IADC Drilling Manual Part 8 doc

K-72 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition Choke Operation System. The choke position is usually controlled with a hydraulic spool valve which will deliver oil to either the open or closed side of the choke actuator. The valve is generally a spring centered type which when released will auto- matically return to the center position which closes both hydraulic lines leading to the actuator. This action effec- tively locks the choke in its last position (if there are no hydraulic oil leaks). The choke position at any time is indicated by a choke position indicator located in the face of the console. The choke operation system will frequently contain a choke speed control valve. This is usually a small needle valve located upstream of the choke control valve. By partially closing this valve the speed of opening or closing the choke can be reduced thus providing for precise positioning of the choke. Standpipe and Casing Pressure Gauges. The pressure condition in both The standpipe and casing is monitored by large diameter pressure gauges mounted in the face of console. These gauges are usually calibrated in 25 psi, or smaller, increments. The gauges are connected by flexible high pressure hose to their respective monitoring points. The hoses are usually oil filled to prevent entry of drilling mud. This is accomplished through the use of isolators at the standpipe and manifold pressure connection points. These isolators contain either a flexible diaphragm or floating piston which allows pressure to be transmitted into the hose. In higher pressure systems (greater than 10,000 psi) the piston type isolator will provide a 4:1 pressure reduction ratio in order to allow the use of lower working pressure hoses. The gauge faces are calibrated to actual system pressure, but have a working pressure four times less than the maxi- mum gauge reading. An alternative method for measuring and displaying these pressures is through the use of low pressure pneumatic pressure transducers. These transducers are located at the standpipe and manifold pressure monitoring points and are supplied with low pressure air from the console. The design is such that the signal returned through the sepa- rate signal line is proportional to the mud pressure being monitored. This signal pressure will generally not exceed 30 psi. The console gauges will display actual system working pressure, but will in fact be low pressure pneumatic gauges. Pump Stroke Counter. The console also contains a pump stroke counter. This counter takes its input signal from the limit switches located at the mud pumps. The counter will accumulate total strokes and the count totalizer may be reset to zero when needed. In addition to the stroke totalizer the unit will also contain a stroke rate indicator which reads in strokes per minute. The stroke counter unit will generally allow for switching from one pump to another if that is necessary. The stroke counter unit may be powered externally, but is most usually battery powered with lithium batteries. These batteries will generally provide a life of up to five years. The unit may be constructed to meet explosion proof requirements, but many are built to be intrinsically safe which leads to a lighter weight unit. Installation Guidelines The following practice is recommended for the installation of a drilling choke control console and the other control system components in a typical drilling rig. A location for the console should be selected so that it is near enough to the driller so that easy spoken communi- cation between the driller and the console operator is possible. This consideration is critical to the safety of the operation when kick control is required. The console should be securely attached to the floor. This attachment should be permanent if the control system is owned by the rig owner. If the control console and drilling choke is rental equipment, the attachment means is necessarily temporary, but the attachment must be sufficient to prevent the console from moving as a result of rig vibration. Should the console move around, the hydraulic and/or other lines connected to the console may be K-73 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures damaged. The air supply line, the hydraulic power lines from the choke actuator, the standpipe and easing pressure lines, the choke position transmitter lines, and the pump stroke counter lines need to be routed so that they do not become kinked or otherwise damaged during the normal course of drilling operations. Any excess line should be carefully rolled up and stored near the console, but in a location where it will not interfere with operations or become damaged. Care needs to be taken to ensure that all lines to the console are connected to the proper port on the console. For example the casing pressure line should be connected at the choke manifold pressure transmitter and also to the console pea which leads to the casing pressure gauge on the face of the console. The design of the console may be such that the various hydraulic and pressure lines have different size connectors so that they can be connected to only one port on the console, but this may not be the case so care must be exercised. The limit switches for the pump stroke counter must be installed on the frames of the mud pumps in such a way that they are tripped by the pump plunger during each stroke of the pump. If the control system is rented, the limit switches are usually supplied with a "C" clamp to facilitate attachment to the mud pump frame. After all the lines are properly routed and attached, the oil reservoir should be checked to ensure that it is filled to the proper