, setting mechanism & Packer Setting Dogs Subs Other accessories Cement job [ spherolite, tuned-light cement ] SAPESCO casing running equipment Back-up slides [VAM-TOP threads, BAKER-LOK, Dull grading & Lubraglide beads] 7” OHL actual Operation summary SCAB liner actual operation summary
  4. 4. Liner string components Detailed components [from down upwards] in the sequence of operation: • • • • • • • • • • Float/reamer shoe Ball catcher Landing collar Liner hanger [flex-lock hydraulic rotating liner hanger] Liner setting mechanism Running tool & Releasing mechanism TD-2 rotating cement manifold [ball dropping sub, plug releasing lock & flag] Pump down plug & Wiper plug ZXP packer, setting mechanism & Packer Setting Dogs Subs Other accessories
  5. 5. Float Shoe It provides two main functions: 1. The shape of the shoe helps to guide the liner through open hole. 2. Single or double check valves prevents backflow inside the liner.
  6. 6. REAMER SHOE with Dual float valve • • • • • • Eccentric nose design can climb ledges and negotiate other wellbore Rigid standoff stabilizer blades, combined with the cutting structure, clear a path for the casing or liner and most types of rigid centralizers installed above. blade cutting structure facilitates both rotating and reciprocating applications to ensure safe passage of casing and liners. Large flow-directed ports cover the entire wellbore during rotating and reaming and prevent channeling during cement pumping. Dual float valve prevents cement backflow. Aluminum nose enables fast drillout with PDC or tri-cone bits.
  7. 7. Tapered and offset tapered noses help casing pass severe ledges, obstructions, high angles, and previous sidetracks. These noses also help protect the float valves from being damaged from debris while running in the hole.
  8. 8. Ball catcher • • • A ported baffle used to stop sheared ball or plugs from resting on the float valve that may stop the valve from working properly. It’s also ported to allow normal circulation through it. It may be screwed as an individual joint or inserted.
  9. 9. Landing Collar • Includes: 1. An integral ball seat 2. liner wiper plug seat. • • When a setting ball is dropped and seated, pressure may be applied to activate hydraulic devices in the liner string, such as hydraulic-set liner hangers and external casing packers. Further increase in pressure shears out the ball and seat, restoring full circulation through the shoe for cementing operations.
  10. 10. Landing Collar with flapper by HALLIBURTON
  11. 11. LINER HANGER ASSEMBLY
  12. 12. Liner hanger assembly Liner top packer Liner hanger assembly, it consists of: • Liner hanger • Drillable pack-off bushing • Liner top packer • • These components remain in the wellbore and sold to customer Inside these components there is the liner running tool, that is rented to the customer as part of the liner installation service. Drillable pack-off bushing Liner hanger
  13. 13. The running/setting tool • • • • • The setting tool is used to connect the liner to the drill pipes. It carries the liner into the well and provides a reliable releasing mechanism when the drill pipe must be disconnected. There is a screen at top of running tool to allow clean mud into liner for pressure equalization without destroying or plugging any ports inside. Slick stinger: is a polished tool that seals inside the drillable pack-off bushing to create a pressure seal at the liner top during the setting process. The wiper plug is attached to the end of the running tool assembly. Screen at top of running tool to allow clean mud into liner for pressure equalization without destroying or plugging any ports inside Drillable pack-off bushing Wiper plug
  14. 14. The most important part of the operation THE LINER HANGER
  15. 15. FLEX-LOCK III Hydraulic-Set Liner Hanger APPLICATION • hydraulic-set liner hanger series is capable of hanging exceptionally heavy liners. • corrosion-resistant alloys (CRAs) are used. • Differential pressure across an integral hydraulic cylinder strokes the slips into engagement with the casing. • The dramatic increase in hanging capacity over cone-type hangers results from state-of-the-art design and finite element analysis study. • Loads transfer circumferentially into the slip seat, rather than radially inward to the mandrel as the liner weight is hung. • High load stresses on the mandrel beneath the slips are avoided, preventing collapse of the hanger body under heavy loading. • Stress hot spots in the parent casing are eliminated.
