DRILLING AND WORKOVER WELL CONTROL MANUAL
VOLUME I
5
th
EDITION, June, 2014
CHAPTER A
EQUIPMENT REQUIREMENTS
CHAPTER B
BOP SYSTEMS
CHAPTER C
MAINTENANCE, TESTING AND RECERTIFICATION
CHAPTER D
WELL CONTROLLED POLICIES
CHAPTER E
WELL CONTROL DRILLS
1.0 INTRODUCTION
The 5th edition of the Well Control Manual has some significant changes from the 4th Edition. It is the responsibility of the authorized users of this manual to familiarize themselves with the specifications and instructions in its entirety.
2.0 REVISIONS
The Well Control Manual (WCM) will undergo a full review and revision every three (3) years. The WCM will be reviewed by the Well Control Committee (WCC), endorsed by the General Manager of Drilling and approved by the Vice President of Drilling and Workover.
Document Control:
The Well Control Manual (WCM) is subject to constant review, revision and updates by the Well Control Committee (WCC). The timely implementation of the policies contained in this document is critical and steps must be taken to ensure that the latest revision including published errata and amendments is available to Drilling and Workover Rigs and Management.
Revisions and Updates will be controlled as follows:
1 The WCM will be fully reviewed and reissued after three (3) years.
2 Interim revisions and updates will be issued as errata or amendments as required.
3 A revision log will be maintained at the beginning of the WCM that will list and summarize any changes
To ensure that the document is available to all concerned parties there will be two (2) versions of the manual available, Electronic and Printed.
Electronic Version:
The Electronic version will reside on the Drilling Information Highway. This document is available for viewing by all authorized DIH users. If a page or section is printed from DIH, it is considered uncontrolled as of the print date.
Printed Version:
Printed copies will be issued as follows: • V.P. D&WO
• General Manager, Drilling • All D&WO Managers
• All Drilling and Workover Rig Superintendents • All Members of the Well Control Committee.
• All rigs operating under Drilling and Workover will have one copy in the Foreman’s Office. • Each Drilling or Workover Rig Contractor’s local head office.
• D&WO Contracts Administration Division
Updates and Revisions to printed copies will be controlled as follows:
1.
When errata or an amendment is issued a notification will be sent to all D&WO personnel. The master electronic copy on the DIH will have the errata and amendments placed at the beginning of the file.CHAPTER A: EQUIPMENT SPECIFICATIONS AND REQUIREMENTS
TABLE OF CONTENTS
1.0
PRIMARY WELL CONTROL EQUIPMENT REQUIREMENTS
1.1 General Requirements A-3
1.2 Annular Units and Diverters A-5
1.3 Fixed Ram Preventers and Elastomers A-5
1.4 Variable Bore Ram Preventer Blocks and Elastomers A-6
1.5 Shear Blind Ram (SBR) Blocks and Elastomers A-6
1.6 Valve Removal Plugs and Blind Flanges on BOP Side Outlets A-8
1.7 Drilling Spools A-8
2.0
REQUIREMENTS FOR KILL, EMERGENCY KILL, CHOKE LINES AND CHOKES
2.1 Minimum Bore Size for Lines: A-9
2.2 Material and Fabrication A-9
2.3 Requirements for Drilling Chokes A-11
2.4 Requirements for Valves A-11
2.5 Requirements for Cup Testers A-12
3.0
ACCESSORY BOP EQUIPMENT REQUIREMENTS
3.1 Pit Volume Totalizers A-12
3.2 Mud Flow Indicators A-12
3.3 Gas Busters A-12
3.4 Full Opening Safety Valves A-17
3.5 Inside BOP A-17
3.6 Trip Tank A-18
3.7 Bowl Protectors (Wear Bushings) A-19
3.8 Valve Removal Plugs A-19
3.10 Weco Connections A-19
3.11 Chiksans A-19
3.12 Accumulator Closing Units A-20
3.13 Stroke Counters A-22
3.14 Gas Detectors A-22
3.15 Drill Rate Recorders A-22
1.0 WELL CONTROL EQUIPMENT SPECIFICATIONS AND
REQUIREMENTS
This Chapter of the Well Control Manual sets forth the specifications and requirements for Blow Out Prevention Equipment (BOPE) and systems for use in Drilling and Workover Operations. Variations or deviations of BOPE, specifications, arrangement, pressure rating or requirements from this standard requires endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling or Workover Rig Superintendent. The Rig Foreman shall ensure that the proper equipment is available and correctly installed. If not specified in these standards all BOP equipment shall comply with API Specifications and Recommended Practices.
