CR FPP 160 REV01 Well Control Equipment
Short Description
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Description
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 2 of 86
Contents 1. RECAP OF RULES ............................................................................................... 7 2. FOREWORD ....................................................................................................... 23 2.1 2.2 2.3
INDICATOR................................................................................................................ 23 LIMITS and DEFINITIONS ......................................................................................... 23 GLOSSARY................................................................................................................ 24
3. BOP STACK CONFIGURATION PHILOSOPHY AND LIMITATIONS ............... 25 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8
Position of the BSR .................................................................................................. 25 Position of the killing lines....................................................................................... 25 Position of the choke line for a 3 sets of rams BOP stack..................................... 26 Position of the choke lines for a 4 or more sets of rams BOP stack..................... 26 Stripping of the drill pipe string in the well with a 3 sets of rams BOP stack ...... 26 Stripping of the drill pipe string in the well with a 4 or more sets of rams BOP stack.................................................................................................................. 27 Casing rams .............................................................................................................. 27 Shooting nipple......................................................................................................... 27
4. BOP REQUIREMENT ......................................................................................... 29 5. MAIN CONSIDERATIONS .................................................................................. 30 5.1 WORKING PRESSURE OF WELL CONTROL EQUIPMENT .................................... 30 5.2 MUD CROSSES ......................................................................................................... 31 5.3 BOP OUTLETS .......................................................................................................... 31 5.4 BLIND RAMS ............................................................................................................. 31 5.5 SHEAR FUNCTION.................................................................................................... 31 5.6 CASING RAMS .......................................................................................................... 32 5.7 PIPE RAMS HANG-OFF CAPACITY ......................................................................... 32 5.8 RAM LOCKING DEVICES.......................................................................................... 33 5.9 DUAL COMPLETION ................................................................................................. 33 5.10 COMPLETION ACCESSORIES ................................................................................. 33 5.11 BAG PREVENTERS................................................................................................... 33 5.12 RING GASKETS ........................................................................................................ 34 5.13 WELL CONTROL EQUIPMENT INFORMATION ON RIG.......................................... 34 5.14 BOP STACK INSTALLATION.................................................................................... 34 5.14.1 Surface BOP stack.................................................................................................... 35 5.14.2 Subsea BOP stack.................................................................................................... 35 5.15 H2S ENVIRONMENT .................................................................................................. 36 5.16 TEMPERATURE / FLUID COMPATIBILITY............................................................... 36 5.17 HP/HT WELLS ........................................................................................................... 37
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 3 of 86
6. CONFIGURATION OF BLOW OUT PREVENTERS........................................... 38 6.1 SURFACE STACK CONFIGURATION ...................................................................... 38 6.1.1 MEWHP < or = 3 000 psi .......................................................................................... 38 6.1.2 MEWHP > 3 000 psi and < or = 5 000 psi ................................................................. 38 6.1.3 MEWHP > 5 000 psi and < or = 10 000psi ................................................................ 39 6.1.4 MEWHP>10 000 psi.................................................................................................. 39 6.2 SUBSEA BOP CONFIGURATION ............................................................................ 40 6.2.1 Single stack System.................................................................................................. 40 6.2.2 Two stack System..................................................................................................... 41 6.2.2.1 Large bore BOP stack........................................................................................... 41 6.2.2.2 Small bore stack MEWHP > or = 5 000 psi ........................................................... 41
7. CHOKE MANIFOLD, KILL & CHOKE LINES ..................................................... 42 7.1 7.2 7.2.1 7.2.2 7.3 7.3.1 7.3.2 7.4 7.4.1 7.4.2
GENERAL .................................................................................................................. 42 KILL LINES ................................................................................................................ 43 Surface BOP............................................................................................................. 43 Subsea BOP ............................................................................................................. 43 CHOKE LINES : ......................................................................................................... 44 Surface BOP............................................................................................................. 44 Subsea BOP stacks .................................................................................................. 44 CHOKE MANIFOLD ................................................................................................... 45 Number of chokes..................................................................................................... 45 General design and operating: .................................................................................. 45
8. BOP CONTROL SYSTEM................................................................................... 47 8.1 GENERAL .................................................................................................................. 47 8.2 HYDRAULIC CONTROL UNIT ................................................................................... 47 8.2.1 ACCUMULATORS VOLUME AND PRESSURE ....................................................... 48 8.2.1.1 Surface BOP......................................................................................................... 48 8.2.1.2 Subsea BOP ......................................................................................................... 49 8.2.2 CLOSING TIME PERFORMANCES ......................................................................... 50 8.2.3 PUMPS SYSTEM...................................................................................................... 51 8.3 CONTROL PANELS................................................................................................... 52 8.3.1 COMMON CONTROL PANELS ................................................................................ 52 8.3.2 ROV INTERVENTION PANEL .................................................................................. 53 8.4 ACTUATION SYSTEM ............................................................................................... 53 8.5 PIPING ....................................................................................................................... 54 8.6 CONTROL FLUID ...................................................................................................... 55 8.7 DIVERTER CONTROL SYSTEM................................................................................ 55
9. DRILL STRING SAFETY VALVES ..................................................................... 56 9.1 9.1.1 9.1.2 9.2 9.2.1 9.2.2
EQUIPMENT IN DRILL STRING ................................................................................ 56 Kelly / Top drive system valves ................................................................................. 56 Drill string valves....................................................................................................... 56 EQUIPMENT READY ON RIG FLOOR ...................................................................... 57 Drill pipe safety valve ................................................................................................ 57 Upper drill string float valve ....................................................................................... 57 This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 4 of 86
10.MUD GAS SEPARATOR (MGS)......................................................................... 58 10.1 10.2 10.3 10.4
MUD SEAL CONFIGURATION .................................................................................. 58 VENT LINE ................................................................................................................. 59 OTHER EQUIPMENT ................................................................................................. 59 DEEP WATER : RISER GAS EVACUATION ............................................................. 60
11.WELL CONTROL EQUIPMENT INSPECTION / CERTIFICATION / MAINTENANCE .................................................................................................. 61 11.1 11.2 11.3 11.4
GENERAL .................................................................................................................. 61 RIG ACCEPTANCE.................................................................................................... 62 PERIODIC INSPECTIONS ......................................................................................... 62 MODIFICATIONS, CHANGES.................................................................................... 63
12.APPENDIX .......................................................................................................... 64 Appendix 1: Drawings ....................................................................................................... 64 SURFACE STACK MEWHP < or = 3 000 psi....................................................................... 65 SURFACE STACK MEWHP < 3 000 psi and < or = 5 000 psi............................................ 66 SURFACE STACK MEWHP > 5 000 psi AND < or = 10 000 psi ........................................ 67 SURFACE STACK MEWHP > 10 000 psi .......................................................................... 68 SUBSEA BOP STACK MEWHP < or = 10 000 psi ............................................................. 69 LARGE BORE SUBSEA BOP STACK MEWHP < or = 3 000 psi ......................................... 70 SUBSEA STACK MEWHP > 10 000 psi............................................................................... 71 CHOKE MANIFOLD SCHEMATIC....................................................................................... 72 HYDRAULIC CONTROL UNIT SCHEMATIC....................................................................... 75 MUD GAS SEPARATOR SCHEMATIC ............................................................................... 76 Appendix 2 : Shear rams ................................................................................................... 77 Appendix 3: Example of accumulator volume calculation............................................. 78 A) Surface BOP stack .......................................................................................................... 78 B) Subsea BOP stack .......................................................................................................... 80
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Date: 15/10/2003
Page: 5 of 86
Reference documents Unless otherwise stipulated, the applicable version of the reference documents listed below, including relevant appendices and supplements, is the latest revision published. Standards Reference API SPEC 6A API SPEC 16A API RP 16E API RP 53 API RP 64
Title Specifications for valves, Wellhead and Xmas tree equipment Drilling and production equipment Design of control systems for drilling well control equipment Blow Out prevention equipment systems for drilling wells Diverter systems Equipment and Operations
Professional Documents Reference
Title
Not applicable
Regulations Reference
Title
Not applicable
Codes Reference
Title
Not applicable
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 6 of 86
Other documents Reference CR FPP 130 CR FPP 215 CR FPP 165 CR FPP 225 CR FPP 230 CR FPP 265 CR FPP 170 GS COR 170
Title Well barriers for drilling and workover operations Shallow gas Well Control equipment pressure tests Casing Design Well Shut In Well Pressure Integrity H2S Policies Materials for sour service (upstream applications) Specifications for design
Other Total documents Reference
Title
Not applicable
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 7 of 86
1. RECAP OF RULES Blue color for rules to apply for offshore operations only, green color for rules to apply for onshore operations only and black for rules for all situations. Rule 1:
All drilling and workover operations shall use a Blow Out Preventer as soon as the architecture allows to shut the well in until the well is plugged or a completion with mechanical barriers is in place (refer to CR FPP 130). In the event of programmed operations, without a Blow Out Preventer (i.e. drilling shallow reservoir with a diverting system) an appropriate risk assessment shall be carried out and documented.
Rule 2:
The Working Pressure of all Well Control Equipment subject to well pressure shall be greater than or equal to the MEWHP of the operational phase during which the equipment will be used.
Rule 3:
The use of mud cross is not allowed on all BOP stacks when MEWH > 5 000 psi.
Rule 4:
Although API 6A allows 2" LP threaded connections on 5 000 psi WP equipment, welded flanges or hub connections are mandatory on all pressure systems when MEWHP > 3000 psi.
Rule 5:
Kill line outlet shall not be smaller than 2”1/16 nominal, Choke line outlet shall not be smaller than 3"1/16 nominal.
Rule 6:
Blind rams shall always been installed in the uppermost set of rams of any BOP stack.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rule 7:
Rev: 01
Date: 15/10/2003
Page: 8 of 86
For any operational phase where hydrocarbon bearing reservoirs are foreseen, shear function is mandatory on a BOP stack, except on onshore development wells when MEWP< or = 5000 psi, with low GOR oil reservoirs ( 5 000 psi, annular preventers may be of a WP immediately lower than the WP of the BOP’s rams preventers. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 9 of 86
Rule 13: Two 10 000 psi WP annular preventers shall be installed for drilling subsea wells with MEWHP>10 000 psi. Two annular preventers shall be installed for drilling deep or ultra-deep water subsea wells with MEWHP> or = 5 000 psi.
Rule 14: New and clean ring gaskets shall be installed each time BOP components are re-assembled. Ring gasket shall not be reused. Only equipment recommended by BOP manufacturer shall be used for well control equipment replacement parts.
Rule 15: Clear and actual schematics of the choke manifold, stand pipe manifolds and BOP lay out shall be displayed next to the posters of well shut-in and control procedures in the Drill Master Cabin, at the choke manifold, at the BOP control unit, at each BOP remote control panel, at the tool pusher and the Company Man offices and at the mud logging unit.