  16. 16. FLEX-LOCK III Hydraulic-Set Rotating Liner Hanger APPLICATION • The FLEX-LOCK hydraulic-set rotating liner hangers incorporate a tapered roller bearing assembly that allows the liner to be rotated with the hanger in the set position while cementing the liner. • This bearing package allows the liner to be rotated at higher RPM than hangers using conventional ball or journal bearing systems. Tapered roller bearing
  17. 17. FLEX-LOCK III Hydraulic-Set Rotating Liner Hanger Advantages • Proprietary slip design results in substantially lower and more uniform stresses in both the parent casing and the hanger mandrel as axial load is applied • Kit hanger can be provided with mandrel or without, for mounting on casing of any weight, grade or thread • Hydraulic cylinder compatible with liner to meet NACE specifications when required • Premium hydraulic cylinder seals withstand up to 10,000 psi (689.6 bar) at 400°F (204°C) • Tapered roller bearings allow rotation of liner after setting, resulting in improved cement job • Double grip retrievable version available • Non left-hand rotating option for use with HRD-E setting tools ensures secondary release if required
  18. 18. Setting mechanism • • • • • • • • • After ball is dropped and seated in the landing collar…it allows pressuring up the string to set the liner hanger. As pressure is applied at the surface…the hydraulic cylinder of the hanger shears and strokes the slips up until they contact the casing wall. As the weight of the liner is slacked-off, the hanger slips transfers the load to the previous casing string. The liner is now hung, to regain circulation, the setting ball is blown out by increasing surface pressure to shear the pins in the seat, then sudden drop in pressure occurs as circulation is re-established, and well is circulated until steady and smooth pump pressure is obtained. Now we can release the setting tool, and that depend on its type. C2 liner setting tool > needs 10 right-hand turns, this disengages the float nut from special carrying thread profile in the body of the top liner packer. The drill pipe can now picked-up to ensure that the running tool is released, and thus we expect to see only the pipe weight on the weight indicator as the liner weight is now supported on the hanger. Only pick-up the liner hanger couple of feet as we don’t want to activate the packer setting device yet. Then slack off sufficient weight to ensure pack-off, we are now ready for the cement job
  19. 19. SB305-3A actual OHL setting parameters just to feel numbers on actual example Flex-lock hydraulic-set rotating liner hanger 1. 2. 3. 4. 5. 6. 7. 8. 9. Drop 1 7/16" bronze ball & chase same till land in landing sub, Press up to 2,200 psi to set liner HGR, Bleed pressure to 500 psi, Confirm HGR set by S/OFF liner wt + 30 Klb. Press up to 3,400 psi to shear ball seat & release running tool, Regain circulation with 4 bpm @ 700 psi. P/U string 3 ft, confirm running tool released (lost liner wt "80 Klb"). Slack off string 3 ft (drill pipes slack-off weight = 165 Klb) then set 30 Klb on liner HGR. Circulate & rotate liner with while prepare mix fluid.
  20. 20. TOP DRIVE CEMENT MANIFOLD…it contains: pump down plug, and its releasing lock, plug release flag, ball dropping sub and rotating bearing [in case of rotating CMT manifold TD-2] TD CEMENT MANIFOLD
  21. 21. Top Drive cement manifold In case of rotating TD-2 This part is static [connected to cement line] and the rest is rotating Hose from cement unit Plug release lock Pump-down plug Plug holding sleeve Plug dropping flag Ball dropping sub
  22. 22. TD2 rotating cement head All the TD2 body rotates with the string except for this part which is connected to the cement line Pump down plug releasing lock Pump-down Plug dropping flag Ball dropping sub
  23. 23. Top drive cement head • • • • • APPLICATION Cementing head is used to release a pump-down plug from surface at the desired time during cementing operations, without the need to break a tool joint connection or hammer union. The TD cementing head has standard tool joint connections to accommodate heavy liner loads. The pump-down plug is contained within a sleeve, with fluid flow bypassing around the plug Until the release lever is turned 180˚. The sleeve then shifts downward, releasing the pump-down plug. Internal fluid bypass eliminates the need for external valves and manifold.