1.1 General Requirements:
All Drilling and Workover Well Control Equipment shall meet the following requirements:
1.1.1 All BOPE (Annulars, Ram Type, Valves, Chokes, Crosses Flexible Lines, Hard Lines and etc.) shall be of forged material, Monogrammed to API Specification 6A, 16A, 16C, 17D or other applicable API Specification as appropriate.
1) All equipment in service in Saudi Aramco D&WO Operations must be API Monogrammed. This includes equipment transferred from other regions whether or not it is on a rig already. Monogram and markings MUST be clearly visible through the painted coating of the equipment. Care should be taken to preserve this monogram on the equipment nameplate, flange or body to prevent it being obliterated or destroyed during handling maintenance and use. Additionally, documentation must be available at the rig site reflecting the equipment Serial Number and API Monogram Status.
2) Any exceptions to this monogram policy (e.g.; 30" 1,000 psi annulars) are noted in the section detailing that specific equipment.
1.1.2 All major BOPE components including, but not limited to, ram BOPs, annular BOPs, drilling spools, ram blocks, valves, choke and kill lines, choke manifolds, gas busters etc. will have an unique serial or asset identification number assigned at time of manufacture by the ORIGINAL EQUIPMENT MANUFACTURER (OEM). The number must be permanently marked in the metal of the component body and should be paint stenciled in a prominent and visible location on the equipment. This number must be referenced on all accompanying certification and recertification documents. Repair numbers are not acceptable for this requirement.
1.1.3 Only OEM parts are acceptable when repairing or redressing the BOP, valves, chokes, and closing units. Documentation (e.g.; PO, invoice, certificate of compliance etc.) must be maintained for all parts verifying that they are OEM.
1.1.4 Maintenance and testing requirements may be found in Chapter C "Maintenance Testing and Certification Requirements” of this manual.
1.1.5 A drilling spool is preferred for primary choke and kill line installation. However in special cases, such as space limitation, preventer side outlets may be used in lieu of a drilling spool. The diameter of all preventer side outlets must be at least as large as the choke manifold lines. NOTE: Side outlets are used for installation of the lower choke and kill lines on 10K/15K BOPs.
1.1.6 The through-bore size of the preventer stack, tubing head, and any adapters used in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner hanger, packer, plug, cup tester, bowl protector or any other large diameter down-hole tools to be run in the well.
1.1.7 The pressure rating of all pressure control equipment (BOP, Valves, Lines etc.) must be greater than the MASP (Maximum Anticipated Surface Pressure).
1.1.8 The inboard manual valves on the choke and kill lines are considered master valves and normally would not, except for pressure testing, be closed unless the outside valve (HCR) has failed.
1.1.9 Check valves must be installed on normal kill lines but shall not be used on emergency kill lines.
1.1.10 The kill line, emergency kill line and choke lines should be flushed and washed out frequently to prevent mud solids settling.
1.1.11 BOP assemblies will be dismantled between wells to inspect for internal corrosion, erosion and to check flange bolts. Refer to Chapter C for maintenance procedures and requirements.
1.1.12 All Rigs shall maintain a logbook of BOP schematics detailing the components installed. The logbooks shall contain the part number, size, description, serial number (if applicable) and installation date of ram blocks, top seals, ram and annular packers and bonnet or door seals. This is be witnessed and co-signed by the Toolpusher and the Saudi Aramco Representative (see form #1 in Chapter C) of this manual).