Rule 16: For surface stack and for MEWHP up to and including 3 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 1 in appendix 1): One annular preventer. Two ram type preventers with BR or BSR in the top cavity. One kill line and one choke line connected below the lowermost set of rams. When working on “non-flowing” reservoirs, the stack can be reduced to one annular and one single equipped with blind rams.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 10 of 86
Rule 17: For surface stack and for MEWHP above 3 000 psi up to and including to 5 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 2 in appendix 1): One annular preventer. If no shear function is required: Two ram type preventers with BR in the top cavity. One kill line and one choke line connected below the lowermost set of rams. If shear function is required: Three singles or one double and one single ram type preventers with BSR in the top cavity. The upper kill line shall be installed below the uppermost set of rams (BSR). The lower kill line shall be connected below the lowermost set of rams. The choke line shall enter the BOP stack above the lowermost set of pipe rams. Stripping with the lowermost set of pipe rams is not allowed
Rule 18: For surface stack and for MEWHP above 5 000 psi up to and including 10 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 3 in appendix 1): One annular preventer. Three singles or one double and one single ram type preventers. The upper kill line shall be installed below the uppermost set of rams (BSR). The lower kill line shall be connected below the lowermost set of rams. The choke line shall enter the BOP stack above the lowermost set of pipe rams. Stripping with the lowermost set of pipe rams is not allowed. Redundancy of rams for each main DP string sizes is mandatory.
Rule 19: For surface stack and for MEWHP > 10 000 psi, the minimum BOP configuration should be the same as for a 10 000 psi WP excepted that a four ram type preventers BOP stack with one secondary choke line is mandatory. (see figure 4 in appendix 1). This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 11 of 86
Rule 20: For subsea single stack BOP stack and for subsea small bore BOP stack, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 5 in appendix 1):
One annular preventer. Upper hydraulic connector (WP = annular preventer WP). Four ram type preventers or two double ram type preventers. Lower wellhead hydraulic connector (WP > or = ram type preventers WP) One upper kill line hooked up below the BSR and one lower kill line below the lowermost set of pipe rams, these lines having a common part. Two choke lines with a common part. Stripping with the lowermost set of pipe rams is not allowed. Redundancy of rams for each main DP string sizes is mandatory If temperature is excessive for VBR, the redundancy between ram preventers on the main DP string sizes shall be achieved by adding additional fixed pipe ram preventers below the top BSR.
Rule 21: For subsea large bore BOP stack, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 6 in appendix 1):
One annular preventer. Two ram type preventers. One kill line hooked up below the BR or BSR. One choke line hooked up below the lowermost set of PR.
Rule 22: Lines and manifold designed for dynamic loads shall be securely fastened. Flexible KL and CL high-pressure hoses longer than 4m and valves assemblies at BOP outlets shall be supported to avoid the weak point initiate by the heavy weight of valves and flexible hoses. All valves shall be marked with a colour code according to their normal position while drilling.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 12 of 86
Rule 23: For surface and subsea BOP, in the case of a 3 or more sets of rams BOP stack, the line connected below the lowermost ram preventer shall not be used to evacuate an influx.
Rule 24: For subsea BOP, the choke manifold connection to the stand pipe manifold shall be designed in such a way as to allow pumping through the KL with returns through the CL, or vice versa but rule 22 still applies.
Rule 25: On surface BOP stacks, KL shall be at least 2” ID. When MEWHP< 10 000 psi, each KL shall be equipped with two manual full bore valves plus a check valve. In case no check valve is installed, minimum one of the two full bore valves shall be remotely operated. When MEWHP> or =10 000 psi, each KL shall be equipped with two full-bore valves plus a check valve. One of the two valves shall be remotely operated. In case no check valve is installed, both full bore valves shall be remotely operated. During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. The two kill lines can have a common part.
Rule 26: On subsea BOP stacks each KL shall be at least 3” ID and equipped with two full bore remotely operated valves (fail safe closed). During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. The kill lines have a common part.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 13 of 86
Rule 27: On surface BOP stacks, CL shall be at least 3’’ ID. Two full-bore valves shall be installed on each CL. One of these two valves shall be remotely operated. During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. If two choke lines, they shall be connected independently to the choke manifold and be completely isolated from the other by at least two valves. "CHICKSAN" type sections are not allowed on choke lines. High-pressure flexible hoses (Coflexip type or equivalent) shall be used.
Rule 28: On subsea BOP stacks each CL shall be at least 3” ID and equipped with two full bore remotely operated valves (fail safe closed). During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. "CHICKSAN" type sections are not allowed on choke lines. High-pressure flexible hoses (Coflexip type or equivalent) shall be used. The choke lines have a common part.
Rule 29: Number of chokes of the choke manifold: 2 M.A.C. 2 M.A.C. + 1 R.O.C. 1 M.A.C. + 2 R.O.C.
if MEWHP ≤ 3 000 psi if MEWHP> 3 000 and ≤ 10 000 psi if MEWHP> 10 000 psi
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 14 of 86
Rule 30: The minimum size for choke manifold equipment is 3" nominal. If two choke lines, two independent pressure sensors shall be available on each line and be completely isolated from the other by at least two valves. All chokes shall discharge directly into a at least 3’’ ID erosion nipple, at least 3 ft long and 1’’1/4 thick. Lead target flanges shall exist on the buffer chamber in front of all lines coming from the well. The buffer chamber shall provide direct exits to the mud pit, vertical degasser, horizontal flare (onshore) or burner boom(s) (offshore) and overboard line. At least one gate valve shall be installed downstream of each choke but ahead of the buffer chamber. This valve may have a working pressure one step down of the upstream side working pressure. A bypass shall be provided from the choke line to the buffer chamber without passing through the chokes. The two gate valves and the piping controlling the bleed line shall have full rate working pressure of the BOP stack preventers. The installation, upstream of chokes, of a Glycol or equivalent injection system is mandatory if hydrates formation is anticipated.
Rule 31: When remotely operated choke is mandatory, its control panel shall be near the Driller. It shall include, in addition to manometers (DP pressure, casing pressure) and choke monitor, the following: an alarm set on Padm A pump strokes totalizer. The remotely operated choke shall be equipped with an emergency backup system in the event of primary energy supply shut down or failure (hand pump or nitrogen).
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 15 of 86
Rule 32: The hydraulic control unit with the master control panel shall be easily accessible, on the escape way and not at the rig floor, in a non-classified (non-hazardous) area. It shall be adequately protected against dropped objects and fire. Onshore, it shall be installed at least at 15 m from the wellhead.
RULE 33: For surface BOP, the total accumulator volume shall be equal to the volume required for the full closure and full opening of all preventers (rams and bag) plus all remote operated valves with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being off. If shear rams are installed, the residual pressure of the accumulators after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. This accumulator shall be split into at least two bottles banks. Each multibottle accumulator banks shall have valve for bank isolation.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 16 of 86
Rule 34: For subsea BOP, the total primary accumulators volume shall be equal to one and haft times the volume required for the full closure and opening of all preventers (rams and bags ) plus all remote operated valves with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being out of service. In addition, the residual pressure of the total primary accumulators after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. In case subsea accumulators are part of the primary system, the total primary accumulators volume shall include the volume of the subsea accumulators on the BOP stack. In case of dedicated subsea accumulators for emergency back up system, the volume of the dedicated subsea accumulators for emergency back up system shall be equal to one and half times the volume required to close the hang-off pipe rams, to shear the drill pipe string, to close a second set of pipe rams, to activate the ram locks and disconnect the lower marine riser package with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being off. In addition, the residual pressure of the dedicated subsea accumulators for emergency back up system after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. The surface accumulator shall be split into at least four bottles banks. Subsea accumulators (dedicated to the emergency back up system or part of the primary accumulators), if any, shall be split into at least two bottles banks. Each subsea multi-bottle accumulator banks shall have ROV operated valves for bank isolation.
Rule 35: If emergency back up system (acoustic, dead man system or equivalent) is installed, it should have its own dedicated and independent pilot circuit. The dedicated subsea accumulators for emergency back up system shall be connected in such a way as fluid is not lost if the supply line(s) from the rig is cut. In case of emergency back up system, dedicated subsea accumulators installed on the BOP stack are mandatory. These dedicated subsea accumulators providing energy to the pilot and the power circuit of the emergency back up system are not used during primary BOP functions. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 17 of 86
Rule 36: For surface installations, the BOP control system shall be capable of closing each ram BOP within 30 seconds. Closing time shall not exceed 30 seconds for annular BOPs smaller than 18 ¾ inches nominal bore and 45 seconds for annular preventers of 18 ¾ inches nominal bore and larger. Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram BOP close response time. For subsea installations, the BOP control system shall be capable of closing each ram BOP in 45 seconds or less. Closing time shall not exceed 60 seconds for annular BOPs. Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram BOP close response time. Time to unlatch the lower marine riser package shall not exceed 45 seconds. The required pressure for shearing the DP shall be obtained in less than two minutes.
Rule 37: For the pump system of the BOP control system the minimum requirement is two pump systems, driven by independent power sources: either 1 electrical pump system plus one air pump system or 2 electrical pump systems completely independent regarding the electric network (cables, distribution boxes) In addition, each pumping system shall be designed to fulfil, independently of the other source, the most stringent case: Either charging of the accumulator from the pre-charge pressure to the rating pressure of the accumulator in less than 15 minutes, Or closure of the annular preventer on drill pipe with correct sealing pressure and the opening of the hydraulic choke valve in less than 2 minutes. In case of two electrical pump system one electrical pump system shall be powered by the emergency generator. Pumping shall start automatically when pressure in the accumulator drops below 90% of the maximum operating pressure.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 18 of 86
Rule 38: Any surface BOP stack installation shall have at least one air or electric remote control panel located near the driller's position. Offshore a second control panel shall be installed in a safe area (tool pusher’s office or on the tender in the case of platform tender assisted mode). For subsea BOP, all control panels shall be electric and shall display all underwater functions. Indication of control fluid flow is required on each panel. Each control panel shall clearly show “open” and “closed” positions on a visual display in line with the BOP stack installed. It shall be adequately protected against fluid projection. Each control panel shall include a master shut-off valve, controls for the regulator valves (general manifold and annular specific one) and control for the by-pass valve. They shall be fitted with main alarms indicating low accumulator pressure, low level in control fluid tank and lack of power supply. A "Think first" flap shall be set as a precaution over each BSR push-button on each control panel The master control panel on the hydraulic control unit shall have a by-pass valve( by-passing the pressure regulator) to allow to have the full pressure of accumulators at the master control panel.
Rule 39: In deep and ultra-deep waters ROV intervention panel is mandatory
Rule 40: When ROV intervention is mandatory, ROV emergency functions are the following: On the LMRP: - LMRP connector primary and secondary unlocking - Choke and kill stabs primary and secondary unlocking. On the BOP stack: - Closure of hang off pipes rams and shear rams - Ram locking devices - Wellhead connector primary and secondary unlocking
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 19 of 86
Rule 41: An Emergency Battery Pack (UPS) shall be available to supply electric power to operate the BOP control system, when electrical type, for up to 24 hours. The battery pack shall supply power to the electric control panels. An Emergency Air Supply shall be available to supply air power to operate the BOP control system, when air operated type. In that case it shall supply the air remote control panels and air driven pressure regulators if these regulators are not of fail safe type.
Rule 42: For subsea BOP the link between the hydraulic control unit and the BOP stack shall be via a dual hydraulic or Electro-hydraulic cable and/or hose system providing 100 % redundancy of control for all functions of the BOP (yellow and blue pods). Total length of the flexible control cables and hoses shall be 90 m (300 feet) greater than the maximum water depth for which the system is to be used
Rule 43: An emergency back up control system (acoustic, dead man system or equivalent) shall be installed for Dynamic Positioning with the following functions:
close the hang-off set of pipe rams shear the drill pipe close a second set of pipe rams activate the ram locks disconnect the lower riser marine package
For anchored rigs, an additional acoustic control system is recommended in case of high risk operation (severe environment, high pressure target).