  24. 24. Top drive cement head Advantages • Compact design holds pump-down plugs securely until release is desired • Innovative plug stop design eliminates potential for plug damage at the time of release • Internal bypass requires no external manifold, ideal for use with top drive or conventional rotary rigs • Easily stackable for multiple plug applications • Releasing mechanism is proven dependable over thousands of field runs Plug release lock Flow is diverted away around the plug .. Until lock is opened and plug is pumped
  25. 25. Positive Ball Dropping Sub • Baker Hughes’ positive ball dropping sub provides a convenient method to release a setting ball from the surface without breaking a drill pipe connection or removing a hammer union cap. Ball Releasing mechanism: • The ball is positively retained in a recess beside the flow stream, unaffected by the fluid flow until the ball is released by a simple turn of the release lever. • When the release lever is rotated approximately 300 degrees, the ball is positively ejected from the recess into the flow stream. The lever handle is locked until the time to drop the setting ball. • A counter-clockwise turn of the handle confirms the presence of the ball without risk of premature release.
  26. 26. ball dropping sub Plug dropping flag
  27. 27. Positive Ball Dropping Sub Advantages • Provides a positive means to release a setting ball into the running string at surface • Ball cannot be prematurely released with handle locked • Drops various standard-sized balls • Simple and reliable operation
  28. 28. Flag Sub • • • • APPLICATION The flag sub, placed below the plug dropping head, provides immediate visual confirmation that the pump-down plug has been released and has moved down the running string. The trip arm, or flag, is in the horizontal position across the flow stream before the pump-down plug is released. As the plug passes, the flag is moved to the vertical position. The flag can be reset to the horizontal position repeatedly when used with multiple pump-down plugs. Advantages: 1.Positive indication that plug has left the plug dropping head 2.Drillpipe connections standard to provide high tensile ratings
  29. 29. Conventional Liner Cementing Plug Systems APPLICATION • Cementing plug systems used in liner applications typically serve two basic functions: 1. They serve as physical barriers between the cement and other wellbore fluids as they are being pumped, while effectively wiping the cement from the tubulars that it's pumped through. 2. They confirm displacement volumes of both the running string and the liner. Visible pressure indications signal when the cement has been completely displaced from both the drillpipe and the liner casing.
  30. 30. Pump-Down Plug APPLICATION • The pump-down plug is used to wipe the running string behind (and sometimes in front of) the cement. • The pump-down plug may be used to latch into a liner wiper plug as described later, or can be used to wipe both the running string and the liner casing in smalldiameter liner applications. • Multiple darts may be used to more effectively wipe the tubulars and reduce cement contamination. Various wiper fin, nose, and latch configurations are available to fit a wide range of applications. Plug release lock Flow is diverted away around the plug .. Until lock is opened and plug is pumped When the lock is opened .. The sleeve moves down and this flapper opens to release the plug
  31. 31. Wiper Plug APPLICATION • • • • • Liner wiper plugs are used to separate cement from the displacement fluid during cementing operations. The Type I liner wiper plug is shear pinned to the bottom of the running string, below the liner setting tool and pack off. At the tail of the cement, a pump-down plug, is released and follows the cement down the running string. When the pump-down plug lands in the liner wiper plug, pressure is increased and shears the liner wiper plug free, allowing both plugs to be displaced as a unit to the landing collar. Both types of liner wiper plugs are manufactured of drillable materials, and are rotationally locked into the landing collar to prevent spinning during Drill out. This ring latches inside the landing collar to prevent the plug from rotation while drilling it
  32. 32. Now after completing displacing the cement, and check for back flow and all OK, it’s time to set the liner top packer *we used a ZXP packer for this demonstration+ ZXP PACKER SETTING
  33. 33. ZXP Liner Top Packer APPLICATION • liner packer is recognized industry-wide as today's premier high-performance liner top packer. • The innovative ZX seal element is designed and constructed to endure exceptionally high circulation rates and achieve high pressure and temperature sealing in the most demanding wellbore environments. Flow loop testing at over 17 BPM (2.7 m3/min) confirms durability of the ZX seal. • The packer is compression-set using a packer setting dog sub or a hydraulic pusher tool. • The ZXP liner packer is available with or without hold-down slips. • ZXP packers can be run on 2 RH, and HRD-E liner setting tools. • The ZXP liner packer is typically run as an integral component of the primary liner hookup. It may also be run in conjunction with a tieback seal assembly to serve as a tieback packer in the event remedial repair of the liner top is necessary. • Tieback extensions are commonly available in lengths of 6 ft (1.82 m) , 10 ft (3.04 m) , 15 ft (4.57 m), and 20 ft (6.09 m) .