1.1.13 All ram preventers must be equipped with manual or automatic locking devices, which must be locked whenever the rams are used to control the well. Hand crank, wrench or hand wheel systems are acceptable manual locking devices.
1.1.14 All preventers and associated equipment must meet NACE MR-0175/ISO 15156, API Specification 6A, 16A or 16C for sour service.
1.1.15 A full OEM certification or recertification of the BOP, choke manifold (including chokes) and all related equipment must be performed at the start of the contract and least once every three years thereafter. The recertification must be in accordance with the relevant API Specification for repair/remanufacture. The documentation package shall be kept with the equipment and must be available for inspection at the rig site by Saudi Aramco personnel. This includes, but is not limited to:
Ram preventers. Annular preventers.
Valves on the kill, emergency kill, choke line and choke manifold. Drilling chokes.
Kill, emergency kill and choke lines (and line components) including both hard line and flexible hoses.
Drilling spools.
NOTE: Recertification can only be performed by the OEM or their licensee facility. If recertified by a licensee, the document package shall include a copy of the license issued by the OEM. In-field recertification is not acceptable.
NOTE: New equipment shall be accompanied by the manufacturer's certificate of compliance and a full documentation package including inspection and test reports.
1.1.16 All BOPE including, but not limited to, annulars, ram type, valves, spools, crosses, tees and other end and outlet connections with working pressures of 3,000 psi and above shall have flanged, welded, integral, or hubbed connections only. Threaded connections and threaded connections that have been seal welded are not permitted.
1.1.17 All Ram Type BOP cavities MUST CONTAIN a Ram. Vacant Ram cavities during operations are not permitted.
1.2 Annular Units and Diverters:
1.2.1 All annular units must comply with the following in addition to the requirements in Section 1.1.
1.2.2 The minimum acceptable ratings for H2S and temperature are as follows,
2,000 psi and less 2.5% H2S and 0-170°F 3,000 psi equipment 2.5% H2S and 0-180°F 5,000 psi equipment 2.5% H2S and 0-180°F 10,000 psi equipment 2.5% H2S and 0-180°F
1.2.3 The acceptable annular manufacturers are Cameron, GE-Hydril and NOV-Shaffer.
1.2.4 GE Vetco KFDJ and Dril-Quip MD diverters are acceptable for offshore 500, 1,000 and 2,000 psi service. Dril-Quip, is currently the only approved design, for the 500 psi onshore diverter.
NOTE: The Dril-Quip onshore diverter is not eligible for API Monogram and is not subject to the 3-year recertification requirement. Only repair after each nipple-up is required.
1.2.5 If a rotary diverter system is utilized on an offshore rig, the diverter lines must have the capability of discharging below the bottom of the hull due to H2S concerns.
1.2.6 Bolted, latched and screwed top annulars are acceptable.
1.2.7 30 inch 1,000 psi annulars may not be monogrammed under API specification 16A. These annulars are exempt from the monogram requirement.
1.3 Fixed Ram Preventer Blocks and Elastomers:
1.3.1 All fixed ram preventers must comply with the following in addition to the requirements in Section 1.1 above.
1.3.2 Only fixed size rams are acceptable as the master pipe ram (bottom ram) on all BOP stacks.
1.3.3 The minimum acceptable ratings for H2S and temperature for ram assemblies are:
3,000 psi stack 5.0% H2S and 0-250°F 5,000 psi stack 10.0% H S and 0-250°F
10,000 psi stack 20.0% H2S and 0-300°F 15,000 psi stack 20.0% H2S and 0-300°F
1.3.4 Cameron, NOV-Shaffer and GE-Hydril are acceptable manufacturers for ram preventers. All ram assemblies shall meet NACE Standard MR-01-75-2000 for sour service.
NOTE: Fixed size ram preventers CANNOT CLOSE on TOOL JOINTS
1.3.5 All ram preventers shall be equipped with manual or automatic locking devices which must be locked whenever the rams are closed to control the well. A hand crank/wrench or handwheel system are acceptable manual devices. Automatic devices (e.g.: Shaffer Posilocks) are also acceptable.