level. The hydraulic pump should then be started by opening the air supply line. As soon as hydraulic pressure in the system builds up to the point where the pump shuts down, the choke control valve (or valves) should be cycled in order to move the choke actuator from open to closed and back several times to facilitate removal of any air from the hydraulic system. It may be necessary to add oil to the choke actuator during this operation. D. Diverter Control Systems Diverters Diverter Systems are used where shallow gas is anticipated during the initial drilling of the well prior to reaching the stable formation where the casing is cemented. Once this "shoe" is established, the B.O.P. stack can be installed and the well closed in should a "kick" be encountered during further drilling. Prior to cementing and establishment of the "shoe", gas encountered during The initial drilling must be diverted. Normally two diverter lines are employed at right angles to the prevailing wind. Diverting is accomplished by opening one or both of the diverter lines, then closing the annulus space, (flowline access) with the "packer" element. This directs gas away from the rotary and mud pits, through the diverter vent lines and harmlessly away from the rig. The shallow pocket of gas will normally loose its pressure and bridge closed in a matter of minutes. The critical issues when shallow gas is encountered and as soon as the "kick" is detected is to respond quickly and correctly. Quickly because in the shallow well there is little hydrostatic head pressure and little distance for the gas to travel before a blowout. Correctly because closing in the well could cause a blowout to occur around the conductor allowing gas to migrate up the outside of the conductor and to the drill floor. To prevent closing in the well, at least one vent line must be open prior to closing the diverter packer (flowline access to the annulus). The most common diverter systems used on land, or fixed offshore rigs consist of an annular type blowout preventer with a top mounted bell nipple which has an outlet for the flowline to the shale shaker/mud pits and one or two diverter lines to vent the diverted gas overboard. When the diverter packer closes on the drill pipe it closes the annulus space shutting off the flow of drilling mud through the flowline. Even in simple systems like this, it is prudent to have the diverter control system designed in a manner to prevent closing the diverter packer until at least one diverter vent is open. It is even more imperative in the more complex platform diverter systems and subsea diverter systems that critical functions occur automatically and that safeguards are employed to prevent K-74 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition erroneous operation which could result in injury, damage to the rig and damage to the environment. Generally accepted diverter control system recommended practices are listed in API RP 16E.5. General Information The master hydraulic diverter control manifold or panel should be treated in the same manner as the B.O.P. hydraulic control unit as stated in API RP16E.2.6.7. It should be located in a safe (protected) area away from the drill floor but accessible to rig personnel in case the drill floor has to be evacuated in an emergency. This means that the diverter functions should be capable of remote control from the driller's position. The automatic sequencing circuitry and safety interlock circuitry should always be established in the master hydraulic diverter control manifold. If these circuits were to be established in the remote control panel, they could be inaccessible or rendered inoperative by damage if the drill floor was evacuated because of gas, fire or falling debris. Diverter Types Diverter Types Brief Description: Hydril MSP NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve. NORMAL SAFETY INTERLOCK Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open. Vetco KFL NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve and locks The insert packer. NORMAL SAFETY INTERLOCK Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open and the insert packer control valve has been shifted to lock. Hydril FSP NORMAL AUTO SEQUENCE Not required in the control system. NORMAL SAFETY INTERLOCK Not required in the control system. NOTE: The FSP diverter is designed so that when the piston moves up to close the diverter packer closing the flow line out of the top mounted bell nipple, it clears the bottom outlet to the vent line which is blocked when the piston is down (diverter packer open). The vent line cannot be closed. There is a selector deflector to select port or starboard. Vetco KFDJ NORMAL AUTO SEQUENCE Placing the diverter packer control valve in the close position automatically shifts The pre-selected overboard control valve to the open position, and ensures The inflowing valves shifts to the position indicated if they are rot already in that position: Insert Packer Lock Diverter Lock Dogs Lock Flowline Seals Pressurized K-75 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures Overshot Packer Pressurized Flowline / shaker Valve Close Trip Tank Valve Close (if applicable) Fill-Up Valve Close (if applicable) NORMAL SAFETY INTERLOCKS Hydraulic pressure to close the diverter packer is prevented until the following pilot signals are sensed: 1. At least one overboard valve has been actuated to open. 2. The insert packer has been actuated to lock. 3. Pressure is applied to both the flowline and overshot packer seals. TIME DELAY CIRCUITS The following circuits should be designed so they can be overridden after a 10 to 60 second delay: 1. Overboard valve can be shifted to port open / starboard close or starboard open / port close. 2. Flowline valve can be opened or closed at the operators discretion. 3. Trip tank valve can be opened or closed at the operators discretion. 4. Riser fill valve can be opened or closed at the operators discretion. NOTE: If overriding these functions is desired by the operator with the overboard valves closed, the diverter-test valve can be placed in the test position interrupting the auto sequence. This is normally required for low pressure testing of the diverter lines. Additional Features Common To Platform Diverters: 1. Safety circuit to prevent venting the flowline seals or overshot packer when the diverter packer is closed. 2. Optional divert/strip function. 3. Divert/test mode function allows closing all diverter functions for low pressure testing. 4. Low deadband failsafe pneumatic motor driven remote controlled regulators. Normally only the diverter packer pressure regulator is remotely operated. All regulators can be remotely operated. Remotely operated regulators should be sensitive to down stream pressure changes within plus/minus 150 psi. 5. KFDJ and KFDS diverter control systems should include a "Diverter Ready" indicator to indicate when the safety interlock circuits have been preset to their proper position. 6. Hydraulic safety logic should be used to reduce the dependence on pneumatic circuitry. 7. Pneumatic circuits should be minimized for safety. Air supply for a minimum of two times the volume to se- quence the diverter controls should be check, valved in and stored in the panel for emergency operation. 8. Low air supply pressure and low hydraulic supply pressure warning lights should be included in diverter control systems with electric remote control. Function position status indication should also be included. Vetco KFDS The normal auto sequence, safety interlocks, delay circuits and additional features described in the KFDJ diverter brief descriptions are generally applicable to the KFDS diverter controls for subsea systems. KFDS systems usually have more hydraulic functions than the KFDJ and will include a slip joint packer which may be energized by air or hydraulic pressure. K-76 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition KFDS diverter control systems are normally self-contained units. They include dedicated pumps, reservoirs and accumulators. Diverter Remote Controls The master hydraulic diverter control manifold or control panel should be located off the drill floor in an area relatively safe from gas, fire and falling debris and should be accessible to the drilling crew for operation in an emergency. This means that the diverter control functions should be capable of remote control from the driller's location. On offshore drilling rigs, the control panel at the driller's location should as a minimum include the follow- ing features: 1. Control and status position indication of all diverter control functions. 2. Control of the diverter packer regulator to increase/decrease function. 3. Low hydraulic supply and low air supply to the master panel alarms. If the diverter control system is a "self- contained" unit, low reservoir level of the diverter control fluid reservoir should be included. 4. Electric pump running light. (Self-contained units with electric pump.) 5. "On battery power" indicator (units so equipped with emergency battery back-up). 6. Nitrogen back-up initiated (if so equipped). 7. Indication of all system pressures. 8. Function controls oriented and represented in a graphic display of the diverter system. The driller's remote control panel should be designed in accordance with the recommendations of API RP16E.2.6 (see API RP16E.5.6). Driller's panels should be suitable for installation in explosive gas environments. Diverter control panels can frequently be incorporated with the B.O.P. control system panels to conserve space. Diverter functions should be electrically independent of the B.O.P. control functions. Diverter Back-up Systems The response time recommendation to sequence the diverter system and close the diverter packer within 30 seconds for diverter packers up to 20 inch nominal bore size and 45 seconds for diverter packers over 20 inch nominal bore size (Ref. API RP16E.5.1) can be met with a nitrogen back-up system or dedicated hydraulic accumulators (Ref. API RP16E.5.3.2). The back-up system can have manual intervention as long as it is select- able on demand (remote control from the driller's panel) or otherwise, automatic. Automatic hydraulic back-up systems sense the loss of a hydraulic pilot signal and automatically open the back-up accumulator supply into the hydraulic control manifold of the diverter control system. Automatic nitrogen back-up systems likewise sense the loss of hydraulic pilot pressure and automatically inject stored nitrogen pressure into the manifold circuit for sequencing the diverter functions and closing the diverter packer. Either system can be "unit" mounted or "separate skid" mounted. Hydraulic back-up systems, whether unit mounted or separate skid mounted, must be designed with consideration of the reservoir size for the additional fluid volume of the back-up accumulators. K-77 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures Pump up time for initially charging the back-up system accumulators need not be considered when sizing pump systems in accordance with API RP16E.5.31. The back-up accumulators will remain charged after the initial charging unless operated in an emergency according to their design intent. E. Control Systems Typical Capacity And Performance Data / Calcula- tions Blowout prevention equipment such as annular preventers and ram preventers are normally opened or closed by fluid pressure. The fluid to accomplish this is stored in the accumulator. The pressure used must meet the capacity and operator pressure requirements of the particular blowout preventer in order for it to perform as designed. The performance characteristics of blowout preventers are discussed in paragraph K1.8. The capacity require- ments, operator chamber design working pressure, and opening and closing ratios of most major manufacturers' blowout prevention equipment are shown in the Quick Reference Tables K1.8.1 through K1.8.5. K-79 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures Table K1-8-2 Hydril Annular BOPs - Operating Characteristics K-80 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition Table K1-8-3 Cameron Annular BOPs - Operating Characteristics K-81 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures Table K1-8-4 Shaffer Annular BOPs - Operating Characteristics K-82 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition Table K1-8-5 Hydril Ram BOPs - Operating Characteristics [...]...Chapter K: BOP Equipment, Procedures Table K1 -8- 6 MH Koomey Ram BOPs - Operating Characteristics International Association of Drilling Contractors K -83 IADC Drilling Manual - Eleventh Edition Table K1 -8- 7 Cameron Ram BOPs - Operating Characteristics K -84 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures Table K1 -8- 8 Shaffer Ram BOPs - Operating Characteristics... tables in K1 .8, above, let us say that we have a surface BOP stack that requires the following closing volumes of fluid: Annular gallons to close = 17. 98 gallons 3 Rams @ 5 .8 gal ea to close = 17.40 gallons Total galonage required: 35. 38 gallons Plus 50% Safety Factor 17.69 gallons Stored Usable Fluid Required = 53.07 gallons International Association of Drilling Contractors K -87 IADC Drilling Manual -... Annular gallons to close = 17. 98 gallons International Association of Drilling Contractors K -89 IADC Drilling Manual - Eleventh Edition Annular gallons to open = 14.16 gallons Rams (3) @ 5 .8 gal each to close = 17.40 gallons Rams (3) @ 5.4 gal each to open = 16.20 gallons Total gallonage required: 65.74 gallons Plus 50% safety factor = 32 .87 gallons Stored usable fluid required = 98. 61 gallons We will say... This capacity can be subtracted from the surface capacity as given below: 98. 61 gal - (17. 98 gal + 5 .80 gal) = 74 .83 gal Therefore we now know that we need to have enough accumulator bottles at surface to give 74 .83 gallons of stored usable fluid and enough accumulator bottles at the BOP stack to give (17. 98 gal + 5 .80 gal) 23. 78 gallons of stored usable fluid Since we have previously calculated the... following information, the table below, and the Driller's Method kill sheet utilizing this kill method International Association of Drilling Contractors K-99 IADC Drilling Manual - Eleventh Edition Table K3-P8 Steps of the Driller's Method K-100 International Association of Drilling Contractors Chapter K: BOP Equipment, Procedures 1 The first step of the Driller's Method is most appropriate for use (by... Remembering that the 0 .8 gallons does not count, we can determine the stored usable fluid in the bottle by the following equation: Stored Usable Fluid = (4.6 - 0 .8) gal = 3 .8 gallons Said another way, as the pressure in the 10 gallon accumulator bottle falls from 4335 psi to 2535 psi, 3 .8 gallons of liquid are forced out of the bottle and into the lines One problem encountered in deepwater drilling is diminishing... Association of Drilling Contractors K-91 IADC Drilling Manual - Eleventh Edition K3 Well Control Procedures Basic Principles Definition A kick is an influx of formation fluids into the well bore A blowout is an uncontrolled kick The objective of well control procedures discussed in this section is to safely handle kicks and reestablish primary well control Primary Well Control During normal drilling operations,... pressures the choke should be used to bleed drilling fluid from the casing the amount of pressure to try to keep constant is the Closed-in Drill Pipe pressure value which reflects the amount of underbalance in the drill string, plus 100 or 200 psi See page 6 for choke adjustment considerations International Association of Drilling Contractors K-95 IADC Drilling Manual - Eleventh Edition Closed In Drill... gauge International Association of Drilling Contractors K-97 IADC Drilling Manual - Eleventh Edition The drill pipe pressure read at this point is usually termed INITIAL CIRCULATING PRESSURE (ICP), if this pump start-up is taking place at the beginning of the kill The difference between the closed-in and pumping drill pipe pressures is the pressure required to cause the drilling fluid to circulate at the... pumping liquid into the bottle, its pressure increases Boyle's Law defines this relationship between the volume of gas and its pressure as given below; International Association of Drilling Contractors K -85 IADC Drilling Manual - Eleventh Edition "The absolute pressure of a confined body of gas varies inversely to its volume provided its temperature remains constant" This means that if a volume of gas . Characteristics K -80 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition Table K1 -8- 3 Cameron Annular BOPs - Operating Characteristics K -81 International Association of Drilling Contractors Chapter. Procedures Table K1 -8- 4 Shaffer Annular BOPs - Operating Characteristics K -82 International Association of Drilling Contractors IADC Drilling Manual - Eleventh Edition Table K1 -8- 5 Hydril Ram BOPs. required: 35. 38 gallons Plus 50% Safety Factor 17.69 gallons Stored Usable Fluid Required = 53.07 gallons K -88 International Association of Drilling Contractors IADC Drilling Manual - Eleventh