  34. 34. ZXP Liner Top Packer cont’d Advantages • Most extensively tested packer on the market • Rugged proprietary seal element design resists swab off at high circulation rates and mechanical damage • Allows liner to be run in hole much faster than conventional liner packers, saving rig time • Aflas* (Asahi Glass of Japan) outer cover material compatible with most wellbore environments • Available with and without hold-down slips • Available with all current running tool profiles • Can be run with seal assembly as a tieback packer to isolate leaking liner top • Standard service for many sizes is 10,000 psi (689.6 bar) at 400°F (204°C) ; high-pressure/high-temperature-rated tools available upon request
  35. 35. ZXP setting mechanism • Now we have the cement in place, we are ready to set the liner top packer To do this: 1. Pick-up the drill pipe several feet [ in this case 10’+ [remember the running tool is already freed when setting the hanger itself] 2. expose the spring loaded dogs in the packer setting dog sub 3. And apply set-down weigh of the drill pipe 4. When sufficient weight has been applied to shear the setting pins in the packer 5. Compression will energize the seal element and engages the hold-down slips into the casing wall. 6. The packer is now set, and will provide an effective annular seal the liner and the previous casing string. 7. We may circulate out the cement at the top of liner. ZXP elastomer hold-down slips
  36. 36. Packer Setting Dogs Sub It’s designed to apply set down weight to mechanically set liner top packers like ZXP. A set of spring loaded dogs are used to transfer the set down weight from the drill string to the liner setting sleeve on the liner packer. APPLICATION • Packer setting dog subs are used to activate and pack off compressionset liner top packers. • Multiple spring-loaded dogs are compressed within the packer extension throughout liner running and cementing. • At the appropriate time, the setting dog sub is raised out of the packer extension and the dogs expand out to the OD of the extension. • Setting force is transferred through the dogs and onto the packer extension as drillpipe weight is slacked off.
  37. 37. OTHER ACCESSORIES
  38. 38. Insert Liner Cementing Equipment • • once installed, is permanently anchored and sealed in place. The desired accessory is threaded into the bottom or top of the seal unit, as appropriate. The seal unit is a compact aluminum module with a 360 degree aluminum slip. The unit also includes elastomer and metal-tometal seals. Insert cementing float valves are designed and tested to satisfy API Recommended Practices 10F specifications installation • Depending on the required component configuration (packoff, landing collar, float valve, etc.), accessory components are added to the bottom or top of the seal unit. • After the insert unit and its setting tool are positioned inside the liner joint, hydraulic pressure from a small hand pump is applied to complete the setting process. • The setting tool is then removed, and the liner joint is marked with accessory position and description.
  39. 39. Insert Liner Cementing Equipment Advantages • Modular insert seal unit easily converts to landing collar, float collar, guide/float shoe, drillable packoff, or ball catcher sub • Simple and reliable installation can be performed at the wellsite • Eliminates multiple premium thread charges and expensive corrosion-resistant collar bodies • Manufactured from drillable aluminum and phenolic components
  40. 40. Insert Liner Cementing Equipment
  41. 41. CEMENTING JOB
  42. 42. Spherolite • • • Hollow glass microspheres made from a low heat conductivity glass composition containing a high vacuum and thin metal coating deposited on the inner wall surface. It can be used to make a superior insulation materials in construction of highly efficient solar energy collectors and insulation systems. Also as filter materials in plastic, plastic foam and in concrete and asphalt composition.
  43. 43. Tuned Cementing Solutions (TCS™) Lightweight Systems • Halliburton enables you to choose from all three primary categories of lightweight cements, so your choices can be based on your requirements, such as: 1. Water-extended– Use water-extended slurries when cost is your primary concern. These slurries can provide the required levels of fill if conditions are not too demanding. 2. Hollow microspheres – Use Tuned Light™ (hollow microspheres) slurries when high strength or achieving the lowest permeabilities are the main drivers or when a premium cement is required and foam is not an option. 3. Foam – Use the Zoneseal® Isolation Process (foam cement) when gas migration or shallow water flow potentials are problems. Foam is also the best choice when long-term stress protection is a primary driver.
  44. 44. Tuned Light™ XL Cement Blend Quick-setting, High-Strength, Lightweight Cement Blend for Problem Top-Hole Jobs • • • Halliburton Tuned Light XL cement blend contains carefully selected additives that produce lightweight slurries with strengths equal to or better than standard accelerated 16 parts per gallon (ppg) Class G cement slurries at the low temperatures found in the North Sea mud line. At a nominal Tuned Light XL slurry weight of 12.7 ppg, the initial set at 50°F is just three hours while the first compressive strength reaches 5,000 psi. Tuned Light XL slurries are also mildly thixotropic, which minimizes fallback in situations where surface gas is a potential problem. These special properties are extremely important in areas where operators often drill through formations near the surface that are weak and nonconsolidated. These formations tend to break down because their fracture gradient cannot withstand the normal cement slurry weight of 16 ppg. The result is cement losses and inability to bring cement up to the mud line. Remedial treatments to top-up the primary job involve rig time, more cement and longer waiting-on-cement (WOC) time. Conventional lightweight slurries may solve the problem of losses, but do not develop adequate strength to endure the stresses on the conductor casings. In addition, it is important to consider the low temperatures of 40- to 50°F usually encountered in the North Sea seabed
  45. 45. Tuned Light® Cement Important Benefits • Low Density. Tuned Light XL slurries are mixed and field-proven at a wide range of densities, maximizing seabed returns and reducing the need for remedial top-up jobs. • Thixotropic. The Tuned Light XL slurry will gel up in approximately one hour and softy set in about three hours. In effect, this means that the casing can be released within three hours of the time the job ends. • Faster Transition Times. The Tuned Light XL slurry’s zero gel time, measured with Halliburton’s Mini Macs™ analyzer, was 20 minutes. The transition time was determined to be 10 minutes at 55°F and 500 psi. Based on Halliburton’s accepted guidelines on gas migration, the Tuned Light XL slurry qualifies as gas-tight for low gas flow potential (GFP) factors. • Compressive Strength. Supporting the conductor is critical. Tuned Light XL slurries develop compressive strength at low densities and cool temperatures that exceed conventional slurries under the same conditions.
  46. 46. Cement silos • There are three silos for cement on the rig and another three for Barite. • They are all connected together and to the supply line from the boat. • Silo capacity is measured be weight cell mounted on bottom of it and connected to gauge that displays the weight in thousands pounds. • Cement is transferred to the unit by carrying it with pressurized air, depend on the vacuum pressure that air induces when passes near the powder cement. • Also the silo itself is pressurized to force cement out of it. • Air supply should be opened first before opening the cement line
  47. 47. To Cement unit Barite silos Cement silos
  48. 48. Pressure gauge inside silo Vent Fill up AIR DISCHARGE WEIGHT GAUGE To indicate tank fillage HIGH PRESSURE LINE LOAD CELL
  49. 49. Cement from boat Air CMT Silo Hall Batch Mixer Hall Mix on fly unit
  50. 50. CASING HANDLING EQUIPMENT
  51. 51. SAPESCO handling equipment • • • • • • • • • • Rotary hand slips Safety clamp Single joint elevator Spider slips [pneumatic] Spider elevator [pneumatic] Side door elevator HYT elevator [tubing] Drifts Stabbing guide Thread protectors • • Jam unit Wincatt software
  52. 52. Power tong with side door Revolution High/low gear control Hydraulic piston used to hang the tong in the air tagger to dampen vertical vibrations and bouncing *shouldn’t be placed here+ 1.25” pressure line INLET 1” pressure line outlet Side door with safety control Revolution counter
  53. 53. Stabbing guide Thread protector This part rotates and [with the dies] everything else is static Some of CSG running equipment This handle rotates the tong Main motor that drives the tong
  54. 54. JAM system Joint Make-up Analysis system • JAM - Joint Analyzed Make-Up. Yes it is a computer system that is used to graph each joint on make up. A load cell is stuck on the tong to snubbing line, this measures torque like the old torque gauge and a turns counter on tong rotor counts the turns. Computer is set up with figures of pipe type minimum and optimal torque and shoulder values. Once the joint makes optimum torque a dump valve will kick in so joint can not be over torqued. Used alot on chrome and completions..... • Also referred to as "torque turn" graph display enables you witness the amount of turns vs the amount of torque through the connection makeup. Interpretation of these graphs determine whether the connection makeup is acceptable or not. How the seals engage or not etc. With todays sophisticated connections with shoulders and seals this practice is essential.
  55. 55. JAM system Key features: 1. Monitors torque during makeup 2. Controls final torque 3. Records about 1,000 connections 4. Displays torque value 5. User can input different handle lengths 6. 500 samples per second 7. Made for non-premium API connections 8. Torque downloadable to PC after each job Included hardware: 1. Dump valve cable 2. Power cable 3. CT cable 4. High capacity junction box with pressure transducer
  56. 56. JAM chart axis-1 of your graph shows no. of turns usually to within 1/100 turns axis-2 generally indexes 3-torques per graph, shoulder torque to where connection "shoulders", delta torque to where additional torque past shoulder to final torque.
  57. 57. JAM chart Max. Torque Optimum Torque Torque Min. Torque Max. shoulder Shoulder point Min. shoulder Time/Turns
  58. 58. WinCatt™ • • WinCatt™ is a software tool which interacts with external control hardware to provide real time monitoring and control of tubular connection power tong make-up. The graphical user interface and logical software structure combined with powerful control, data acquisition and presentation capabilities enable the user to easily specify make-up parameters, control the make-up process and evaluate quality. WinCatt™ was developed with an emphasis on the user's needs for reliability, accuracy, and ease of use. KEY FEATURES ARE: 1. monitors torque, turns, and rotational speed during make-up 2. controls speed during make-up (optional) 3. controls based on either final torque or final turns 4. includes calibration management system 5. includes automatic "Start Recording" & "Dump Valve Release" 6. includes automatic descriptive comments with optional over-ride 7. available with optional pressure test system
  59. 59. Dump valve assembly WinCatt™ High capacity junction box with pressure transducer Dump valve cable
  60. 60. Minor details while operation BACK-UP SLIDES
  61. 61. Back-up slides • • • • • LubraGlide® BEADS – Advantages, concentrations & Uses VAM-TOP thread – Normal VS. high torque BAKERLOK® Thread-Locking Compound Dull-bit grading for the 8 ½” bit used in SB305-3A Diaphragm pump
  62. 62. LubraGlide® BEADS It’s MECHANICAL lubricity in the hole. Advantages • Reduces torque and drag • Reduces casing wear • Is non-abrasive • Is recoverable & environmentally safe • Is thermally stable up to 500°F • Is compatible with both oil and water base mud • Is Resistance to deformation is greater than 25,000 psi hydrostatic, • Thermally stable down hole to 500°F in a drilling environment “CE’’ CO-POLYMER
  63. 63. LubraGlide® BEADS Concentrations: • Concentrations of 2 – 8 ppb (5.71 – 22.87 Kg/m3) recommended to control torque and drag • Concentrations of 8 –12 ppb (22.87 – 34.31 Kg/m3) recommended for spotting in wire-line operations and running casing • The optimum concentration of Lubra-Glide beads is ten (10) pounds per barrel. • The volume of fluid to be treated is calculated based on the volume necessary to cover the open hole from the bottom of the hole to a point approximately two hundred (200) feet above the kick off point in the open hole. • If the kick off point is already behind casing, then the entire open hole volume should be treated.
  64. 64. LubraGlide® BEADS Typical Uses for LUBRA-GLIDE CE CO -POLYMER BEADS® • Spot in hole prior to running casing or liners • Spot in hole prior to logging operations • Allows more true weight to bit • Spot in key seats to reduce torque, drag, and sticking problems • Apply LUBRA-GLIDE CE CO-POLYMER BEADS® fine beads for torque and drag in coil tubing operations or with work strings • Lubricant for OBM or SBM • Aids in prevention of differential sticking when using OBM or SBM • Aids in directional changes or sliding
  65. 65. Energized metal-to-metal seal • A patented metal-to-metal seal system offers excellent gastight sealing, under even the most severe combined loads, as encountered in deviated or long horizontal wells. • The seal integrity remains constant after repeated make-ups and break-outs. • The seal geometry protects against galling. Improved hook thread design • A modified hook thread profile with 3° reverse angle on the load flank, not only provides the connection with superior tension strength but also increases its resistance to compression. • The excellent structural strength including increased bending and compression resistance, makes this connection especially suited for highly deviated and long horizontal wells. • Optimized thread geometry minimizes the risk of galling, even when thread lubricants are poorly applied.
  66. 66. Reverse angle torque shoulder • A reverse angle torque shoulder provides a positive torque stop which allows for accurate power-tight make-up and minimizes hoop stresses in the connection. • The “wedge” effect caused by the reverse angle gives the connection superior structural strength. • The shoulder design is optimized in order to resist adverse conditions such as combined compression and external pressure or combined bending, compression, and torque.
  67. 67. VAM® TOP HT Based on the main features of the VAM® TOP connection. This connection provides reinforced torque capability for liners and where High Torque is anticipated (torque rotating liner while running, rotating casing when cementing) The torque shoulder dimension on VAM® TOP HT is significantly larger than VAM TOP which enables the connection to withstand combined load for various applications using high torque
  68. 68. The detailed actual sequence followed on SB305-3A as a guide for future operations 7” OHL OPERATION SUMMARY
  69. 69. 7” OHL Operation summary 1. 2. 3. 4. 5. Conditioning the hole before running Running the liner Setting the liner hanger 7” OHL CEMENT JOB Setting the ZXP packer
  70. 70. Conditioning the hole before running • • • • On the last trip out of hole before running the liner: Sweep hole with 50 BBL HVP while rotate and reciprocate string Continue circulate until returns are cuttings free. Sweep hole w/ 50 BBL inhibited WBM pill to surface - control sweeping rate while WBM pill against baba salt to induce more erosion/dissolving to salt. • Flow check then record torque on BTM with and without pump. • POH on elevator to casing window and record same parameters again inside casing • Spot LubraGlide® pill (120 BBLs Hi Vis pill on bottom), observe well stable and POOH.  We used LubraGlide® exclusively in this case to assist in running the casing in through BABA salt section to avoid sticking potentials.
  71. 71. Running the liner • • • • • • • • • • Change 5" top ram to 7" ram, retrieve wear bushing, pressure test & close shear ram while change top ram. Install wear bushing & diverter packer again M/U baker top drive plug dropping manifold, RU cement surface line, flush, pressure test, test top drive manifold then LD as one piece. RU 7" handling equipment. Apply Bakerlok thread-locking compound to all shoe track connections. Install 1 CENTEC centralizer per joint Install insert ball catcher in box of first joint of shoe joint, test float equipment in both directions. RIH with 7" liner & install pip tag at the desired depth. PU & MU 7" baker flex lock rotating liner hanger with ZXP packer & setting tool Tie back sleeve id =7.375", extension 10 ft Cont. RIH with 7" liner on HWDP and DP till TD, then PU & MU loaded cement manifold Circulate 1.5 times string capacity
  72. 72. Setting the liner hanger • • • • • • • • • Drop 1 7/16" bronze ball & chase same till land in landing sub, Press up to 2,200 psi to set liner HGR, Bleed pressure to 500 psi, Confirm HGR set by s/off liner wt + 30 klb. Press up to 3,400 psi to shear ball seat & release running tool, Regain circulation with 4 bpm @ 700 psi. P/u string 3 ft, confirm running tool released (lost liner wt "80 klb"). Slack off string 3 ft (drill pipes slack-off weight = 165 klb) then set 30 klb on liner HGR. Circulate & rotate liner with while prepare mix fluid.
  73. 73. 7” OHL CEMENT JOB • • R/U CMT surface line & test same to 400/4000 psi Batch mix CMT slurry in 100 BBL batch mixer Perform cement job as follow: • Pump 50 bbl 7.0 ppg pre flush w/ 4.0 bpm. • Pump 50 bbl 11.5 ppg tuned spacer ahead w/ 4.0 bpm. • With 98 bbl 12.5 ppg batch mixed cement (equivalent to 113 bbl 13 ppg down hole) “g” neat + 14% salt (302 sxs) with cement unit with 4.0 bpm. • Release 5” dp pump down plug (flag tripped). • Pump 5 bbl 13.0 ppg tuned spacer behind with 4.0 bpm. • Rotate 7" liner all the time while pumping CMT & displacement w/ 15 rpm
  74. 74. Setting the ZXP packer • • • • • P/U string 10 ft to activate ZXP setting dogs sub, slack off 70 klb on ZXP packer, PKR set. May see surface indication for PKR set [weight indicator greatly disturbed]. Maintain S/O wt. For 5 min on the packer. Pooh w/ baker liner setting tool ( 600 ft above expected TOC ) Drop foam ball, sweep hole with 50 BBL HVP, normal circulate 1.5 complete cycles while reciprocate & rotate string with 20 RPM and circulate with high GPM.
  75. 75. The detailed actual sequence followed on SB305-3A as a guide for future operations SCAB LINER OPERATION SUMMARY
  76. 76. SCAB liner operation summary • • • • • • • MU BAKER TD CMT manifold. RU cement surface line, flush, pressure test same to 500 / 5,000 psi. test top drive manifold / 5" DP single joint using cement unit to 500 / 5,000 psi, hold, OK, L/D same as one piece to be ready when pick-up again. RU SAPESCO 7" handling equipment PU BAKER ported TIE BACK SEAL ASSY. with three seal units, VAM TOP – 7” baker landing collar, – Installed insert orifice float valve at box end of the joint that is directly above tie back seal assy. & function test for insert orifice float valve and float collar. – Apply BAKER-LOK to all shoe track connections. – Install one aluminum tabulator each joint. M/U 7” x 9 5/8” HMC hydraulic set liner hanger, "HMC" 2HR type tie back sleeve (8.9 ft extension). R/D 7" scab liner SAPESCO handling equipment. RIH with 7” scab liner on 5" HWDP & 5" DP . PU & MU loaded cement manifold.
  77. 77. Test for tie back stem & sleeve • Circulate with 200 psi and slack off slowly to enter the ported TIE BACK STEM into the liner TIEBACK SLEEVE until pressure start to increase, stop the pump, mark the pipe (marker#1). • Continue going down to NO-GO while monitor stabbing of seal unit inside liner tie back sleeve on martin decker, Slack off 15 klb locating tie back sleeve ring mark the pipe (marker#2). • P/U string to normal P/U weight and test tie back stem seal to 500 psi from inside drill pipe, OK. • Bleed off pressure to 200 psi and while holding pressure pick up until observe a pressure drop.  Now we’re sure that the TIE-Back stem seals working OK everything is working fine • Circulate hole clean while prepare mix fluid and CMT slurry.
  78. 78. 7” SCAB liner Cement job • • • • • • • • • • • • Perform 7" scab liner cement job using HALL CMT unit as follow: Pump tuned spacer as spacer ahead Pump cement slurry, Release 5" DP pump down plug (flag had tripped). Pump tuned spacer as spacer behind Displace with 45 bbl., 16 ppg weighted OBM pill Displace with 10 bbl., 11.2 ppg OBM (pump down plug latch to wiper plug may or may not be observed). Displace with 27.5 bbl. 11.2 ppg OBM Pump 7.5 bbl., 16 ppg tuned spacer , will cover the liner top when drill pipe is out to reduce contamination with displacing mud. Displace with 45.5 bbl. 11.2 ppg OBM Displace with 10 bbl. 11.2 ppg OBM Bump plug at 1400 psi for 10 min, ok, bleed off pressure while sting in, had no return fluid.
  79. 79. Setting the SCAB liner hanger • Open lines back to cement unit displacement tanks while sting in with seal assy. Till had 10 klb S/Off WT and confirmed NO-GO (at marker#2),  Pressure up t/3200 psi and set 7" scab liner "HMC" hanger. Slack down liner weight plus 30 klb on setting tool and confirmed hanger set.  Pressure up t/3000 psi and release setting tool, bleed off pressure keeping relief valve open, check string p/u weight had drill pipe weight confirming RT free. • • • • P/U 5 ft with setting tool with no U-tube observed, R/D BAKER TD2 cement manifold, POOH 6 STD'S 5" DP above expected TOC. Drop Halliburton foam ball and conventionally circulate hole clean max. GPM POOH W/7'' baker liner running tool to surface and LD same. PU & MU 8 1/2" clean out assy. To clean-out top of scab liner.
  80. 80. References • GUPCO standard operations book. • Baker liner hanger tools brochure. • Halliburton casing accessories brochure. • http://www.halliburton.com/public/cem/contents/Books_and_Catalogs/TECH/Sect02_ce.pdf • FARR website http://www.mccoyglobal.com/tubular-products/view/kt5500
  81. 81. END THANK YOU KAMEL ELSAYED, DE BELLIHYKE@GUPCO.NET

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