1.4 Variable Bore Ram Preventer Blocks and Elastomers:
1.4.1 All variable bore ram preventers must comply with the following in addition to the requirements in Section 1.1 above.
1.4.2 Variable bore rams (VBR) are optional for tapered drill string applications on Class ‘A’ stacks. In all cases the master pipe ram (bottom ram) must be a fixed ram.
1.4.3 The minimum acceptable ratings for H2S and temperature for VBR's are:
3,000 psi stack 5.0% H2S and 0-250°F 5,000 psi stack 10.0% H2S and 0-250°F
1.4.4 The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) for the Cameron 13-5/8” U Type blowout prevented is acceptable for 3,000 and 5,000 psi applications ONLY. This VBR was successfully tested to 250 oF with a CAMLAST elastomer rated for 20% H2S.
NOTE: The Cameron ER-HT VBR-II, described above, is approved for use in 3M and 5M Class 'A' BOPs. This is the ONLY APPROVED VBR.
1.5 Shear Blind Ram (SBR) Blocks and Elastomers: 1.5.1 SBR's are required on:
Close Proximity Wells (All Wells in Populated Areas) Gas Cap Wells (Either 3,000 or 5,000 Class ‘A’ Stacks)
Onshore Class ‘A’ 5,000 psi stacks (Expl./Dev. Wells >10 % H2S)
Smart Well Completions and Downhole monitoring systems where more than one (1) line is run on the OD of the tubing.
ESP Completions in areas where the well can flow naturally Offshore Class ‘A’ 5,000 psi stacks (Offshore Wells)
Class ‘A’ 10,000 psi stacks (Deep Gas Exploration and Development Wells) Class 'A' 15,000 psi stacks (Deep Gas Exploration and Development Wells)
1.5.2 The minimum acceptable ratings for H2S and temperature for SBR's are: 3,000 psi stack 5.0% H2S and 0-250°F
5,000 psi stack 10.0% H2S and 0-250°F 10,000 psi stack 20.0% H2S and 0-300°F 15,000 psi stack 20.0% H2S and 0-300°F
1.5.3 Approved Shear Blind Rams are as follows: Cameron Shearing Blind Rams
Shaffer V-Shear, T-72 and LFS (Low Force Shear) Rams Hydril Blind/Shear Rams
1.5.4 All rigs utilizing SBR in 3,000 and 5,000 psi BOP equipment shall have a 3” emergency kill line. This will provide additional kill line capacity in case the SBR does not make a proper seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard manual valve shall be 2” with DSA back to 3”. Rigs with 10,000 psi and higher BOP equipment shall have dual choke and kill lines as specified in Chapter B.
1.5.5 Shear Blind Rams are normally installed in Class A BOP stacks. When installed they will be in the position immediately above the drilling cross as detailed in the individual stack configurations shown in this manual. They may be used on Class B BOP stacks on close proximity wells to allow the utilization of smaller rigs. When installed in Class B stacks, the configuration must be a fixed pipe ram in the bottom position, a drilling cross above that, the SBR and then the annular.
NOTE: Double rams may not be used in conjunction with SBR’s on a Class B stack.
NOTE: SBR’s are only to be used during testing and a well control incident. They shall not be used to close the well when out of the hole. A steel hole cover (minimum ¼” thick with locating pins) should be available on the rig floor to cover the rotary when pipe is out of the hole.
1.5.6 The tables below indicate the shear capability of SBR for different BOP manufacturers, sizes and pressure applications.
NOTE: Shear Blind Rams CANNOT BE CLOSED ON TOOL JOINTS. SHEAR BLIND RAM CAPABILITY
10,000 - 15,000 PSI SERVICE BOP SERVICE BOPE SIZE - WP CLASS MFG. DRILL PIPE SHEAR CAPABILITY REQUIRED SHEAR BLIND RAM TYPE OPERATOR REQUIRED SIZE SIDE PACKER TEMP (0F) H2S, (%) DEEP GAS EXPL/ DEV. 13-5/8" 10M CLASS 'A' CAMERON (1) ALL SIZES TO 5-1/2" 24.7# G-105 'SBR' YES/ LBT (2) 0-300 20
SHAFFER (1) ALL SIZES TO
5-1/2" 24.7# G-105 'V' 14"/10" (3) 0-300 20 11" 10M CLASS 'A' CAMERON (1) ALL SIZES TO 5" 19.5# G-105 'SBR' YES/ LBT (2) 0-300 20
SHAFFER (1) ALL SIZES TO 5" 25.6# G-105
NOTE: (1) CAMERON,HYDRILANDSHAFFERAREAPPROVEDMANUFACTURERS.
(2) CAMERON-LBTREFERSTOLARGEBORESHEARBONNETSWITHTANDEMBOOSTERS. (3) NOVSHAFFER-14"OPERATORWITH10"BOOSTERISREQUIRED.
3,000 - 5,000 PSI SERVICE BOP SERVICE BOPE SIZE - WP CLASS MFG. DRILL PIPE SHEAR CAPABILITY REQUIRED SHEAR BLIND RAM TYPE OPERATOR REQUIRED SIZE SIDE PACKER TEM P (0F) TE MP (0F) OFFSHORE ONSHORE EXPL/DEV. w/ H2S > 10%
GAS CAP WELL POPULATED
AREAS
13-5/8" 3-5M CLASS 'A'
CAMERON (1) ALL SIZES TO
5-1/2" 24.7# G-105
'SBR' YES/ LBT (2) 0-250 20
DUAL TUBING STRINGS SHAFFER (1) ALL SIZES TO
5-1/2" 24.7# G-105 'V' 14"/10" (3) 0-250 20 11" 3-5M CLASS 'A'
CAMERON (1) ALL SIZES TO 5" 19.5# G-105
'SBR' YES/ LBT (2) 0-250 20
SHAFFER (1) ALL SIZES TO
5" 25.6# G-105
'T-72' 14"/10" (3) 0-250 20
NOTE: (1) CAMERON,HYDRILANDSHAFFERAREAPPROVEDMANUFACTURERS.
(2) CAMERON-LBTREFERSTOLARGEBORESHEARBONNETSWITHTANDEMBOOSTERS. (3) SHAFFER-14"OPERATORWITH10"BOOSTERISREQUIRED.
1.6 Side Outlets, Valve Removal Plugs and Blind Flanges
1.6.1 Two side outlets are required below each ram on a BOP. Therefore, a single ram body will have two (2) outlets and a double ram body will have four (4).
1.6.2 Valve Removal (VR) plugs are not required on BOP side outlets, however they may be used. The following conditions apply to the blind flanges installed on side outlets:
Flanges installed on the side outlets of ram preventers that do not have VR plugs installed shall be blind with no penetrations.
Flanges installed on the side outlets of ram preventers that have VR plugs installed shall have a ½ inch NPT or an Autoclave tap (depending on the pressure rating) and have a plug installed.
1.7 Drilling Spools:
1.7.1 All Drilling Spools shall comply with the following requirements:
Monogrammed to API Specification 6A or 16A PSL-2 (5,000 psi working pressure or lower)
PSL-2 with PSL-3 Gas Test (10,000 psi working pressure or higher) PR-1 (or better)
MR-DD (or better)
TR-U (5,000 psi working pressure or lower) TR-X Suitable for 350 o
F service (10,000 psi working pressure or higher) Forged bodies
2.0 REQUIREMENTS FOR KILL, EMERGENCY KILL, CHOKE LINES AND
CHOKES
All Kill, Emergency Kill and Choke lines shall comply with the following in addition to Section 1.1.
2.1 The Minimum Bore Size for Kill, Emergency Kill and Choke Lines Shall Be As Follows:
KILL LINE
Nominal Size/Bore (in) Working Pressure (psi)
2-1/16" 3,000 and 5,000
2-1/16" 10,000
3-1/16" 15,000
EMERGENCY KILL LINE
Nominal Size/Bore (in) Working Pressure (psi)
2-1/16" 3,000 and 5,000 3-1/8" (with SBR) 3,000 3-1/8" (with SBR) 5,000 2-1/16" 10,000 3-1/16" 15,000 CHOKE LINE
Nominal Size/Bore (in) Working Pressure (psi)
3-1/8" 3,000
3-1/8" 5,000
4-1/16" 10,000 and 15,000
2.1.2 The complete piping system, valves, chokes and choke manifold will be the full working pressure of the BOP through the block valves downstream of the chokes and the Choke Manifold Buffer Chamber.
2.2 Material and Fabrication:
2.2.1 The lines from the BOP stack to the choke manifold shall have the same working pressure (or greater) as the BOP stack. All lines shall meet Sour Service requirements for API Specifications 6A and 16C.
2.2.2 Choke lines for 3M and 5M applications shall be either steel pipe, flexible hose or a combination of these.
2.2.3 Choke lines for 10M and higher applications shall be either steel pipe or a combination of hard line and flexible hose.
2.2.4 Flexible steel hose if used in combination flanged hard line may be used for the choke, kill and emergency kill lines on 3M through 15M applications provided the following requirements are satisfied:
All components of the hose and end fittings in possible contact with wellbore fluids meet Sour Service NACE MR-01-75/ISO 15156 (latest revision)
2.2.5 All lines and end connections shall be pressure tested and Monogrammed as per API specification 6A, 16C or 17D as appropriate.
2.2.6 Steel line material shall meet the requirements of API specification 6A or 16C for H2S service.
2.2.7 Flexible choke and kill lines shall be monogrammed to API Specification 16C. The only approved flexible choke and kill lines are:
Technip/Coflexip (coflon lined)
Continental Contetich-Thermo plastic lined (only allowed in 5,000 psi and lower service) Phoenix HNBR (only allowed in 5,000 psi and lower service)
NOTE: The Phoenix HNBR hose has the following limitations in chemical compatibility: Product compatibility of HNBR lined Phoenix Rubber hoses
(choke and kill hoses acc. to API Spec. 16C 07 C draft &hoses c\w st. st. internal carcass acc. to API Spec. 17K) 0oF 75oF 150oF 200oF 250oF Medium Concentration -18oC 24oC 66oC 93oC 121oC Hydrochloric acid HCl 15% + + - - - Hydrofluoric acid HF 0.6% + + - - - Xylene C6H4 (CH3)2 25% + + + L L Methanol CH3OH 100% + + L L L
Zinc bromide ZnBr2 Saturated + + L L L
Calcium bromide CaBr2 Saturated + + L L L
Calcium chloride CaCl2 Saturated + + L L L
Diesel 100% + + + + -
Sea water --- + + + - -
Sodium hydroxide NaOH 50% L L - - -
Hydrogen sulfide H2S 20% + + + + +
(+) Suitable, (-) Not Suitable, (L) Limited Service
2.2.8 Field welding is not permitted on choke and kill lines. These must be welded in an API licensed shop to a qualified welding procedure and must, at a minimum, pass hardness tests (HRC 22 or less) and radiography of the welds.
2.2.9 All choke and kill lines shall be as straight as possible with targeted, block tees at turns. The tees will be lead targeted with renewable target flanges. Welded or threaded tees are not acceptable.
NOTE: Threaded tees that are seal welded are NOT ALLOWED in any service.
NOTE: Chiksans are not acceptable for kill line, emergency kill line or choke line.
2.2.10 All kill, emergency kill, choke and choke manifold connections should be flanged, API licensed factory welded, integral or hubbed and shall be monogrammed to API Specification 6A.
2.3 Requirements for Drilling Chokes:
2.3.1 A remote controlled hydraulic choke(s) shall be installed on each manifold. All chokes used in Saudi Aramco service must be from one of the approved models listed below. Acceptable models are:
SWACO 'Super Choke' Cameron Drilling Choke NOV Shaffer Drilling Choke
NOTE: Choke makes and models not listed above will not be accepted.
2.3.2 All Chokes, regardless of make and model, shall comply with the following specifications:
Monogrammed to API Specification 6A or 16C PSL-2 (or better) (With PSL-3 Gas Test) PR-1 (or better)
MR-DD (or better)
TR-U (5,000 psi working pressure or lower) TR-X Suitable for 0-350 o
F service (10,000 psi working pressure or higher) Forged bodies and bonnets
Alloy 625 or better, inlaid ring grooves
2.4 Requirements for Manual Gate Valves, Hydraulic Gate Valves and Check Valves:
2.4.1 Manual Gate Valves shall be non-rising stem, single slab floating gate valves with one-piece seat design (Body Bushings Not Allowed). Split gates or valves with floating or two-piece seats that can pressure lock are not acceptable. Nitrile/Buna Elastomer Seals are not allowed. PTFE/PEEK Based Seals are acceptable. Manufacturers are not specified for contractor owned manual gate valves, however, it should be noted that each valve must be re-certified by the OEM at contract start-up and every three (3) years thereafter. Hydraulic Controlled Remote (HCR) Gate Valves will be required to meet the same specification with the exception of the Stem. HCR Gate Valves are allowed to incorporate a rising stem and a balance stem on the bottom of the valve body.
Approved Hydraulic Valve Manufacturers: Cameron (all sizes), Axon (7-1/16” only).
2.4.2 All Gate Valves shall comply with the following specifications (in addition to Section 1.1): Monogrammed to API Specification 6A
PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PSL-2 (or better) (5,000 psi and lower)
PR-1 (or better) MR-DD (or better)
TR-U (5,000 psi working pressure or lower) TR-X suitable for 0-350 o
F service (10,000 psi working pressure or higher) Forged bodies and bonnets
2.4.3 All Check Valves shall comply with the following specifications (in addition to Section 1.1):
Monogrammed to API Specification 6A
PSL-2 (or better) (5,000 psi and lower) PR-1 (or better)
MR-DD (or better)
TR-U (5,000 psi working pressure or lower) TR-X suitable for 0-350 o
F service (10,000 psi working pressure or higher) Forged bodies and bonnets
Top entry valves only, no bottom body penetrations. Metal to metal seal valves only.
2.5 Requirements for Cup Testers:
2.5.1 Cameron Type ‘F’ cup testers are the only approved model. All elastomers and other parts must be OEM.
3.0 ACCESSORY BOP EQUIPMENT REQUIREMENTS
3.1 Pit Volume Totalizers:3.1.1 All rigs shall have a pit volume totalizer installed. These should be kept on at all times, even when out of the hole, changing bits or logging.
3.1.2 Charts and, or, warning devices (horn, lights etc.) should be installed at the Drill Floor, Mud Logging unit and the Toolpushers or Drilling Representative's office.
3.2 Mud Flow Indicators:
3.2.1 All rigs shall have a mud flow indicator installed. These should be kept on at all times, even when out of the hole, changing bits or logging.
3.2.2 Electrical Differential and the Flow Sensor types are approved.
3.3 Gas Busters:
3.3.1 Gas busters (poor boy degassers) shall be installed on every rig.
3.3.2 The vent lines must meet the following requirements:
Lines will be 8” minimum OD flanged or clamped steel line (minimum of 240’ in length, from the gas buster)
Same pressure rating (or greater) than that of the gas buster.
Shall terminate in a flare pit, positioned 50’ beyond the edge of the reserve/waste pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.
3.3.3 The gas buster design for ‘deep gas rigs’ is shown in Figure A-3.1 The minimum internal capacity for Gas Rig gas busters is 35 barrels.
3.3.4 The gas buster design for ‘oil development rigs’ is shown in Figure A-3.2 The minimum internal capacity for Oil Rig gas busters is 17.5 barrels.
3.3.6 Never circulate cement returns through a gas buster.
3.3.7 Gas busters have a tendency to shake and rattle when they are in use. They should be securely anchored.
3.3.8 All gas busters shall be built in compliance to ASME Boiler and Pressure Vessel Code, