Sigve Hamilton Aspelund: Coiled tubing underbalanced drilling

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Sigve Hamilton Aspelund: Coiled tubing underbalanced drilling

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Sigve Hamilton Aspelund: Coiled tubing underbalanced drilling

  1. 1. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  2. 2.  * geophysical well logging * under reaming following multistage underbalanced drilling * cement plug placing * emergency and fishing operations * selection criteria for well bore candidates * job planning and risk analysis * CT ground equipment * coiled tubing pipes * coiled tubing machinery (capillary units, injectors, reels etc.) * equipment for flow control and completion (drilling motors, drilling jars, intensifiers, reamers, Collars, etc.) * high tech drilling bits Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  3. 3.  Nitrogen equipment application for coiled tubing drilling * * * * * * gas liquid mixtures nitrogen compressor stations pumping units vaporiser systems for CT continuous circulation systems and agitators management and control systems Separation systems for drilling fluids * * * * * centrifuges hydrocyclones shakers pumps management and control Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  4. 4. Geophysical well logging - Schlumberger brothers, Conrad and Marcel, are credited with inventing electrical well-logs. - On September 5, 1927, the first “well-logA” was created in a small village named Pechelbroon in France. - In 1931, the first SP (spontaneous potential) log was recorded. Discovered when the galvanometer began “wiggling” even though no current was being applied. - The SP effect was produced naturally by the borehole mud at the boundaries of permeable beds. By simultaneously recording SP and resistivity, loggers could distinguish between permeable oil-bearing beds Managedimpermeable and pressure drilling systems. Multilateral wells. Coiled tubing nonproducing beds. underbalanced drilling.
  5. 5. Types of Logs a) Gamma Ray b) SP (spontaneous potential) c) Resistivity (Induction) d) Sonic e) Density/Neutron f) Caliper Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  6. 6. a) Gamma Ray    The gamma ray measures the natural radioactivity of the rocks, and does not measure any hydrocarbon or water present within the rocks. Shales: radioactive potassium is a common component, and because of their cation exchange capacity, uranium and thorium are often absorbed as well. Therefore, very often shales will display Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  7. 7. The scale for GR is in API (American Petroleum Institute) and runs from 0125 units. There are often 10 divisions in a GR log, so each division represents 12.5 units.  Typical distinction between between a sandstone/limestone and shale occurs between 50-60 units.  Often, very clean sandstones or carbonates will display values within the 20 units range.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  8. 8. b) SP (Spontaneous Potential) The SP log records the electric potential between an electrode pulled up a hole and a reference electrode at the surface.  This potenital exists because of the electrochemical differences between the waters within the formation and the drilling mud.  The potenital is measured in millivolts on a relative scale only since the absolute value depends on the properties of the drilling mud.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  9. 9. In shaly sections, the maximum SP response to the right can be used to define a “shale line”.  Deflections of the SP log from this line indicates zones of permeable lithologies with interstitial fluids containing salinities differing from the drilling fluid.  SP logs are good indicators of lithology where sandstones are permeable and water saturated.  However, if the lithologies are filled with fresh water, the SP can become suppressed or even reversed. Also, they are poor in areas where the permeabilities are very low, sandstones are tighly cemented or the interval is completely bitumen pressure drilling systems. Managed saturated (ieMultilateral wells. Coiled tubing oil sands). underbalanced drilling. 
  10. 10. c) Resistivity (Induction) Resistivity logs record the resistance of interstitial fluids to the flow of an electric current, either transmitted directly to the rock through an electrode, or magnetically induced deeper into the formation from the hole.  Therefore, the measure the ability of rocks to conduct electrical currents and are scaled in units of ohm-meters.  On most modern logs, there will be three curves, each measuring the resistance of section to the flow of electricity.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  11. 11. Porous formations filled with salt water (which is very common) have very low resistivities (often only ranging from 1-10 ohms-meter).  Formations that contain oil/gas generally have much higher resisitivities (often ranging from 10-500 ohms-meter).  With regards to the three lines, the one we are most interested in is the one marked “deep”. This is because this curve looks into the formation at a depth of six meters (or greater), thereby representing the portion of the formation most unlikely undisturbed by the drilling process.  One must be careful of “extremely” high values, as they will often represent zones of either anhydrite or other non-porous intervals. Managed pressure drilling systems.  Multilateral wells. Coiled tubing underbalanced drilling.
  12. 12. d) Sonic    Sonic logs (or acoustic) measure the porosity of the rock. Hence, they measure the travel time of an elastic wave through a formation (measured in ∆T- microseconds per meter). Intervals containing greater pore space will result in greater travel time and vice versa for non-porous sections. Must be used in combination with other logs, particularly gamma rays and resistivity, thereby allowing one to better understand the reservoir petrophysics. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  13. 13. e) Density/Neutron Density logs measure the bulk electron density of the formation, and is measured in kilograms per cubic meter (gm/cm3 or kg/m3).  Thus, the density tool emits gamma radiation which is scattered back to a detector in amounts proportional to the electron density of the formation. The higher the gamma ray reflected, the greater the porosity of the rock.  Electron density is directly related to the density of the formation (except in evaporates) and amount of density of interstitial fluids.  Helpful in distinguishing lithologies, especially between dolomite (2.85 kg/m3) and limestone (2.71 kg/m3  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  14. 14. Neutron Logs measure the amounts of hydrogen present in the water atoms of a rock, and can be used to measure porosity. This is done by bombarding the the formation with neutrons, and determing how many become “captured” by the hydrogen nuclei.  Because shales have high amounts of water, the neutron log will read quite high porositiesthus it must be used in conjunction with GR logs.  However, porosities recorded in shale-free sections are a reasonable estimate of the Managed pressure drilling systems. pore spaces that could produce water. Multilateral wells. Coiled tubing  underbalanced drilling.
  15. 15. It is very common to see both neutron and density logs recorded on the same section, and are often shown as an overlay on a common scale (calibrated for either sandstones or limestone’s).  This overlay allows for better opportunity of distinguishing lithologies and making better estimates of the true porosity. * When natural gas is present, there becomes a big spread (or crossing) of the two logs, known as the “gas  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  16. 16. f) Caliper Caliper Logs record the diameter of the hole. It is very useful in relaying information about the quality of the hole and hence reliability of the other logs.  An example includes a large hole where dissolution, caving or falling of the rock wall occurred, leading to errors in other log responses.  Most caliper logs are run with GR logs and typically will remain constant throughout  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  17. 17. Underbalanced drilling Though not as common as overbalanced drilling, underbalanced drilling is achieved when the pressure exerted on the well is less than or equal to that of the reservoir.  Performed with a light-weight drilling mud that applies less pressure than formation pressure, underbalanced drilling prevents formation damage that can occur during conventional, or overbalanced drilling processes.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  18. 18.  The negative differential pressure obtained during underbalanced drilling between the reservoir and the wellbore encourages production of formation fluids and gases. In contrast to conventional drilling, flow from the reservoir is driven into the wellbore during underbalanced drilling, rather than away from it. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  19. 19. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  20. 20.  Although initially more costly, underbalanced drilling, also known as managed-pressure drilling, reduces common conventional drilling problems, such as lost circulation, differential sticking, minimal drilling rates and formation damage. Additionally, underbalanced drilling extends the life of the drill bit because the drilling gases cool the bit while quickly removing cuttings. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  21. 21. To establish pressure control, a rotating control head with a rotating inner seal assembly is used in conjunction with the rotating table. An important factor to successful underbalanced drilling, drilling and completion operations must remain underbalanced at all times during operations. To accomplish this, pre-planning and onsite engineering are critical to the success of underbalanced drilling procedures.  Typically used for only a section of the entire drilling process, underbalanced drilling cannot be used in most shale environments Managed pressure drilling systems.  Multilateral wells. Coiled tubing underbalanced drilling.
  22. 22. Underbalance Gases  Gases used for underbalance include air, nitrogen and natural gas. Although it is not typical, if natural gas is recovered from the well, it can be reinjected into the well to establish underbalance, resulting in the most cost-effective solution for underbalanced drilling. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  23. 23.  Commonly used in under balance operations, nitrogen is preferred for its somewhat low cost of generation, scale of control and minimal potential for downhole fires. While pure nitrogen can be purchased, it is costprohibitive. Therefore, nitrogen is more commonly produced onsite with a membrane unit, resulting in a 95% level of purity. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  24. 24. Underbalance Techniques   There are four main techniques to achieve underbalance, including using light weight drilling fluids, gas injection down the drill pipe, gas injection through a parasite string and foam injection. Using lightweight drilling fluids, such as fresh water, diesel and lease crude, is the simplest way to reduce wellbore pressure. A negative for this approach is that in most reservoirs the pressure in the wellbore cannot be reduced enough to achieve under balance. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  25. 25.  The method of injecting gas down the drillpipe involves adding air or nitrogen to the drilling fluid that is pumped directly down the drillpipe. Advantages to this technique include improved penetration, decreased amount of gas required, and that the wellbore does not have to be designed specifically for underbalanced drilling. On the other hand, disadvantages include the risk of overbalance conditions during shut-in and the requirement of rare MWD tools. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  26. 26.  In performing the gas injection via parasite string, a second pipe is run outside of the intermediate casing. While the cost of drilling increases, as does the time it takes, this technique applies constant bottom hole pressure and requires no operational differences or unique MWD systems. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  27. 27.  A less common underbalanced application, nitrogen foam is less damaging to reserves that exhibit water sensitivities. While the margin of safety is increased using foams, the additional nitrogen needed to generate stable foam makes this technique cost prohibitive. Additionally, there are temperature limits to using foam in underbalanced drilling, limiting using the technique to wells measuring less than 12,000 feet deep. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  28. 28. Cement Plugs Cement slurry design. – Cement type and additives. • API class • Extenders, shrinkage, gas control, fluid loss control, formation and pipe adherence, spacers. • Volumes and excesses. • Placement method. – Location identification, – Depth control, – Spotting method (bailer, circulation, etc.), – Contamination control, – Testing requirements. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  29. 29. Cement Plug Placement Balanced method. • Modified balanced method. • Displacement from surface. • Two plug circulation. • Grouting – various. • Mechanical assistance. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  30. 30. Setting a cement plug Not as easy as it may seem • Position of the end of tubing (EOT) may not correspond to where the plug is actually set. • What are the considerations of setting a cement plug in mud? • Effect of fluid loss and cross flow on setting an effective cement plug? Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  31. 31. Setting Cement Plugs A near 100% reliable system if cross flow can be stopped. • Most cement plugs fail because of cross flow, density and viscosity mismatch, or failure to “break” the fluid momentum. • Full plug method described and field tested in SPE 11415 (published in SPE JPT Nov 1984, pp 1897-1904) and SPE Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  32. 32. Cement Plug Failure Many cement plugs fail for the same 4 reasons: 1. Cross flow cuts channels into the plug. 2. Cement is higher density that the mud – cement falls through the mud. Mud contamination of the cement may keep it from setting. 3. The mud is much lower viscosity than the cement slurry – cement falls through the mud 4. The open ended tubing produces a high momentum energy condition that the mud cannot stop – thus cement falls through the mud. The result of the last three is that the cement is spread out along the hole andManaged pressure drilling systems. a plug is never Multilateral wells. Coiled tubing formed. underbalanced drilling.
  33. 33. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  34. 34. How? 1. Use a simple tubing end plug with circulation to the side and upward but not downward. 2. Spot a heavily gelled bentonite pill below the cement plug depth. Pill thickness of 500- 800 ft (152- 244 m). 3. Use a custom spacer to separate the pill and the cement slurry. 4. Use a viscous, thixotropic cement with setting time equal to the job time plus ½ hr. Plug thickness of 300 to 600 ft (91 to 183 m) 5. Rotate the centralized tubing (do not reciprocate) during placement and gently withdraw at the end of the pumping. 6. WOC = 4 hrs for every 1 hour of pump time. Full details and field tests in SPE 11415. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  35. 35. Reasons for Cement Plug Failures • Contamination of the cement slurry with drilling mud during or immediately after placement. • Failure to place a viscous pill to stop downward movement of cement slurry. • Inaccurate knowledge of volumes required. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  36. 36. General Requirements • Onshore – 10 ft (3 m) plug on top of the well and casing cut 3 ft (1m) below the ground surface. • Mud between plugs (9.5 lb/gal). • Plug thickness minimum of 100 ft, plus 10% for each 1000 ft of zone. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  37. 37. Procedures • Remove salvageable equipment. – NORM scale present? Leave the pipe in the well? – What pipe is needed for a barrier? How effective? • Set, at minimum, plugs required by regulations. Don’t hesitate to go beyond requirements. • Test to limits required. • Cap and identify as specified. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  38. 38. Isolation of Open Hole • Cement Plug 100ft (30m) above and below lower-most shoe in open hole. • Cement retainer 50 to 100 ft (15 to 30m) above the shoe. Cement 100 ft (30m) below shoe and 50 ft (15m) of cement on top. • Tested to 15,000 lbs load or 1000 psi. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  39. 39. Isolation of Perforations • Cement Plug 100ft (30m) above and below perfs (or to next plug). • Cement retainer 50 to 100 ft (15 to 30m) above the perfs. Cement 100 ft (30m) below shoe and 50 ft (15m) of cement on top. • Permanent bridge plug within 150 ft (45m) of perfs with 50 ft (15m) of cement on top. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  40. 40. Isolation of lap joints or liner tops • Cement Plug 100ft (30m) above and below liner top (or to next plug). • Cement retainer or permanent bridge plug 50 ft (15m) above the liner with 50 ft (15m) of cement on top. • Cement plug 200 ft (60m) long within 100 ft (30m) of liner. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  41. 41. Finding and Repairing Channels in Cement Channels in cement occur from many causes: – Lack of effective pipe centralization, – Inadequate mud conditioning prior to cementing, – Ineffective cement displacement design and/or execution, – Excess free water in the cement, especially in a deviated hole (usually a cement mixing problem). – Excessive fluid loss from the cement slurry (generally results in low cement top), – Gas influx before the cement sets, – Cement shrinkage, – Etc. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  42. 42. Identifying Channels in Cement Sheath Numerous logging methods: – CBL and segmented CBL tools that scan around the wellbore, – Borax logging, Carbon-Oxygen logs, Sonic tools, etc. • Plug and packers with perforating. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  43. 43. Repair of Channels - Cement Squeezes Types (some names anyway) – Block squeeze – Cement Packer – Suicide squeeze – Breakdown squeeze – Running and Walking squeezes – Hesitation squeeze • What is used depends on both what is needed and the experience of the operator. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  44. 44. Surface Plug On-Shore – depends on local regulations. • Offshore – cement plug 150 ft (45m) long within 150 ft (45m) of mud line. Placed in the smallest string of casing that extends to the mud line. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  45. 45. Testing of Plugs Location of the first plug below the surface plug shall be verified. – Pipe weight of 15,000 lbs on cement plug, cement retainer, or bridge plug. – Pump pressure of 1,000 psi with maximum 10% drop in 15 minutes. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  46. 46. Risk evaluation Risk & unwanted incidents ranking  Systems in place  • Report incidents and near miss • Analyse material • Look for trends Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  47. 47. Risk definition   Risk=Practicable*Consequence Risk to  Personel  Environment  Material Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  48. 48. Mapping of HSE & risks  Register incidents: Positive and negative Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  49. 49. Cause assesment • Direct causes vs underlying causes • Cause perspective – Human – Technical – Organisational • 5 Whys technique – Look for underlying causes – Eliminate root of the problem Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  50. 50. HSE analyse QRA: Quantity Risk Assesment QRM: Qualitative Risk Matrix Safe job analysis – Chemical analysis Risk assesment promt card Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  51. 51. Risk reduction ALARP: As Low As Reasonable Practicable  BAT: Best Available Technology  Precation principles  Substitution principles  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  52. 52. Barriers – swiss cheese model The Barriere Concept BARRIERS; Technical, Qualifications, Procedures etc. INITIATING INITIATING CAUSE CAUSE ACCIDENT/ ACCIDENT/ LOSS LOSS Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  53. 53. We are all responsible for managing HSE Barrier 1 – HSE Policy & Leadership Hazard/ Risk Barrier 2 – Planning I was responsible for planning the operations safely Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  54. 54. Barrier 1 – HSE Policy & Leadership Hazard/ Risk Barrier 2 – Planning Barrier 3 – Supervision I turned a blind eye to some of the crew not following all the procedures as we had limited time to do the job I was responsible for supervising the maintenance work Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  55. 55. Barrier 1 – HSE Policy & Leadership Hazard/ Risk Barrier 2 – Planning Barrier 3 – Supervision Barrier 4 – Procedures I didn’t work safely and took short-cut to get the job done Accident I was responsible completing the work Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  56. 56. We all have a part to play Mngt Team Finance/Accounting Visible leadership promotes HSE culture ….. Resources allocated for effective implementation Resource budgets effectively tracked and managed Maintenance Maintain equipment and ensure that operational integrity is maintained SJA team Legal Legal requirements of projects identified and complied with Hazards identified and risk mngt plans implemented Drilling HR Competencies required for job are clearly identified IT/ Data/ Graphics Systems to control and securely store HSE critical information Risk management integrated to drilling programme HSE dept Contract Ensure that Company are Guidance and given the means to perform advisory support Managed pressure drilling systems. the job safely and efficiently Multilateral wells. Coiled tubing provided to underbalanced drilling. operations
  57. 57. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  58. 58. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  59. 59. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  60. 60. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  61. 61. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  62. 62. How Does Fishing Work?   There are a number of problems that can occur while drilling a well. Whether a drill string breaks and falls to the bottom of the wellbore or a bit breaks, accidents happen. Even pipe or a tool can fall from the rig floor into the bottom of the well. This stray equipment that has fallen into the well is referred to as fishor junk, and regular drill bits cannot drill through it. Should a fish fall into a well, fishing is required to remove it. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  63. 63. Fishing tools Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  64. 64. In order to perform fishing on a well, drilling must be shelved and special fishing tools employed. Each tool is specially crafted to perform a specific function, or retrieve a certain type of fish. Most fishing tools are screwed into the end of a fishing string, similar to drillpipe, and lowered into the well.  There are two options to recover lost pipe. The first is a spear, which fits within the pipe and then grips the pipe from the inside. On the other hand, an overshoot may be employed, and this tool surrounds the pipe and grips it from the outside to carry it up the wellbore.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  65. 65. When a fish is difficult to grip, a washover pipe or washpipe is used. Made of largediameter pipe with a cutting surface at the tip, washpipe is run in the well and then the cutting edge grinds the fish to a smooth surface. Then drilling fluids are pumped into the well to remove debris, and another tool is used to retrieve the remaining fish.  Sometimes, a junk mill and boot basket are used to retrieve fish from the wellbore. In this instance, a junk mill is lowered into the well and rotated to grind the fish into smaller pieces. A boot basket, also known as a junk basket, is then lowered into the well. Drilling fluid is pumped into the well, and the ground parts of the fish are Managed pressure drilling systems. raised into the basket and then towells. Coiled tubing by the surface Multilateral the boot basket. underbalanced drilling. 
  66. 66.  In order to recover casing that has collapsed within the well or irregularly shaped fish, a tapered mill reamer can be used. Permanent and magnetic magnets are employed to reclaim magnetic fish, and a wireline spear uses hooks and barb to clasp broken wireline. Additionally, an explosive might be detonated within the well to break the fish up into smaller pieces, and then a tool such as a junk bucket is used to retrieve the smaller items. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  67. 67.  When a fishing professional is unable to determine which fishing tool might work best to retrieve the fish, an impression block is used to get an impression of the fish and allow the professional to know with what exactly he or she is dealing. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  68. 68.  Fishing a well may take days to complete, and during this time, drilling cannot occur, although the operator is still responsible for drilling fees. Some drilling contractors offer fishing insurance, making operators not responsible for rig fees during fishing operations. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  69. 69. Statoil records first successful North Sea HP/HT coiled tubing milling job Telemetry proves critical for intervention at Kvitebjoern on Norwegian continental shelf  Statoil learned valuable lessons during the planning and execution of a high pressure/high-temperature (HP/HT) coiled tubing milling job on the Norwegian continental shelf (NCS) in the North Sea at Kvitebjørn field.  Kvitebjørn is a Statoil-operated gas and condensate field in block 34/11 with a reservoir at about 4,000 m (13,120 ft) with pressure of 770 bar (11,168 psi) and Managed pressure drilling systems. temperature of 160º C (320º F). Coiled tubing Multilateral wells.  underbalanced drilling.
  70. 70.  Well 34/11-A-9 T2 was drilled as a gas producer and during the final completion phase, it was not possible through pressure cycling to open the HP/HT isolation ball valve set in the 9 7/8-in. liner at 6,245.7 m (20,486 ft) MD/3,795.8 m (12,450 ft) TVD. After several failed attempts with wireline using mechanical override tools, it was decided to punch above it to allow well production passing the outside of the valve through the annulus between 9 7/8-in. liner and the 5½-in. tail pipe. However, the production performance was poor. A feasibility study evaluated ways to open or mill out the valve with the objective to improve the production characteristics and to allow access for future production logging. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  71. 71.   The decision was to mill the stuck-closed isolation ball valve using coiled tubing (CT). Statoil had not performed any HP/HT CT operations and the available experience was limited. To minimize uncertainty relating to depth determination during milling, a telemetry system ran at its operational pressure and temperature limits to provide realtime casing collar locator (CCL) readings in addition to downhole pressure and temperature data. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  72. 72. The Super 13% chrome, 110 Kpsi yield isolation ball valve was stuck closed at a deviation of 57.8º. Its ID when open is 4.25-in with a drift ID = 4.151 in. The EOF seating nipple at 6,223 m (20,411 ft) MD from the rig kelly bushing was ID = 4.31 in., which represents the minimum wellbore restriction from surface down to the ball valve depth.  The 34/11-A-9 T2 well is in the Statfjord formation with the top of perforations at 4,313 m (14,147 ft) TVD. The original prognosed reservoir pressure was 770 +45/-14 bar (11,168 + 653/-203 psi) and the downhole temperature at reservoir was 160º C. The shut-in wellhead pressure was 571 bar (8,282 psi) in March 2011. The expected downhole temperature at the ball valve was 145º C (293º F). The H2S and CO2 concentrations in the produced gas were less than 5 ppm and a concentration of 3.477 mol %, respectively.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  73. 73. A feasibility study including an onshore milling test evaluated the possibility of milling the isolation ball valve with an electrical mill assembly run on mono-conductor wireline cable. The report concluded with large uncertainty regarding the number of bailer runs necessary to remove debris above the valve and reach milling depth, as well as the lifetime for the electrical milling equipment at the very high downhole temperature. Based on this study and the low estimated likelihood of success (30 -- 40%), the Kvitebjørn license decided not to proceed with the wireline alternative.  New feasibility studies evaluated using CT, rigassisted snubbing, and the rig for opening or Managed pressure drilling systems. milling out the isolation ball valve.wells. Coiled tubing Multilateral  underbalanced drilling.
  74. 74. Wellbore schematic. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  75. 75. The CT alternative seemed to be feasible since similar jobs were performed at lower temperature and shallower depths, but the 15K psi well control equipment and CT string design would have to be specified and sourced specifically for the job.  The main drawbacks for the rig-assisted snubbing were the drilling crew's rig-assisted snubbing experience, rig-assisted snubbing personnel experience, ram-to-ram stripping experience, and HP/HT well conditions.  For the rig alternative, the main risks were gas migration to the surface in addition to more time and cost relating to killing the well.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  76. 76. Well control stack as built Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  77. 77.  It was decided that the primary method to be further evaluated and developed for removal of the ball valve restriction from the well would be CT, the secondary method would be rigassisted snubbing and the final method would be to use the rig. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  78. 78. Concept selection During the concept selection phase, the recommended method for deploying CT to remove the isolation ball valve from the wellbore consisted of the following steps:  Pre-CT job "pump and bleed“ operation. Displacing the wellbore from the current gas by repeatedly bullheading 1.044 sg 40/60% MEG/fresh water from the kill wing valve of the christmas tree and bleeding the gas that migrates to surface. The aim of this "pump and bleed" step was to reduce the surface shut-in wellhead pressure (SIWHP) to the minimum before running the CT. This had advantages in safety and operations.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  79. 79.  CT drift and cleanout run(s). The well was producing intermittently for few months through punched holes above the closed ball valve. It was suspected that fill and debris might have settled above the ball valve with the 11.5-m (38-ft) interval between the punched holes and top of the ball valve being particularly vulnerable. Offshore crane capacity limits and the long CT string needed to reach the ball valve at 6,245.7 m (20,492 ft) MD RKB, the maximum CT string size that could be shipped in one piece was 2- in. OD. The well completion from surface to approximately the ball valve depth was 7 in., 35 lb/ft tubing with a 6-in. ID. Therefore, it was impossible to generate enough turbulence in the annulus between the tubing and CT to lift any fill or debris when run in hole (RIH) with the milling bottom hole assembly (BHA) to mill the ball valve. It was decided to RIH first with a with venturi jet junk basket (VJJB) to drift and clean out the wellbore to Managed pressure drilling systems. Multilateral wells. Coiled tubing the top of the ball valve. underbalanced drilling.
  80. 80.  CT milling run(s). This was the ultimate run to achieve the job objective and mill the ball valve. The motor needed to provide enough torque to mill through the ball valve. In addition, its operating pump rate should be achievable through the specially designed 2-in. CT string. A yard test and a successful milling job of a similar ball valve in a well operated by Shell in the British section of the North Sea were on record. The mill was a 4.1-in. OD dome profile ball mill run with a hydraulically (pump rate) operated shifting tool and an anti-stall tool. All lessons learned during this Shell job were taken into account for this Kvitebjørn CT project. The mill was designed and tested to mill through the ball valve material. The mill size for this Kvitebjørn job was decided to be 4-in. OD to deploy the milling BHA through the 41⁄16-in. 15K psi CT BOP. This mill size is big enough to allow later production logging tools to run through the milled hole. This critical detailed planning phase took approximately five months. It consisted of organizing several meetings and coordinating between different departments, disciplines, and third parties. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  81. 81. Offshore execution  The job went as planned. The CT job was carried out through the drilling rig. The ball valve was successfully milled and drifted with the 4-in mill and the access to the lower wellbore was regained. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  82. 82. CT equipment layout on pipe deck. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  83. 83.   No serious HSE & Q incidents were reported during this first HP/HT CT job in Statoil and the Norwegian continental shelf with a high operating factor of 96.2%. The total job duration was 31.6 days with equipment rig up including "pump and bleed" of 10.9 days; one VJJB clean up run and three milling runs totaling 9.1 days; extra production test and one extra drift run with VJJB through and below the milled ball valve, 6.1 days; and equipment rig down and back load, 5.5 days. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  84. 84. Operational risk analysis An operational risk analysis log sheet and risk register covering the different steps of the operation was elaborated during detailed planning. This was important because this was the first HP/HT CT operation in Statoil and in the NCS.  The risk assessment involved representatives from all concerned disciplines within Statoil, including reservoir, well intervention, drilling and production, plus Statoil discipline advisors for CT, well intervention, well integrity, HP/HT, and well control, as well as third-parties representatives for CT services and the rig contractor.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  85. 85.   The probability and the potential impact for each initial risk were assessed using a standard risk tolerance matrix. Prevention and mitigation actions were identified for each risk with the objective of reducing the probability and/or the potential impact of the corresponding risk. This resulted in a detailed operational risk register including 41 identified hazards and 84 risk prevention and/or mitigation measures that were implemented during the planning and execution phases. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  86. 86. This risk register was subdivided into 11 sections as following:  1. Mobilization and demobilization 2. Spotting and equipment rig up 3. "Pump and bleed" operation 4. VJJB drift and cleanout run(s) 5. Milling run(s) 6. Well control stack up 7. BHAs 8. Fluids 9. Contingency scenarios 10. Rig down equipment 11. Simultaneous contingency situations in A-9 T2 and a second well. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  87. 87. Lessons learned There were a number of lessons learned on this project. They key lessons are described below.  Telemetry tool performance. The telemetry tool provided valuable CCL data to correlate the depth down to the ball valve. The telemetry tool failed in three of four runs at a bottomhole temperature around 145ºC (293º F). However, the CCL logging signal failed after the initial depth correlation. The telemetry tool was running properly for its first few hours of exposure under extreme downhole pressure and temperature conditions before it failed. It was a known and accepted risk prior to operation that the tool might fail if exposed to downhole conditions close to or above its operational specifications of 8,000 psi/150º C (55 MPa/305º F) for a prolonged time. It could be concluded from the data that the telemetry tool operated properly up to 564 bar (8,180 psi) and 146º C (295º F) before failure.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  88. 88.  Equipment availability. The equipment availability for this special and non-frequent HP/HT CT job was a challenge. Early planning and ordering of some critical equipment was vital, especially knowing the day rate of the drilling derrick to be used. This critical equipment included both CT strings, the gas tested 71⁄16-in./15K psi gate valve, the safety head handler, the gas-tested christmas tree crossover, and the 21⁄16-in 15K psi gas tested gate valves. Weekly meetings to review critical items were held with the CT contractor. The need for long lead items was identified early in the project, and Managed for drilling systems. Statoil issued purchase orderspressure relevant Multilateral wells. Coiled tubing equipment. underbalanced drilling.
  89. 89. Site surveys. Three site surveys were carried out by Statoil and CT contractor representatives to avoid conflict with platform interfaces, and to identify any limitations or special requirements.  Personnel HP/HT training. Two fullday sessions of CT awareness and HP/HT seminars were organized and presented by the CT contractor to all involved personnel before the job start up.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  90. 90. Bleed off procedure. The bleed off needed to avoid explosive decompression of well control equipment elastomers was not provided by the CT contractor. Rather, the local platform best practice used during wireline operations was followed during this CT job. For future CT HP/HT operations, the bleed off procedure should be based on recommendations from the original equipment manufacturer for standard and high-pressure well conditions, respectively.  Pump and bleed operation. Liquid losses into formation were experienced during the "pump and bleed" phase and it was not possible to reduce the WHP. It was decided to abort the pump and bleed operation and to start running in the well while circulating through the CT. This alternative was effective in reducing the WHP.  Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  91. 91.  CT weight simulations. A drag reduction by 25% (from 0.24 to 0.18) was observed when displacing the wellbore with metal-to-metal friction reducer while RIH from 4,200 m (13,776 ft) MD RKB to the ball valve. Data proves that the actual CT RIH and pick up weights were within the operating limit at 80% yield of CT string material. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  92. 92.  Milling through the ball valve. It was difficult to control the weight on bit (WOB) at 6,245 m (20,484 ft) MD while pumping 40/60% MEG/fresh water at 400 l/m pump rate and at 340 to 375 bar (4,931 to 5,439 psi) CT circulation pressure. During the first milling run, the WOB was set down gradually but the motor stalled 15 times. The first milling BHA was pulled to surface for inspection. During the second milling run, milling was carried out with patience for longer periods without increasing the WOB. Vibration and an anti-stall tool was expected to provide sufficient WOB. The top part of the ball valve was milled during the second run in approximately 12 hours and the bottom part in an additional 12 hours. The experience gained from the first milling run was used to optimize the milling parameters of the second and third milling runs, and succeeded to break through the ball valve with the 4-in. mill at the end. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  93. 93.  Confirmed milled ball valve. A 3D multi-finger caliper log was run on wireline two months after the CT milling job to investigate the wellbore status, particularly the milled ball valve area. The ball valve was confirmed to be milled out with a minimum ID of 3.97 in. at 6,245.7 m MD. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  94. 94. Conclusion  This CT project represents an excellent reference for future HP/HT CT operations for Statoil in Norway and worldwide. The job execution was performed as planned and in compliance with the relevant industry standards and local regulations. The stuck closed isolation ball valve was successfully milled and drifted with the 4-in. dome profile mill. No serious HSE&Q incidents were reported during this first HP/HT CT job in the Norwegian continental shelf, which had a high operating factor of 96.2%. Valuable lessons learned from the planning and execution phases of this challenging Managed pressure drilling systems. operation should be useful in future similar HP/HT CT applications. Multilateral wells. Coiled tubing underbalanced drilling.
  95. 95. Coil tubing equipment  Hydra Rig Trailer mounted 2” CT unit, two trailer design, 22,000 feet reel capacity, 80,000 lbs. pull injector and 50 ton crane Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  96. 96.  Hydra Rig 6100 CT Injector with tubing straightener and leveling lift bale Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  97. 97.  Offshore 1¼” CT Unit Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  98. 98.  Hydra Rig Trailer Mounted Sichuan CTU  Hydra Rig Trailer Mounted CTU and pumper on location in Turkestan Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  99. 99.  Hydra Rig Intermediate size trailermounted CTU with crane, 635 injector Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  100. 100.  Hydra Rig’s new 55,000 sq. ft. final assembly and CTU maintenance facility Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  101. 101.  CTD horizontal re-entry project, with NOV Hydra Rig coiled tubing unit, nitrogen unit, and NOV Rolligon pumping unit. Also utilized are NOV Texas Oil Tools BOPs and NOV CTES DAS system. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  102. 102.  Hydra Rig Mini Coil Drop In Drum Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  103. 103.  Hydra Rig Mini Coil 420C Injector Head Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  104. 104.  Hydra Rig Mini Coil Unit Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  105. 105. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  106. 106. Snubbing Units NOV Hydra Rig Snubbing Units have earned a reputation worldwide for high performance and versatility in the field. Rig-up is fast due to lightweight, compact design and the elimination of the need to “kill” the well. NOV Hydra Rig Snubbing Units are engineered to work on any pressure well, with pipe sized up to 8s”, and pulls up to 600,000 lbs. With over 200 units manufactured, our snubbing units are the industry standard. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
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  133. 133. Coring and drilling Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
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  141. 141.  Hydraulic fracturing Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
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  159. 159.  Shaker Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
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  162. 162. Communications and safety issues The Piper Alpha Disaster In 1988 Britain suffered one of the worst industrial disasters when the Piper Alpha oil Platform was destroyed by fire and gas explosion, resulting in 167 fatalities. The disaster caused significant changes to the manner in which safety was regulated and managed in the UK offshore oil industry. Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  163. 163. Events in the disaster  The Piper Alpha platform was operated by Occidental Petroleum (Caledonia) Ltd. and located 110 miles notheast of Aberdeen  The platform produced oil and gas and was linked to the installations Tartan, Claymore and MCP01 by subsea pipelines  On July 6, 1988, dayshift workers had removed a safety release for a consendate pump that was not being used and replaced it with a blank flange  Several hours later the night shift operations team experienced a problem with a second consendate pump and restarted the first pump, unaware of the the safety valve had been removed Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  164. 164.  Around 10:00 pm there was an explosion on the production deck of the platform which was caused the ignition of a cloud of gas consendate leaking from the temporary flange  The fire spread rapidly and was followed by a number of smaller explosion  At around 10:20 pm a major explosion was followed by the ruptering of a pipeline carrying gas to the Piper Alpha platform from the nearby Texaco Tartan platform  The next few hours an intense high-pressure gas fire raged, punctuated by a series of major explosions that served to hasten the structural collapse of the platform Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  165. 165.    Most of the emergency systems on the platform, including the fire water system, failed to come into operations Of the 226 persons onboard the installation only 61 survived The great majority of the of the survivors escaped by jumping into the sea, some from as 175 feet (approx. 54 m) Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  166. 166. Piper Alpha in flames Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  167. 167. Crisis Management at Piper Alpha  The explosion on the Piper Alpha that led to the disaster was not devasting. We shall never know, but it probably would have killed only a small number of men  There was a number of critisim related to the performance of the OIM on both Piper Alpha, Claymore and Tartan platforms  These platforms were linked together by pipelines and if the hydrocarbons from these platforms had been stopped earlier, the situation on Piper might have deterioated less rapidly Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  168. 168.  On the evening of the crisis the platforms OIM was at his cabin  In the control room at 9:55 pm a series of low gas alarms was registered followed by a single high gas alarm and a suddenly explosion  The stand by boat sent out a mayday call  By 10:05 several minutes after the explosion the OIM arrived in the radio room wearing a survival suit and instructed the radio operator to send out a mayday  The OIM left without giving further instructions or stating his intentions Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  169. 169.  A few seconds later he ran into the radio room and told the operator that area outside was on fire and that it should be broadcasted that the platform was being abandoned  By this time people had started to muster in the accomodation area an were waiting further instructions  Some of the emergency response teams made attempts to tackle the fires or to effect rescues, but these were uncoordinated and ineffective efforts in a desperate situation  By 10:20 pm 22 surviors had abandoned the platform – many who had been working outside such as divers  Where people had mustered no one was in charge or giving instructions and there was confusion Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  170. 170.  A second major explosion because of gas coming into the the Piper from Tartan caused a massive high-pressure gas fire on the platform  By 10:50 pm the structure of the platform was beginning to collapse and gas fires were raging  The OIM and the majority of his crew died onboard as a result of smoke inhalation  The report afterwards showed that the OIM took no initiative in an attempt to save life but in his defense several psychological factors could explain the OIM`s inadequate leadership and poor decision making  He was under considerable stress and had not been properly trained and smoke inhalation can effect cognitive functioning Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  171. 171. The Claymore Platform Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  172. 172. Crisis Management at Claymore  However what was more suprising revealing serious weaknesses in the oil industry`s provision for offshore crisis management, was that the two other OIM`s on duty from the linked platforms also failed to take appropriate decisions  The Claymore platform situated 22 miles from Piper needed to shut down the oil production to prevent it from flowing towards the Piper platform  At 10:05 pm the Claymore OIM was told that there had been a mayday on Piper due to fire and explosion  An attempt to contact Piper was unsuccessful and on the secong mayday from Piper he sent a standy vessel without shutting down the oil production Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  173. 173.  The operating superintendent at Claymore asked the OIM if he could shut down the oil production. The OIM refused this  The OIM at Claymore then called his manager in Aberdeen. They knew that Pipers oil had been shutdown. But as the pipeline pressure was stable the OIM decided to continue the production  10:30 they have heard that the fire on Piper was spreading, and the operating superintendent again asked the OIM to shut down oil production. This was refused because he wanted to maintain the production Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  174. 174.  During a later phonecall the OIM made to the Production Manager the operating superintendent shouted that there had been an explosion on the Piper. The Production Manager in Aberdeen asked them to shut down immediately when he found out that they were still operating  The Production Manager was suprised that they were still operating and instructed both Claymore and Tartan to shut down production Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  175. 175. Illustration of the Oil field Piper Alpha Claymore Tartan Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  176. 176. The Tartan Platform Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  177. 177. Crisis Management on Tartan  Texaco`s Tartan was located 12 miles southwest of Piper and also needed to shut down gas and oil production in the event of an serious emergency on Piper  10:05 pm the OIM at Tartan heard mayday from Piper Alpha  The OIM could not see any flames so he did not shut down the production but instructed his production supervisor to monitor the gas pressure on the pipeline to Piper  Production was maintained on Tartan in the belief that Piper was still producing (no telephone contact was possible)  10:25 the production supervisor was informed of a large explosion on Piper. This explosion was in fact caused by the hydrocarbons from Tartan Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  178. 178.  The emergency control was finally shut down and it took 5-10 minutes before the Tartan OIM asked for their gas line to be depressurized and for the oil production to be shut down Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  179. 179. Conclusion  The Piper Alpha disaster demonstrated the need for proper training for the responsibility in this kind of position  This is just one of many crisis that have highlighted the need for organizations to competent to deal with major crisis  Crisis Management is primarily dependent on the decisionmaking of those in key command positions, at strategic, tactical and operational levels  The immediate cause of the accident was due to communication problems relating to shift handover and Permit to Work procedures  This crisis also shows the importancy of good organizational communication and information routines Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
  180. 180. What if... There had been a proper shifthandover, proper marking of the safety valve that wasn`t functioning, or proper Permit to Work for this shift at the Piper Alpha? Managed pressure drilling systems. Multilateral wells. Coiled tubing underbalanced drilling.
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