Rule 44: High-pressure steel pipe or high-pressure fire-resistant control hoses with a working pressure at least equal to the accumulator rating pressure shall be used. The nominal diameter shall be 1’’ minimum, so as to reduce pressure losses and consequently BOP closing time. For flexible parts, the hoses shall be steel wrapped (Coflexip type or equivalent) to provide greater resistance to fire and improved durability. Sharp bends on hoses shall absolutely be avoided.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 20 of 86
Rule 45: For surface BOPs, fluid storage capacity on the rig shall be at least twice the working volume of the accumulators. For subsea BOPs, automatic proportioning equipment is required for soluble oil. Its capacity shall be greater than the total flow-rate produced by the two pump systems. The characteristics of control fluid (including cleanliness) shall be in line with the recommendation of the manufacturer and shall be suitable for work carried out in cold areas if applicable.
Rule 46: In case of kelly, two valves are installed at the top and bottom end of the kelly: The upper Kelly valve. This valve will be closed first if necessary. The lower Kelly valve. This valve allows installation of the circulating head or of the drop-in check valve in drill pipes. In case of Top drive, there will be two IBOP safety valves: The upper safety valve remotely operated. This valve will be closed first if necessary The lower safety valve manually operated. Both the lower and upper Kelly and IBOP valves will have as a minimum the same pressure rating as the BOP. Rule 47: A DICV sub and a float valve near the bit shall be incorporated in a drill or work string on: All drilling phases of exploration and delineation wells, Before entering the reservoir on development wells, As a protection against shallow gas influx. On a floating rig, a DICV sub shall always be incorporated in a drill or work string.
Rule 48: One spare drill pipe safety valve with lifting device shall be permanently kept on the drill floor with cross-over adapted to string pipes in use.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 21 of 86
Rule 49: Each drilling or work over rig shall be provided with an atmospheric degasser. Minimum requirements are: 10 ft Mud seal height 8’’ nominal pipe for gas exhaust a siphon breaker not tied into the vent line
Rule 50: A Well Control Equipment log book is mandatory on each rig and will be part of the site Safety Register It is the drilling and completion supervisor’s role to periodically verify that the Well Control Equipment log book is issued, available and up to date. The rig Well Control Equipment log book is constituted with: Certification package by the manufacturer or an approved third party with API monogram. API manufacturing documentation, NACE certification including raw material traceability. Manufacturers must provide full traceability of Well Control Equipment and spare parts. Commissioning Well Control Equipment inspection report and action plan inspection reports and following action plans after periodic inspections of Well Control Equipment any inspection reports after repair or change of equipment. repair / change log book. Dates, technical reason for change, part number and working limitations of installed components (pressure, temperature rating, OBM compatibility, etc) shall be recorded and approved by the rig manager. maintenance log book.
Rule 51: A new certification is required if, at the rig acceptance stage, the BOP documents file (previous certificates, log book, etc) is missing or badly completed. A complete BOP stack dismantling and inspection shall be carried out for certification when control equipment has been stacked for a period equal to or greater than 6 months At the rig acceptance stage, periodic inspections will be checked
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 22 of 86
Rule 52: A complete BOP stack dismantling and inspection shall be carried out for certification if: equipment is in continuous use for more than 5 years equipment was subject to abnormal conditions (excessive shock, fire, etc).
Rule 53: A new certification is required in the case of repair inducing hot work
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 23 of 86
2. FOREWORD
2.1 INDICATOR Rule which needs derogation
2.2 LIMITS and DEFINITIONS This rule gives configuration, rating and maintenance policy for well closure systems involved in drilling, work-over and well testing. Diverting systems are mentioned but are more specifically detailed in the CR FPP 215 ‘’Shallow gas’’. Efficiency and reliability are required for this mechanical barrier which is the final barrier in place if the hydraulic barrier is damaged. The minimum requirements are dictated by the API RP 53 standard (with reference to RP 16E). This rule retains the main points of this standard but aims to highlight any specific points that diverge from API or are more stringent. Points not addressed shall be in accordance with the API standard. Equipment testing policy is defined in CR FPP 165 “Well Control equipment: pressure tests”. “Deep water” is defined as the water depths included between 300 meters and 1000 meters. “Ultra –deep water” is defined as the water depths greater than 1000 meters. “HP” (high pressure) wells are the wells with MEWHP above 10000 psi. “HP/HT” (high pressure/high temperature) wells are the wells with MEWHP above 10000 psi and bottom hole temperature above 350°F.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Date: 15/10/2003
Page: 24 of 86
2.3 GLOSSARY
BOP
Blow Out Preventer
BR
Blind Rams
BSR
Blind Shear Rams
CL
Choke Line
CV
Check Valve
DICV = DIBPV
Drop In Check Valve or Drop In Back Pressure Valve
DP
Drill Pipe
IBOP
Internal BOP
KL
Kill Line
LMRP
Lower Marine Riser Package
MAC
Manual Choke
MEWHP
Maximum Expected Wellhead Pressure
MGS
Mud Gas Separator
ML
Mud Line
Padm
Admissible Pressure
PR
Pipe Rams
ROC
Remotely Operated Choke
SIMOPS
Simultaneous Operations
VBR
Variable Bore Rams
XO
Cross Over Sub
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 25 of 86
3. BOP STACK CONFIGURATION PHILOSOPHY AND LIMITATIONS
3.1 Position of the BSR The BSR installation in the lowermost cavity could be considered as the most effective position for an ultimate barrier. But the major drawback of this position is to lose the drill string when the BSR are activated. As we want to keep the possibility of conventional well control after shearing the drill string, the drill pipe has to be hung-off prior to shearing and consequently the BSR can not be located in the lowermost cavity. As we consider the outlets of the choke lines on the BOP stack as a weak point (possible wash out with uncontrolled fluid) which could lead to a catastrophic consequence, we want, when possible, no choke lines located below the lowermost set of pipe rams which must be kept as the last barrier. Consequently, in the case of a 3 or more sets of rams BOP stack, the outlets of all the choke lines have to be located above the lowermost set of pipe rams. As the choke line has to be located below the set of pipe rams used to hang-off before shearing, the only possible position of the BSR for a 3 sets of rams BOP stack is in the top cavity. For harmonisation reason the BSR is located in the top cavity of a 4 sets of rams BOP stack. Note: The wellbore pressure can cause cases where the pipe cannot be sheared (operating pressure must overcome the shearing force plus the well bore pressure). The position of BSR on top of the BOP stack is helpful as, when the drill pipe is hung-off, the bleed-off of the wellbore is possible before shearing which is not possible when the BSR are at the lowermost position of the BOP stack.
3.2 Position of the killing lines As we want to have the possibility to bull-head in the well when the lowermost rams are closed one kill line must be located below the lowermost set of rams. The risk of wash out of this kill line is very low as, always, a clean and controlled fluid is pumped through this line. The consequence is that the line connected below the lowermost ram preventer shall never be used to evacuate an influx. After hanging-off and shearing the drill pipe, we want to kill the well by circulation down the drill string with return through the choke line and without dismantling the set up. Therefore, the upper kill line shall be connected just below the BSR. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 26 of 86
3.3 Position of the choke line for a 3 sets of rams BOP stack As already mentioned the choke line must not be located below the lowermost set of pipe rams. The choke line has to be located below a set of pipe rams in order to circulate through the choke manifold when closed on pipe rams. For that reason, the choke line cannot be located below the BSR in the top cavity. Consequently the only possible position is below the middle pipe rams. The corollary is that the well cannot be circulated conventionally or volumetrically killed when shut in on the lowermost set of pipe rams.
3.4 Position of the choke lines for a 4 or more sets of rams BOP stack As this configuration is for high risk wells and / or when a tapered drill string is used 2 choke lines are mandatory to increase the reliability and the flexibility of the set up. As already mentioned no choke line can be located below the lowermost set of pipe rams. At least one choke line must be located below a set of pipe rams in order to circulate through the choke manifold when closed on this set of pipe rams.
3.5 Stripping of the drill pipe string in the well with a 3 sets of rams BOP stack As we want to keep the lowermost set of rams as a mean of shutting the well if other component of the BOP stack fails, these rams shall never be subjected to the wear and stress of stripping operations. Therefore, the minimum configuration for a 3 sets of rams BOP stack (with one choke line below the intermediate set of pipe rams) only allows stripping of the drill pipe string through the annular preventer and consequently, the installation of a stripping bottle on the annular preventer is recommended. If stripping between annular preventer and the intermediate set of pipe rams is wanted a second choke line should be connected above the intermediate pipe rams. When rams to rams stripping is a requirement for a high risk well, an additional set of pipe rams and a second choke line shall be installed.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 27 of 86
3.6 Stripping of the drill pipe string in the well with a 4 or more sets of rams BOP stack As mentioned above, a second choke line is a requirement on a 4 or more sets of rams BOP stack. If rams to rams stripping is a requirement, the position of the two choke lines and the spacing between rams will be adjusted to allow rams to rams stripping on the main drill pipe string (s). The lowermost set of rams will never be used for stripping. For subsea BOP, if rams to rams stripping is a requirement, the position of the upper kill line (as this line could be used as a choke line in subsea BOP), the position of the two choke lines and the spacing between rams will be adjusted to allow rams to rams stripping on the main drill pipe string(s). The lowermost set of rams will never be used for stripping. Note: For subsea BOP, rams to rams stripping is often unpractical.
3.7 Casing rams Consideration for the use of casing rams will be dependent on the inherent risks of the section to be cased: For simple cases, to be validated by the drilling manager with a risk assessment, we consider that: - the bag preventer is capable to treat a well flow during running down a casing string - and, if the situation worsen, the use of a proper cross-over sub will allow to shut in the well with the pipe rams For the other cases, the use of casing rams is mandatory. The pressure test of the casing rams themselves at the MEWHP is strongly recommended. (Note: The position of the BSR in the top cavity allows the BOP body test at the MEWHP).
3.8 Shooting nipple The pack-off assembly generally used on wire line BOP above the shooting nipple is sealing on a non moving stranded cable up to 2 500 psi. If the cable is moved, the sealing rubbers of the pack-off will be destroyed. Normal procedure when killing a well during logging does not allow to move the cable. Some special equipment is available for controlling the well with the cable moving but generally not on the rig. Consequently, the shooting nipple is to be used on well with a MEWHP below 2 500 psi and without H2S and our recommendations are: This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 28 of 86
For logging operations, the shooting nipple is not mandatory. Firstly, a hydraulic wire cutter is available on rig floor in order to cut the wire if needed and secondly, BSR are installed in the BOP stack in case the hydraulic wire cutter fails. Moreover, the stability of the well is ensured before starting POOH. For perforations operations, two cases exist: - On wells with a MEWHP below 2 500 psi and without H2S, a shooting nipple is rigged up in the annular preventer and chained to avoid any upward movement. If any problem, the cable is stopped and the pack-off activated to allow to kill the well. - On wells with H2S or with a MEWHP above 2 500 psi, the use of a shooting nipple is forbidden.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 29 of 86
4. BOP REQUIREMENT Rule 1:
All drilling and workover operations shall use a Blow Out Preventer as soon as the architecture allows to shut the well in until the well is plugged or a completion with mechanical barriers is in place (refer to CR FPP 130). In the event of programmed operations, without a Blow Out Preventer (i.e. drilling shallow reservoir with a diverting system) an appropriate risk assessment shall be carried out and documented.
The use of a diverter system as a BOP on exploration wells is not recommended. Even if the rig is equipped with a 2000 psi diverter unit, this cannot be considered as a valid BOP. A compatible 2000/3000 psi BOP stack will be used as soon as closure of the well is possible.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 30 of 86
5. MAIN CONSIDERATIONS
5.1 WORKING PRESSURE OF WELL CONTROL EQUIPMENT The Well Control Equipment is one of the main components of the structural barrier when drilling or completing a well. The rating of the Well Control Equipment will be in accordance with the MEWHP of the operational phase during which the equipment will be used. Refer to CR FPP 225 “Casing design” – chapter 8.3.3- for MEWHP evaluation. Constraints due to special pumping operations (acid job, stimulation, etc.) will be taken into consideration if foreseen. For exploration wells, the maximum formation pressure gradients given by the geologist department will be taken into account for the MEWHP estimation (basically made on a well full of gas).MEWHP should not be confused with Padm. Padm is the wellhead pressure limit based on the weakest point of surface equipment, casing and casing shoe. Well Control equipment could be used at its API WP unless any de-rating applies, for example: temperature limitations, specific points mentioned in inspection reports (wear, existing repair, etc) or H2S in fluids.
The WP of an equipment is equal to its API WP minus any de-rating: WP= API WP * K Rule 2:
with K= de-rating ratio.
The Working Pressure of all Well Control Equipment subject to well pressure shall be greater than or equal to the MEWHP of the operational phase during which the equipment will be used.
For deep or ultra-deep water stacks, water pressure will be ignored when calculating the subsea well control equipment working pressure. Six working pressure categories are given by API:
2,000 psi/138 bar 3,000 psi/207 bar 5,000 psi/345 bar 10,000 psi/689 bar 15,000 psi/1035 bar 20,000 psi/1379 bar This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 31 of 86
5.2 MUD CROSSES The use of double and/or triple stage BOPs with lateral outlets below the rams allows: the elimination of mud cross the reduction of stack heights the reduction of the number of flanges or bolted clamps (potential leak points) The use of mud cross on all BOP stacks is not recommended. However, mud cross is allowed on surface stacks when MEWHP < or equal to 5 000 psi when pipe ram preventers are not fitted with lateral outlets Rule 3:
The use of mud cross is not allowed on all BOP stacks when MEWH > 5 000 psi.
If necessary for adequate spacing between rams, spools could be used.
5.3 BOP OUTLETS Rule 4:
Although API 6A allows 2" LP threaded connections on 5 000 psi WP equipment, welded flanges or hub connections are mandatory on all pressure systems when MEWHP > 3000 psi.
Rule 5:
Kill line outlet shall not be smaller than 2”1/16 nominal, Choke line outlet shall not be smaller than 3"1/16 nominal.
5.4 BLIND RAMS Rule 6:
Blind rams shall always been installed in the uppermost set of rams of any BOP stack.
5.5 SHEAR FUNCTION Rule 7:
For any operational phase where hydrocarbon bearing reservoirs are foreseen, shear function is mandatory on a BOP stack, except on onshore development wells when MEWP< or = 5 000 psi, with low GOR oil reservoirs ( 5 000 psi, annular preventers may be of a WP immediately lower than the WP of the BOP’s rams preventers. A dedicated expansion bottle on the opening and closing chambers of the annular preventer is recommended for improved stripping capabilities and reduced damage on packing. For subsea BOP stack two annular preventers are recommended. One annular preventer could be located below the upper connector, the second one could be located above the upper connector. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 34 of 86
Rule 13: Two 10 000 psi WP annular preventers shall be installed for drilling subsea wells with MEWHP>10 000 psi. Two annular preventers shall be installed for drilling deep or ultra-deep water subsea wells with MEWHP> or = 5 000 psi.
5.12 RING GASKETS Rule 14: New and clean ring gaskets shall be installed each time BOP components are re-assembled. Ring gasket shall not be reused. Only equipment recommended by BOP manufacturer shall be used for well control equipment replacement parts. The ring groove is checked and cleaned with oil before make-up, but oil is not be left in the groove. Grease is not used. The use of face-to-face connections (BX flanges or equivalent) is recommended between WH and BOP with a jack-up configuration. All gaskets that include an additional elastomeric or non-elastomeric sealing (Hy-Car for example) are not be considered as permanent metal to metal seal systems. If high temperature, gaskets for LMRP, Wellhead, KL and CL hydraulic connectors will be stainless steel or cadmium plated gaskets with no non-metallic sealing parts.
5.13 WELL CONTROL EQUIPMENT INFORMATION ON RIG Rule 15: Clear and actual schematics of the choke manifold, stand pipe manifolds and BOP lay out shall be displayed next to the posters of well shut-in and control procedures in the Drill Master Cabin, at the choke manifold, at the BOP control unit, at each BOP remote control panel, at the tool pusher and the Company Man offices and at the mud logging unit.
5.14 BOP STACK INSTALLATION Valves position should be in accordance with CR FPP 230 “Well shut in”.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 35 of 86
5.14.1 Surface BOP stack Correct line-up (concentricity) of the rotary table, BOPs and wellhead provide proper function and safeguarding of well control equipment. The installation and good working condition of the BOP and wellhead valves hand wheels will be checked. Wellhead valve hand wheels will be secured with safety pins, not nuts. Blow Out Preventer anchoring should be checked every week. In the case of jack-ups, riser centralising and tensioning system should have a continuous monitoring and should be checked daily.
5.14.2 Subsea BOP stack Subsea BOPs will not be run on wellheads at an angle greater than 1,5° to avoid keyseating damage to the bore of the wellhead, BOP and riser. Connecting the BOP onto the subsea wellhead housing during a large heave could damage the equipment. The drilling contractor will specify the limitation in their procedures according to the heave compensator system in use. When running in, the various hoses will be attached properly to the riser. It is recommended that during BOP running/retrieving operations: The different types of power sources actuating the functions is isolated (“off” position) The LMRP hydraulic connector is run with the riser "connector lock" function, the wellhead "connector unlock" function and "pod latch" and/or "stab extend" functions activated. All other functions are in the neutral (blocked) position The emergency back up system neutralisation is activated On template drilling, the unit is shifted down current away from the well axis. Prior to landing the BOP stack, the sealing area of the WH main hub will be closely observed using a subsea camera or ROV.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 36 of 86
5.15 H2S ENVIRONMENT The H2S compatibility of Well Control Equipment should be thoroughly assessed according to the working programme. Refer to API RP 53 - sections 19.6 and 20 and CR FPP 170: H2S policy § 7.5. In particular: Elastomeric components In the presence of H2S, the service life of elastomers shortens as temperature increases. Any elastomeric component on a BOP is recommended to be changed out as soon as possible after exposure to hydrogen sulphide under pressure. Acceptable materials: - Fluoro-polymers such as Teflon or Ryton - Fluoro-elastomers such as Viton or Kalrez Metallic components In H2S environment, all metallic components which may be in contact with well fluids, should meet the requirements of NACE Standard MR-01-75. Shear rams which involve high strength materials with a hogh hardness can be susceptible to H2S cracking, even on H2S trim BOP’s. The compatibility of shear rams with H2S shall always be verified.
Sour service identification Components should be marked in accordance with NACE MR-01-75 Section 5.4 to show their suitability for sour service. Temporary marking shall be in agreement with COMPANY GS COR 170 Section 8.3.
5.16 TEMPERATURE / FLUID COMPATIBILITY The temperature rating of all elastomers (rams, bonnets, valves, etc..) and their resistance to oil base mud and completion fluid (including the annular bag) should be thoroughly assessed according to the working programme. Standard elastomers are rated from 200-250°F; 350-380°F peak temperature products exist and can replace them.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 37 of 86
5.17 HP/HT WELLS Specific points: Elastomers will be certified for a continuous 250°F Temperature rating and a 380°F peak T° rating (for an hour): BOP rams, KL/CL valves, and riser joints at each KL/CL pin end. Hoses will be designed to appropriate temperature, pressure and well fluids: Coflon lining is the most appropriated material for extreme cases. To avoid exceeding these T° limits the temperature will be monitored on the choke line, upstream of the choke, and on the flow line, with read-out in the Driller's cabin. For offshore wells, two straight overboard lines will be installed from buffer tank to port/starboard sides, with interlocked hydraulic valves manually controlled. The pressure rating of the overboard lines will not be less than the WP of the buffer tank.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 38 of 86
6. CONFIGURATION OF BLOW OUT PREVENTERS 6.1 SURFACE STACK CONFIGURATION 6.1.1 MEWHP < or = 3 000 psi Rule 16: For surface stack and for MEWHP up to and including 3 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 1 in appendix 1): One annular preventer. Two ram type preventers with BR or BSR in the top cavity. One kill line and one choke line connected below the lowermost set of rams. When working on “non-flowing” reservoirs, the stack can be reduced to one annular and one single equipped with blind rams. 6.1.2 MEWHP > 3 000 psi and < or = 5 000 psi Rule 17: For surface stack and for MEWHP above 3 000 psi up to and including to 5 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 2 in appendix 1): One annular preventer. If no shear function is required: Two ram type preventers with BR in the top cavity. One kill line and one choke line connected below the lowermost set of rams. If shear function is required: Three singles or one double and one single ram type preventers with BSR in the top cavity. The upper kill line shall be installed below the uppermost set of rams (BSR). The lower kill line shall be connected below the lowermost set of rams. The choke line shall enter the BOP stack above the lowermost set of pipe rams. Stripping with the lowermost set of pipe rams is not allowed Redundancy of rams for each main DP string sizes is recommended and can be maintained by using VBR. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 39 of 86
6.1.3 MEWHP > 5 000 psi and < or = 10 000psi
Rule 18: For surface stack and for MEWHP above 5 000 psi up to and including 10 000 psi, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 3 in appendix 1): One annular preventer. Three singles or one double and one single ram type preventers. The upper kill line shall be installed below the uppermost set of rams (BSR). The lower kill line shall be connected below the lowermost set of rams. The choke line shall enter the BOP stack above the lowermost set of pipe rams. Stripping with the lowermost set of pipe rams is not allowed. Redundancy of rams for each main DP string sizes is mandatory. One fixed pipe ram for each main DP string sizes is recommended. On high risk wells or If temperature is excessive for VBR or if two main drill pipe strings are in use, a four ram type preventers BOP stack is recommended with one secondary choke line. When rams to rams stripping on the main drill pipe string(s) is required, the position of the two choke lines and the spacing between rams will be adjusted accordingly.
6.1.4 MEWHP>10 000 psi
Rule 19: For surface stack and for MEWHP > 10 000 psi, the minimum BOP configuration should be the same as for a 10 000 psi WP excepted that a four ram type preventers BOP stack with one secondary choke line is mandatory. (see figure 4 in appendix 1). When rams to rams stripping on the main drill pipe string(s) is required, the position of the two choke lines and the spacing between rams will be adjusted accordingly. One fixed pipe ram for each main DP string sizes is recommended.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 40 of 86
6.2 SUBSEA BOP CONFIGURATION The underwater BOP equipment involves either a single stack or a two-stack system. Single stack system is currently widely used for deep or ultra-deep water operations. A number of variations in the position of annular preventers, PR, BSR, kill and choke lines connections are in use in subsea BOP stacks throughout the industry as many have been designed by Contractors or Operators with different operational preferences. The configurations defined in rule 20 and rule 21 are to be used . If it is not possible (delivery/cost), the limitations and possibilities of any particular layout should be highlighted in the derogation’s request, the procedures for well shut-in and killing adapted and the crew specifically trained. 6.2.1 Single stack System Rule 20: For subsea single stack BOP stack and for subsea small bore BOP stack, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 5 in appendix 1):
One annular preventer. Upper hydraulic connector (WP = annular preventer WP). Four ram type preventers or two double ram type preventers. Lower wellhead hydraulic connector (WP > or = ram type preventers WP) One upper kill line hooked up below the BSR and one lower kill line below the lowermost set of pipe rams, these lines having a common part. Two choke lines with a common part. Stripping with the lowermost set of pipe rams is not allowed. Redundancy of rams for each main DP string sizes is mandatory If temperature is excessive for VBR, the redundancy between ram preventers on the main DP string sizes shall be achieved by adding additional fixed pipe ram preventers below the top BSR. One fixed pipe ram for each main DP string sizes is recommended. On high risk wells or If temperature is excessive for VBR or if two main drill pipe strings are in use, a five ram type preventers BOP stack is recommended. When rams to rams stripping on the main drill pipe string(s) is required, the position of the upper kill line (as this line could be used as a choke line in subsea BOP), the position of the two choke lines and the spacing between rams will be adjusted accordingly. Note: For subsea BOP, rams to rams stripping is often unpractical. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 41 of 86
6.2.2 Two stack System This consists of a 2000 psi WP large bore BOP stack (generally 21’’1/4) and a smaller bore stack (generally 13’’5/8 – 10 000 psi WP).
6.2.2.1 Large bore BOP stack Rule 21: For subsea large bore BOP stack, the minimum BOP configuration shall be, as arranged from top to bottom (see figure 6 in appendix 1):
One annular preventer. Two ram type preventers. One kill line hooked up below the BR or BSR. One choke line hooked up below the lowermost set of PR.
6.2.2.2 Small bore stack MEWHP > or = 5 000 psi For Subsea small bore stack BOP, the minimum BOP configuration is as the "subsea single stack BOP stack " described in rule 20.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 42 of 86
7. CHOKE MANIFOLD, KILL & CHOKE LINES
7.1 GENERAL The kill and choke lines and the choke manifold system consist of high-pressure hoses, pipes, flanges, valves and manual/hydraulically operated adjustable chokes. It is used to stop and to handle the fluid flow from the well-bore and to bleed off the well-bore pressure after a kick occurred. Rule 22: Lines and manifold designed for dynamic loads shall be securely fastened. Flexible KL and CL high-pressure hoses longer than 4m and valves assemblies at BOP outlets shall be supported to avoid the weak point initiate by the heavy weight of valves and flexible hoses. All valves shall be marked with a colour code according to their normal position while drilling. Where two valves exist on a "normally closed" line, the downstream valve only will be usually closed. When two valves exist on an outlet, the valve closest to the well will be considered as a master valve to be used only in the event of repair on the outer valve. Rule 23: For surface and subsea BOP, in the case of a 3 or more sets of rams BOP stack, the line connected below the lowermost ram preventer shall not be used to evacuate an influx.
Rule 24: For subsea BOP, the choke manifold connection to the stand pipe manifold shall be designed in such a way as to allow pumping through the KL with returns through the CL, or vice versa but rule 22 still applies. When the choke manifold and the stand pipe manifold are connected, there is a pressure rating risk which should be properly evaluated and mitigation measures have to be in place.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 43 of 86
7.2 KILL LINES
7.2.1 Surface BOP Rule 25: On surface BOP stacks, KL shall be at least 2” ID. When MEWHP< 10 000 psi, each KL shall be equipped with two manual full bore valves plus a check valve. In case no check valve is installed, minimum one of the two full bore valves shall be remotely operated. When MEWHP> or =10 000 psi, each KL shall be equipped with two full-bore valves plus a check valve. One of the two valves shall be remotely operated. In case no check valve is installed, both full bore valves shall be remotely operated. During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. The two kill lines can have a common part.
7.2.2 Subsea BOP Rule 26: On subsea BOP stacks each KL shall be at least 3” ID and equipped with two full bore remotely operated valves (fail safe closed). During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. The kill lines have a common part.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 44 of 86
7.3 CHOKE LINES :
7.3.1 Surface BOP Rule 27: On surface BOP stacks, CL shall be at least 3’’ ID. Two full-bore valves shall be installed on each CL. One of these two valves shall be remotely operated. During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. If two choke lines, they shall be connected independently to the choke manifold and be completely isolated from the other by at least two valves. "CHICKSAN" type sections are not allowed on choke lines. High-pressure flexible hoses (Coflexip type or equivalent) shall be used. This line will be as straight as possible and correctly anchored against vibration.
7.3.2 Subsea BOP stacks Rule 28: On subsea BOP stacks each CL shall be at least 3” ID and equipped with two full bore remotely operated valves (fail safe closed). During operations, all valves shall be fully opened or fully closed (no valve in intermediate position) as per CR 230 well shut in. "CHICKSAN" type sections are not allowed on choke lines. High-pressure flexible hoses (Coflexip type or equivalent) shall be used. The choke lines have a common part. For deep water application, 4’’ and 4’’1/2 choke lines are now currently used to reduce pressure drop during circulation through the choke.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 45 of 86
7.4 CHOKE MANIFOLD
7.4.1 Number of chokes Rule 29: Number of chokes of the choke manifold: 2 M.A.C. 2 M.A.C. + 1 R.O.C. 1 M.A.C. + 2 R.O.C.
if MEWHP ≤ 3 000 psi if MEWHP > 3 000 and ≤ 10 000 psi if MEWHP > 10 000 psi
7.4.2 General design and operating: Drawings of basic control manifolds are given in Figures 8, 9 and 10 in appendix 1 for surface and subsea BOP stacks. Rule 30: The minimum size for choke manifold equipment is 3" nominal. If two choke lines, two independent pressure sensors shall be available on each line and be completely isolated from the other by at least two valves. All chokes shall discharge directly into a at least 3’’ ID erosion nipple, at least 3 ft long and 1’’1/4 thick. Lead target flanges shall exist on the buffer chamber in front of all lines coming from the well. The buffer chamber shall provide direct exits to the mud pit, vertical degasser, horizontal flare (onshore) or burner boom(s) (offshore) and overboard line. At least one gate valve shall be installed downstream of each choke but ahead of the buffer chamber. This valve may have a working pressure one step down of the upstream side working pressure. A bypass shall be provided from the choke line to the buffer chamber without passing through the chokes. The two gate valves and the piping controlling the bleed line shall have full rate working pressure of the BOP stack preventers. The installation, upstream of chokes, of a Glycol or equivalent injection system is mandatory if hydrates formation is anticipated. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 46 of 86
Rule 31: When remotely operated choke is mandatory, its control panel shall be near the Driller. It shall include, in addition to manometers (DP pressure, casing pressure) and choke monitor, the following: an alarm set on Padm A pump strokes totalizer. The remotely operated choke shall be equipped with an emergency backup system in the event of primary energy supply shut down or failure (hand pump or nitrogen). Casing annular pressure, pump stroke counter and drill pipe pressure (Sensitivity to low pressures shall be verified) are recommended at the choke manifold. This enables a kick to be controlled from the manifold whatever choke is selected All valves and chokes of the choke manifold should be easily accessible. If possible, a vertical choke manifold set-up is recommended.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 47 of 86
8. BOP CONTROL SYSTEM
8.1 GENERAL The BOP control system ensures the correct operation of all installed preventers, remote control valves and disconnection devices. This system includes:
An automatic hydraulic accumulation system and control manifold One or two remote control panels one actuation system High-pressure hydraulic lines
A schematic of a BOP control system is given in figure 11 in appendix 1. Accumulators for use with surface and subsea BOP are rated from 3 000 psi (standard case) to 5000 psi (deep or ultra-deep waters)
8.2 HYDRAULIC CONTROL UNIT Rule 32: The hydraulic control unit with the master control panel shall be easily accessible, on the escape way and not at the rig floor, in a non-classified (non-hazardous) area. It shall be adequately protected against dropped objects and fire. Onshore, it shall be installed at least at 15 m from the wellhead. If possible, the hydraulic control unit will not be located in direct view of the BOP or wellhead.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 48 of 86
8.2.1 ACCUMULATORS VOLUME AND PRESSURE
8.2.1.1 Surface BOP RULE 33: For surface BOP, the total accumulator volume shall be equal to the volume required for the full closure and full opening of all preventers (rams and bag) plus all remote operated valves with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being off. If shear rams are installed, the residual pressure of the accumulators after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. This accumulator shall be split into at least two bottles banks. Each multibottle accumulator banks shall have valve for bank isolation.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 49 of 86
8.2.1.2 Subsea BOP Note: Some times subsea accumulators are installed on BOP stack in order to improve closing performance times. In that case these subsea accumulators are part of the primary accumulators.
Rule 34: For subsea BOP, the total primary accumulators volume shall be equal to one and haft times the volume required for the full closure and opening of all preventers (rams and bags ) plus all remote operated valves with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being out of service. In addition, the residual pressure of the total primary accumulators after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. In case subsea accumulators are part of the primary system, the total primary accumulators volume shall include the volume of the subsea accumulators on the BOP stack. In case of dedicated subsea accumulators for emergency back up system, the volume of the dedicated subsea accumulators for emergency back up system shall be equal to one and half times the volume required to close the hang-off pipe rams, to shear the drill pipe string, to close a second set of pipe rams, to activate the ram locks and disconnect the lower marine riser package with a residual pressure which does not drop below the nitrogen pre-charge pressure plus 200 psi, the pumping systems being off. In addition, the residual pressure of the dedicated subsea accumulators for emergency back up system after having closed the hang-off pipe rams and sheared the drill pipe string shall be at least equal to the manufacturer’s recommended pressure, the pumping systems being off. The surface accumulator shall be split into at least four bottles banks. Subsea accumulators (dedicated to the emergency back up system or part of the primary accumulators), if any, shall be split into at least two bottles banks. Each subsea multi-bottle accumulator banks shall have ROV operated valves for bank isolation. An example of accumulator volume calculation is given in appendix 3.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 50 of 86
Rule 35: If emergency back up system (acoustic, dead man system or equivalent) is installed, it should have its own dedicated and independent pilot circuit. The dedicated subsea accumulators for emergency back up system shall be connected in such a way as fluid is not lost if the supply line(s) from the rig is cut. In case of emergency back up system, dedicated subsea accumulators installed on the BOP stack are mandatory. These dedicated subsea accumulators providing energy to the pilot and the power circuit of the emergency back up system are not used during primary BOP functions.
8.2.2 CLOSING TIME PERFORMANCES Rule 36: For surface installations, the BOP control system shall be capable of closing each ram BOP within 30 seconds. Closing time shall not exceed 30 seconds for annular BOPs smaller than 18 ¾ inches nominal bore and 45 seconds for annular preventers of 18 ¾ inches nominal bore and larger. Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram BOP close response time. For subsea installations, the BOP control system shall be capable of closing each ram BOP in 45 seconds or less. Closing time shall not exceed 60 seconds for annular BOPs. Response time for choke and kill valves (either open or close) shall not exceed the minimum observed ram BOP close response time. Time to unlatch the lower marine riser package shall not exceed 45 seconds. The required pressure for shearing the DP shall be obtained in less than two minutes.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 51 of 86
8.2.3 PUMPS SYSTEM Rule 37: For the pump system of the BOP control system the minimum requirement is two pump systems, driven by independent power sources: either 1 electrical pump system plus one air pump system or 2 electrical pump systems completely independent regarding the electric network (cables, distribution boxes) In addition, each pumping system shall be designed to fulfil, independently of the other source, the most stringent case: Either charging of the accumulator from the pre-charge pressure to the rating pressure of the accumulator in less than 15 minutes, Or closure of the annular preventer on drill pipe with correct sealing pressure and the opening of the hydraulic choke valve in less than 2 minutes. In case of two electrical pump system one electrical pump system shall be powered by the emergency generator. Pumping shall start automatically when pressure in the accumulator drops below 90% of the maximum operating pressure.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 52 of 86
8.3 CONTROL PANELS
8.3.1 COMMON CONTROL PANELS Rule 38: Any surface BOP stack installation shall have at least one air or electric remote control panel located near the driller's position. Offshore a second control panel shall be installed in a safe area (tool pusher’s office or on the tender in the case of platform tender assisted mode). For subsea BOP, all control panels shall be electric and shall display all underwater functions. Indication of control fluid flow is required on each panel. Each control panel shall clearly show “open” and “closed” positions on a visual display in line with the BOP stack installed. It shall be adequately protected against fluid projection. Each control panel shall include a master shut-off valve, controls for the regulator valves (general manifold and annular specific one) and control for the by-pass valve. They shall be fitted with main alarms indicating low accumulator pressure, low level in control fluid tank and lack of power supply. A "Think first" flap shall be set as a precaution over each BSR push-button on each control panel The master control panel on the hydraulic control unit shall have a by-pass valve( by-passing the pressure regulator) to allow to have the full pressure of accumulators at the master control panel.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 53 of 86
8.3.2 ROV INTERVENTION PANEL Rule 39: In deep and ultra-deep waters ROV intervention panel is mandatory For the other cases it is recommended to have a ROV intervention panel. Rule 40: When ROV intervention is mandatory, ROV emergency functions are the following: On the LMRP: - LMRP connector primary and secondary unlocking - Choke and kill stabs primary and secondary unlocking. On the BOP stack: - Closure of hang off pipes rams and shear rams - Ram locking devices - Wellhead connector primary and secondary unlocking One function could be added for the closure of a second set of pipe rams.
8.4 ACTUATION SYSTEM Rule 41: An Emergency Battery Pack (UPS) shall be available to supply electric power to operate the BOP control system, when electrical type, for up to 24 hours. The battery pack shall supply power to the electric control panels. An Emergency Air Supply shall be available to supply air power to operate the BOP control system, when air operated type. In that case it shall supply the air remote control panels and air driven pressure regulators if these regulators are not of fail safe type. If air driven pressure regulators are used, fail safe pressure regulators are recommended on the hydraulic control unit manifold. Rule 42: For subsea BOP the link between the hydraulic control unit and the BOP stack shall be via a dual hydraulic or Electro-hydraulic cable and/or hose system providing 100 % redundancy of control for all functions of the BOP (yellow and blue pods). Total length of the flexible control cables and hoses shall be 90 m (300 feet) greater than the maximum water depth for which the system is to be used
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 54 of 86
Rule 43: An emergency back up control system (acoustic, dead man system or equivalent) shall be installed for Dynamic Positioning with the following functions:
close the hang-off set of pipe rams shear the drill pipe close a second set of pipe rams activate the ram locks disconnect the lower riser marine package
For anchored rigs, an additional acoustic control system is recommended in case of high risk operation (severe environment, high pressure target).
8.5 PIPING The various lines operating the BOP functions will be clearly identified. The condition of the flexible hoses will be investigated at regular intervals. Rule 44: High-pressure steel pipe or high-pressure fire-resistant control hoses with a working pressure at least equal to the accumulator rating pressure shall be used. The nominal diameter shall be 1’’ minimum, so as to reduce pressure losses and consequently BOP closing time. For flexible parts, the hoses shall be steel wrapped (Coflexip type or equivalent) to provide greater resistance to fire and improved durability. Sharp bends on hoses shall absolutely be avoided.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 55 of 86
8.6 CONTROL FLUID For surface BOP stack, hydraulic oil is generally used and soluble oil could also be considered. For subsea BOPs, a soluble oil/water mixture is used. Rule 45: For surface BOPs, fluid storage capacity on the rig shall be at least twice the working volume of the accumulators. For subsea BOPs, automatic proportioning equipment is required for soluble oil. Its capacity shall be greater than the total flow-rate produced by the two pump systems. The characteristics of control fluid (including cleanliness) shall be in line with the recommendation of the manufacturer and shall be suitable for work carried out in cold areas if applicable.
8.7 DIVERTER CONTROL SYSTEM Refer to CR FPP 215 “Shallow Gas”. The diverter control system may be either independent, or supplied with hydraulic control pressure from the BOP control system. In the latter case, an isolation valve with clear labelling is recommended . Diverter control panels separated from the BOP panels but installed at the same location are recommended.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 56 of 86
9. DRILL STRING SAFETY VALVES
9.1 EQUIPMENT IN DRILL STRING
9.1.1 Kelly / Top drive system valves Rule 46: In case of kelly, two valves are installed at the top and bottom end of the kelly: The upper Kelly valve. This valve will be closed first if necessary. The lower Kelly valve. This valve allows installation of the circulating head or of the drop-in check valve in drill pipes. In case of Top drive, there will be two IBOP safety valves: The upper safety valve remotely operated. This valve will be closed first if necessary The lower safety valve manually operated. Both the lower and upper Kelly and IBOP valves will have as a minimum the same pressure rating as the BOP. The use of these two valves as a mud saver is not recommended. It will be verified that the drop-in check valve could pass through these valves.
9.1.2 Drill string valves Rule 47: A DICV sub and a float valve near the bit shall be incorporated in a drill or work string on: All drilling phases of exploration and delineation wells, Before entering the reservoir on development wells, As a protection against shallow gas influx. On a floating rig, a DICV sub shall always be incorporated in a drill or work string.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 57 of 86
The DICV dart is pumped into a special sub (landing sub) located on top of the drill collars or the HWDP. This sub will be positioned in order to be above the potential back off or severing point in the event of a stuck BHA. When ever compatible with the BHA used, a near bit float valve will be installed in a drill or work string . Utilisation of a float valve in the drill string generally requires the drill pipe to be completely filled up while tripping in and does not always allow direct drill pipe pressure measurement in the event of a kick. To overcome these handicaps, a model "GC" Baker float valve equipped with "GA" flapper (with nozzle) is a good compromise. If the float valve is installed, the DICV is used as a back up.
9.2 EQUIPMENT READY ON RIG FLOOR
9.2.1 Drill pipe safety valve Rule 48: One spare drill pipe safety valve with lifting device shall be permanently kept on the drill floor with cross-over adapted to string pipes in use.
9.2.2 Upper drill string float valve Also named Gray valve, this float valve does not allow further use of a DICV. Nevertheless one valve in good condition is recommended to be available on the rig floor. It could be used in the event of a DICV failure and if the stripping down is necessary.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 58 of 86
10. MUD GAS SEPARATOR (MGS) The MGS is designed to provide the effective separation of the mud and gas circulated from the well through the choke manifold during a kick, while drilling with significant drilled gas or when circulating trip gas. It is recommended to pay special attention to this equipment when selecting a rig, particularly for HP or HP/HT wells and in case of H2S. The design and specifications of such equipment should comply with the API 12 J. The contractor will supply operating performance and limitations of its MGS, the efficiency and performance of which are extremely dependent of their sizing and configuration. The MGS may be either vertical (the most popular is also called a ‘’poor boy degasser’’), cyclonic or horizontal (see Figure 12 in appendix 1). An insufficiently sized separator could lead to reduced killing rates or require the installation of an additional MGS in parallel. Rule 49: Each drilling or work over rig shall be provided with an atmospheric degasser. Minimum requirements are: 10 ft Mud seal height 8’’ nominal pipe for gas exhaust a siphon breaker not tied into the vent line A mechanical type de-gasser located on the mud pits will complete the final degassing of the mud.
10.1 MUD SEAL CONFIGURATION Whatever the design, the operating pressure within the separator is determined by the gas pressure loss through the vent line. The head of fluid (mud seal) will at least hold this pressure in order to prevent any gas blow through to the shaker room. The minimum height is 10 ft. For high-pressure wells it is highly recommended to request 20 ft.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 59 of 86
10.2 VENT LINE The gas vent line should not be less than: 8" nominal pipe diameter 10" nominal pipe diameter for HP wells (12" if possible) For pressure losses purpose, the line design will be as straight as possible with any bends as smooth as possible. The route of the vent line will prevent any liquid traps. Only rigid hard piping will be used. This line will be free of any flow control system and not connected to the gas line from vacuum de-gasser. Whenever possible, both on and offshore, the gas line will be routed up to crown block, even if H2S may be encountered. In most circumstances this achieves better gas dispersion (except in “no wind” conditions, which are rarely met at crown block level). Onshore, a horizontal line could be used. In such cases the line will be oriented downwind and gas exhaust will be located at least 15 m from any ignition source.
10.3 OTHER EQUIPMENT Overboard line: the facility to bypass the MGS from the choke manifold directly to the overboard line (down wind) will be available. Solids handling: The MGS will be able to handle a large quantity of solids (or weighting materials). The design will minimise the risks of plugging, settling and erosion. Pressure gauge: a 0-20 psi gauge will be installed on top of the MGS. It would be useful to have it readable from the choke control panel. Pressure rating: The MGS system should theoretically withstand at least the hydrostatic head of a heavy mud seal; but short peaks of pressure will also be considered. H2S requirements: Compatibility of the MGS with H2S will be verified. Anchoring the MGS: The MGS will be sufficiently anchored in place and adequately braced to prevent movement of both the separator and lines. The main function of the siphon breaker is to vent gas in the event of blow-down of the mud seal.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Page: 60 of 86
Date: 15/10/2003
10.4 DEEP WATER : RISER GAS EVACUATION In ultra-deep waters, large volumes of gas could reach the surface if a gas bubble enters the riser. The uncontrolled expansion of this bubble in addition to the restricted working pressure of surface equipment (telescopic joint first) leads to diversion of the riser fluids through large diverting lines. A mud de-gasser could be used, but sizing of the required equipment is not easy and the problem could remain.
Mud Gas Separator
A
A
6” return line Port Overboard
6” Ball Valve
VIEW A-A
Flow Selector Diverter
Flowline
12” Ball Valve
Starboard Overboard
Fig. xx - 6” Line from Diverter Overboard to Poorboy MGS
A simple mud saver at the exit of the diverting lines, less efficient but probably safer than a standard mud de-gasser for this application, could also be contemplated. In any event, this situation has to be considered as a critical one. The probability for mud spills is likely in such a situation and adequate means to contain and treat these spills should be available on the rig.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
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Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 61 of 86
11. WELL CONTROL EQUIPMENT INSPECTION / CERTIFICATION / MAINTENANCE
11.1 GENERAL Rule 50: A Well Control Equipment log book is mandatory on each rig and will be part of the site Safety Register It is the drilling and completion supervisor’s role to periodically verify that the Well Control Equipment log book is issued, available and up to date. The rig Well Control Equipment log book is constituted with: Certification package by the manufacturer or an approved third party with API monogram. API manufacturing documentation, NACE certification including raw material traceability. Manufacturers must provide full traceability of Well Control Equipment and spare parts. Commissioning Well Control Equipment inspection report and action plan inspection reports and following action plans after periodic inspections of Well Control Equipment any inspection reports after repair or change of equipment. repair / change log book. Dates, technical reason for change, part number and working limitations of installed components (pressure, temperature rating, OBM compatibility, etc) shall be recorded and approved by the rig manager. maintenance log book. This log book ensures that the manufacturer's BOP operating manual is followed and no alterations/modifications have been made to the BOP equipment without written consent from the manufacturer. Spare Parts: Only original equipment manufacturer’s spares will be used for Well Control Equipment replacement parts. In order to extend the life of the BOP seals and associated equipment (depending on the type of mud, temperature and gas environment), particular attention will be given to the choice of the sealing material. The manufacturer’s standards will be followed. Storage conditions will follow the manufacturer recommendations. It will be remembered that rubber can be damaged by temperature, UV radiation and ozone created by electrical motors.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 62 of 86
11.2 RIG ACCEPTANCE The required BOP inspection program will be clearly highlighted in the call for tender acceptance. Rig acceptance will include a review of the Well Control Equipment certification package and Well Control Equipment maintenance log book. Rule 51: A new certification is required if, at the rig acceptance stage, the BOP documents file (previous certificates, log book, etc) is missing or badly completed. A complete BOP stack dismantling and inspection shall be carried out for certification when control equipment has been stacked for a period equal to or greater than 6 months At the rig acceptance stage, periodic inspections will be checked At the rig acceptance stage, periodic inspections (refer to paragraph 11.3) will be checked. All ram cavities, the bag preventer and all gate valves will be opened and carefully checked. All seals and gaskets will be replaced with new ones. The packer could also be changed if deemed necessary. On stacks equipped with hydraulic rams locks, rams locks will to be stripped, checked and tested. It is recommended to change the packing system(s) of annular preventer(s) at the rig acceptance stage if it has been in use for more than one year. Coflexip type (or equivalent) hoses are recommended to be inspected internally The external condition of all BOP control flexible hoses will be checked.
11.3 PERIODIC INSPECTIONS Rule 52: A complete BOP stack dismantling and inspection shall be carried out for certification if: equipment is in continuous use for more than 5 years equipment was subject to abnormal conditions (excessive shock, fire, etc). A clean out and visual inspection of bag preventer packer, rams, ram cavities, tightness of flange and connectors and verification of pre-charge pressures in accumulators will be carried out prior to each well. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 63 of 86
An internal inspection of Coflexip type (or equivalent) hoses is recommended once a year. The external condition will be also checked. A calibration of all pressure gauges is recommended once every 3 years.
11.4 MODIFICATIONS, CHANGES Rule 53: A new certification is required in the case of repair inducing hot work All modifications, design changes or weld repairs to Well Control Equipment will comply with appropriate API specifications or manufacturer specifications or local government regulations whichever is more stringent.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 64 of 86
APPENDIX
Appendix 1: Drawings
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 65 of 86
SURFACE STACK MEWHP < or = 3 000 psi
AN
BR
KL
CL
MINIMUM CONFIGURATION / NON FLOWING WELLS
AN
BR or BSR (1)
PR
CL
KL
HAZARDOUS WELLS
AN
BR or BSR (1)
PR
KL
CL Fig. 1
(1) according to rule 16
VR INSTEAD of PR IF TAPERED STRING
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Date: 15/10/2003
Page: 66 of 86
SURFACE STACK MEWHP > 3 000 psi and < or = 5 000 psi
AN
BR
PR
KL
CL
MINIMUM CONFIGURATION
AN
BSR
KL
PR
PR
CL
KL
HAZARDOUS WELLS
Fig. 2
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 67 of 86
Date: 15/10/2003
SURFACE STACK MEWHP > 5 000 psi AND < or = 10 000 psi
AN
BSR
KL
PR
PR
CL
KL
MINIMUM CONFIGURATION WITH ONE SIZE DP STRING
AN
BSR
CL KL
PR 1
PR 2
VBR
Fig. 3 CL
KL SPECIFIC CASE (HIGH RISK WELL - TWO MAIN SIZES OF DP STRING) This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 68 of 86
Date: 15/10/2003
SURFACE STACK MEWHP > 10 000 psi
AN
BSR
CL KL
PR 1
PR 2
VBR
CL
KL
IF VBR COMPATIBLE WITH TEMPERATURE
Fig. 4
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 69 of 86
Date: 15/10/2003
SUBSEA BOP STACK MEWHP < or = 10 000 psi
AN
BSR CL KL
PR PR VBR
CL
KL
Fig. 5
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 70 of 86
Date: 15/10/2003
LARGE BORE SUBSEA BOP STACK MEWHP < or = 3 000 psi
KL / CL
AN
BSR KL
PR
Fig. 6
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 71 of 86
Date: 15/10/2003
SUBSEA STACK MEWHP > 10 000 psi
AN
AN
BSR CL KL
PR PR VBR
CL
KL
Fig. 7
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 72 of 86
Date: 15/10/2003
CHOKE MANIFOLD SCHEMATIC
3" To shakers
10000 psi Surface BOP Stack - Kill and choke manifolds Typical drawing
Remote control choke 3"
4" Manual choke
From Stand pipe
To burner port side
3"
3"
To atmospheric degasser
Manual choke 3"
AN NN AN
HP pump
3"
Bypass
4"
Overboard line
BSR 4" 2"
PR
To burner starboard
VBR
3"
CL
Fig. 8
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 73 of 86
Date: 15/10/2003
3" To shakers
10000 psi Surface BOP Stack - Kill and choke manifolds Typical drawing
Remote control choke 3"
4" Manual choke
From Stand pipe
To burner port side
3" To atmospheric 3" degasser Manual choke 3"
AN NN AN
HP pump
3"
Bypass
4"
Overboard line
BSR 4" 2"
PR1
To burner starboard
PR2 CL1
3"
VBR 3"
CL2
Fig. 9
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Page: 74 of 86
Date: 15/10/2003
10000 psi Subsea BOP Stack - Kill and choke manifolds Typical drawing
3" To shakers
Remote control choke 3"
4" Manual choke
From Stand pipe
To burner port side
3"
3"
To atmospheric degasser
Manual choke
HP pump
3" AN
3"
Bypass
3" AN
3"
4"
Overboard line
4"
To burner starboard
2 or 3"
BSR
PR
PR VBR
Fig.10
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
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CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Page: 75 of 86
Date: 15/10/2003
HYDRAULIC CONTROL UNIT SCHEMATIC
Basic Surface BOP Control System Accumulators Set 1
Accumulators Set 2
to another pump
Pump system 1 Regulator Valve
Regulator Valve
By Pass Valve
Pump system 2
By Pass Valve
to rams & valves
to annular preventer
Fig. 11
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 76 of 86
MUD GAS SEPARATOR SCHEMATIC
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CR_FPP_160_REV01_Well_control_equipment.doc
FigFig. 12 10
Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Date: 15/10/2003
Page: 77 of 86
Appendix 2 : Shear rams
Cutting efficiency upgrading (Ref. Cameron)
BOP Size
PIPE
RAM TYPE
SHEAR FORCE (lbs)
13” 5/8 - 10K
5”1/2 – 21.9# S135
DS
299200
13” 5/8 – 10K
6”5/8 – 25.2# S135
DS
326400
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 78 of 86
Appendix 3: Example of accumulator volume calculation
A) Surface BOP stack A1) Calculation of the required volume (VR) VR is the required volume by rule 33 depending on the configuration of the BOP stack. The example here below is for a 3 rams plus 1 annular preventer 13 5/8” WP 10000 psi CIW BOP stack plus 3 remote operated valves. The tables n° 1: ram preventers and n° 2: bag preventers attached at the end of this appendix 3 give the fluid requirements to operate the required functions. OPENING (Gal)
CLOSING (Gal)
TOTAL (Gal)
BAG 5M
10.34
12.12
22.46
2 PIPE RAMS 10M
5.4 x 2
5.8 x 2
22.40
1 BLIND SHEAR RAMS
10.5
10.9
21.40
3 VALVES
1x3
1x3
6
VR
Note:
72.26
The fluid requirement to operate one remote operated valve is assumed at one gallon.
A2) Calculation of the usable volume of an accumulator (VU). The usable volume (VU) is the fluid delivered by the accumulator from the maximum operating pressure (P max) up to the minimum operating pressure (P min) of the accumulator. VU is the volume difference occupied by the gas (generally nitrogen) from P min to P max. VU = V pmin - V pmax P max is given by the manufacturer. The pre-charge pressure (P pc) is given by the manufacturer. P min is equal to the P pc + 200 psi.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 79 of 86
If V (in gallon) is the volume of one accumulator bottle, the maximum volume of the gas of one bottle is equal to V-1 as one gallon is kept for bladder displacement. This volume is V ppc.
By application of the Marriott law PV= cte, P max * V pmax = P min * V pmin = P pc * V ppc è V pmin = (P pc * V ppc) / P min = (P pc * V ppc) / (P pc + 200 psi) è V pmax = P pc * V ppc / p max VU = (P pc * V ppc) / (P pc + 200 psi) - P pc * V ppc / p max Example: if the volume of one bottle is 11 gal, if the pre-charge pressure is 1 000 psi and if the maximum working pressure is 3 000 psi, then
V ppc = 11 – 1 P pc P max VU = 1 000*10/1 200 – 1 000*10/3 000 = 8.33 – 3.33
= 10 gal = 1 000 psi = 3 000 psi, = 5 gal.
That means that, with our assumptions, the usable volume of one bottle of 11 gal is only 5 gal. A3) Calculation of the number of accumulator bottles required. The useable fluid volume available in the accumulators must be as per rule 33 equal to required volume VR. The number of accumulator bottles required is determined by dividing the required volume VR by the useable volume VU of one accumulator bottle. With the assumptions of the here above example, we need 72.26 / 5 = 15 bottles to operate the BOP described in A1. That means that V ppc of the total accumulator is 15 * 10 = 150 gal A4) Verification of shearing capacity. To comply with rule 33, we have to check that after using the volume (V shr) needed to realise the determined shearing sequence from the maximum operating pressure (P max) up to the remaining pressure (P rem), this remaining pressure is above the manufacturer’s recommended pressure, the pumping systems being off. V shr = V prem - V pmax By application of the Marriot law PV= cste, This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 80 of 86
P max * V pmax = P rem * V prem è P rem = ( P max * V pmax ) / V prem with
V pmax = P pc * V ppc / P max P rem = (P pc * V ppc) / ( V shr + V pmax )
With the assumptions of the here above example and with the BOP described in A1:
V shr = 5.8 (VR for the set of PR) + 10.9 (VR for the shear) V p max = 1 000 *150 / 3 000 P rem = (1 000* 150 ) / ( 16.7 + 50 )
= 16.7 gal = 50 gal = 2 249 psi
As P rem is above the manufacturer’s recommended pressure at the end of the shearing process (usually around 2000 psi), the size of this accumulator is correct. However the manufacturer’s recommended pressure at the end of the shearing process could be more than 2 000 psi for specific cases (5 ½” drill pipes or no large bore shear bonnets and/or no tandem boosters installed).
B) Subsea BOP stack B1) Calculation of the required volume VR. VR is the required volume by rule 34 depending on the configuration of the BOP stack. The example here below is for a 3 pipe rams plus 1 shear pipe rams plus 1 annular preventer 18 3/4” WP 10 000 psi CIW type U BOP stack plus 8 remote operated valves. The tables n° 1: ram preventers and n° 2: bag preventers attached to this appendix 3 give the fluid requirements to operate the required functions
BAG 10M 3 PIPE RAMS 10M 1 BLIND SHEAR RAMS 8 VALVES TOTAL Functions VR = 1.5 Total Functions
OPENING (Gal)
CLOSING (Gal)
45.1 21.2 x 3 21.2 1x8
51.0 23.1 x 3 23.1 1x8
TOTAL (Gal) 96.1 132.9 44.3 16 289.3 434
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Note:
Rev: 01
Date: 15/10/2003
Page: 81 of 86
The fluid requirement to operate one remote operated valve is assumed at one gallon.
B2) Calculation of the usable volume of an accumulator VU. For the part of the surface accumulator bottles, the calculation of VU of this surface part (VU surf) is done as described in A2. The calculation of the usable volume of the subsea part of accumulator (VU ss) is different as the pre-charge and the maximum operating pressure of the subsea accumulator bottles should be increased to compensate for: the hydrostatic head of the sea water column the compressibility and temperature effect on the pre-charge gas behaviour should also be taken into consideration when calculating the usable volume of the subsea accumulators. a) the hydrostatic head of the sea water column The following technique can be used to size accumulator bottles for subsea operation, assuming a ML water depth. The hydrostatic pressure at ML (P ml) is 1.03*0.981*ML (m)/10 in bars or 14.5xP ml in psi. The pre-charge pressure (P pcss) has to be increased to compensate for the hydrostatic head of the sea water column. Therefore, P pcss for subsea accumulator is the P pc at surface conditions (given by manufacturer) plus the hydrostatic pressure P ml. P pcss = P pc + P ml P minss = P pcss + 200 psi = P pc + P ml + 200 psi For the maximum operating pressure at bottom conditions ( Pmaxss ) same correction has to be made: P maxss = P max + P ml b) the compressibility and temperature effect on the gas behaviour The compressibility factor Z of a gas is a function of the temperature and the pressure. This compressibility factor Z is used in the gas law: P * V / T *Z = constant (T in ° Kelvin)
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CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 82 of 86
With: T surf = surface temperature in ° C plus 273. T bot = sea bottom temperature in ° C plus 273 Z pc = the compressibility factor of the gas in the accumulator bottle at surface temperature T surf and at a pressure of P pcss. Z pmin = the compressibility factor of the gas in the accumulator bottle at sea bottom temperature T bot and at a pressure of P minss. Z pmax = the compressibility factor of the gas in the accumulator bottle at sea bottom temperature T bot and at a pressure of P maxss. Nitrogen compressibility factor 1,5
Z compressibility factor
1,4 1,3 Z at 4°C
1,2
Z at 30°C
1,1 1 0,9 2000
4000
6000
8000
10000
12000
Pressure in psi
COMPRESSIBILITY FACTOR OF NITROGEN (From Sage&Lacy API project N°37) figure n° 1 The usable volume of a subsea accumulator (VU ss) is the fluid delivered by the accumulator from the maximum operating pressure (P maxss) up to the minimum operating pressure (P minss) of the accumulator. VU ss is the volume difference occupied by the gas (generally nitrogen) from P minss to P maxss. VU ss= V pminss - V pmaxss
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CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 83 of 86
By application of the above gas law: P pcss * V ppc / T surf * Z pc = P maxss * V pmax / T bot * Z pmax P pcss * V ppc / T surf * Z pc = P minss * V pmin / T bot * Z pmin è V pmin = [P pcss * V ppc] * [T bot * Z pmin] / [T surf *Z pc] / [P pc + P ml + 200 psi] è V pmax = [P pcss * V ppc] * [T bot * Z pmax] / [T surf * Z pc] / [P maxss] VU ss =
[(P pcss * V ppc * T bot) / (T surf * Z pc)] * [Z pmin / P minss – Z max / P maxss]
If V (in gallon) is the volume of one accumulator bottle, the maximum volume of the gas of one bottle is equal to V-1 as one gallon is kept for bladder displacement. This volume is V ppc. if the pre-charge pressure is 1 000 psi and if the maximum working pressure is 3 000 psi, then Example: In a 1000 m water depth for a standard nitrogen accumulator bottle with a maximum working pressure of 3 000 psi and a pre-charge pressure of 1 000 psi, then:
P ml = 14.5 ( 1.03 *0. 981*1000 / 10 )= P pcss = 1 000 psi + 1 500 psi = P minss = 2 500 psi + 200 psi = P maxss = 3 000 psi + 1 500 psi = T surf = 273 + 30 = T bot = 273 + 4 =
1 500 psi 2 500 psi 2 700 psi 4 500 psi 303 °K 277 °K
From the figure n° 1:
Z pc (for a P pcss of 2500 psi and a T surf estimated at 30°C) = 1.01 Z pmin (for a P minss of 2700 psi and a T bot of 4°C) = 0.99 Z pmax (for a P maxss of 4500 psi and a T bot of 4°C) = 1.04 VU ss = [(2500 * 10 * 277) / (303 * 1.01)] * [0.99 / 2700 – 1.04 / 4500] = 3.067 gal
That means that, with our assumptions, the usable volume of one subsea bottle of 11 gal is only 3.067 gal at bottom conditions. B3) Calculation of the number of accumulator bottles required. The useable fluid volume available in the accumulators must be, as per rule 34, equal to VR and VU surf + VU ss must be equal to VR The number of accumulator bottles required is determined by dividing the required volume VR by the useable volume VU of one accumulator bottle depending the location (surface or subsea) of the bottle. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 84 of 86
Example: With the assumptions of the here above subsea example, we need 434 gal of bottle capacity. If the number of bottles at the surface accumulator is 60, the surface usable volume is equal to 60 * 5 = 300 gal. The usable volume required to the subsea accumulator is equal to 434 – 300 = 134 gal. Consequently the number of bottles of the subsea accumulator must be 134 / 3.067 = 43,7 or 44.
B4) Verification of shearing capacity. In the case the accumulator is split with a surface part and a subsea part, the verification is quite more complicate compare to A4. Firstly, the verification has to be conducted with the only surface part (generally the biggest one) and if the remaining pressure, in this case, is above the manufacterer’s recommended pressure then it is obvious that it remains valid with surface + subsea part. If not iterations have to be done to take into account the subsea part. Example: In the here above case
V ppc for the surface part is 60 * 10 P pc V shr = 5.8 + 10.9 V pmax = 1 000 * 600 / 3 000 P rem = (1 000 * 600) / (16.7 + 200)
= = = = =
600 gal 1 000 psi 16.7 gal 200 gal 2 769 psi
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_160_REV01_Well_control_equipment.doc
Company Rule
CR FPP 160 Well control equipment
Exploration & Production
Rev: 01
Page: 85 of 86
Date: 15/10/2003
TABLE N°1: RAM PREVENTERS GALLONS OF FLUIDS REQUIRED TO OPERATE ONE SET Cameron NL Shaffer Size and Working Pressure U QRC LWS SL E Inches psi Close Open Close Open Close Open Close Open Close Open 4 1/16 10 000 0,59 0,52 6 3 000 1,22 1,17 0,81 0,95 2,75 2,30 6 5 000 1,22 1,17 0,81 0,95 1,19 0,99 2,75 2,30 7 1/16 10 000 1,22 1,17 6,35 5,89 7 1/16 15 000 1,22 1,17 6,35 5,89 8 3 000 2,36 2,70 2,58 2,27 2,75 2,30 8 5 000 2,36 2,70 2,58 2,27 2,75 2,30 10 3 000 3,31 3,16 2,77 3,18 1,74 1,45 3,25 2,70 10 5 000 3,31 3,16 2,77 3,18 2,98 2,62 3,25 2,70 10 5 000 4,23 (S) 4,03 (S) 11 10 000 3,31 3,16 11 10 000 4,23 (S) 4,03 (S) 8,23 7,00 9,45 7,00 11 15 000 5,54 5,42 9,40 8,10 12 3 000 5,54 5,20 4,42 5,10 5,50 4,50 3,55 2,90 13 5/8 3 000 5,44 4,46 13 5/8 3 000 13 5/8 5 000 5,54 5,42 5,44 4,46 3,55 2,90 13 5/8 5 000 10,9 (S) 10,5 (S) 11 (S) 10,52 (S) 13 5/8 10 000 5,54 5,42 9,45 7,00 13 5/8 10 000 10,9 (S) 10,5 (S) 13 5/8 15 000 16,2(S) 16,0(S) 11,56 10,52 16 3/4 3 000 10,16 9,45 16 3/4 5 000 10,16 9,45 6,07 4,97 16 3/4 5 000 12,03 (S) 11,19 (S) 11,76 10,67 16 3/4 10 000 19,0 (S) 18,1 (S) 14,47 12,50 18 3/4 5 000 23,1 21,2 14,55 13,21 18 3/4 10 000 24,88 23,00 18 3/4 15 000 14,62 13,33 20 2 000 8,11 7,61 7,80 6,68 20 3 000 8,11 7,61 7,80 6,68 20 3 000 9,35(S) 8,77(S) 16,88(S) 15,35(S) 21 1/4 2 000 8,11 7,61 21 1/4 2 000 9,35(S) 8,77(S) 21 1/4 5 000 20,41 17,78 21 1/4 5 000 23,19(S) 20,20 (S) 21 1/4 10 000 26,54 21,14 14,42 12,65 21 1/4 10 000 30,15(S) 27,42 (S) 16,05(S) 13,86(S)
Hydril Manual (a) Auto (a) Close Open Close Open
1,90 3,70
1,80 3,40
5,20
5,20
5,40 11,5 (S) 5,40 11,5 (S) 11,80 11,8 (S)
4,90 11,2 (S) 4,90 11,2 (S) 11,80 11,8 (S)
5,90 12 (S) 5,90 12 (S) 12,90 12,9 (S)
4,90 11,2 (S) 4,90 11,2 (S) 11,80 11,8 (S)
15,80
14,10
17,10
15,60
Company Rule
CR FPP 160 Well control equipment
Rev: 01
Exploration & Production
Page: 86 of 86
Date: 15/10/2003
TABLE N°2: ANNULAR PREVENTERS GALLONS OF FLUIDS REQUIRED TO OPERATE AN OPEN HOLE Size and Working Pressure Inches psi 6 3 000 6 5 000 7 1/16 10 000 8 3 000 8 5 000 10 3 000 10 5 000 11 5 000 11 10 000 12 3 000 13 5/8 5 000 13 5/8 1 000 16 2 000 16 3 000 16 3/4 5 000 18 2 000 18 3/4 5 000 18 3/4 10 000 20 2 000 20 3 000 21 1/4 2 000 21 1/4 5 000
Hydril GK Close Open 2,9 2,2 3,9 3,3 9,4 4,4 3,0 6,8 5,8 7,5 5,6 9,8 8,0 25,1 11,4 18,0 34,5 17,5 21,0 28,7 21,1
9,8 14,2 24,3 12,6 14,8 19,9 14,4
Close
GL Open
Balacing
NL Shaffer Spherical Close Open
CIW "D" Close
Open
18,6
14,6
5,7
4,7
19,8
19,8
8,2
23,6 47,2
17,4 37,6
12,1 18,1
10,3 16,2
33,8
33,8
17,3
33,0
25,6
22,3
19,0
44,0
44,0
20,0
48,2
37,6
35,6 51,0
29,0 45,1
32,6
17,0 40,5 40,5
28,4 28,4
58,0
58,0
29,5
32,6 61,4
16,9 47,8
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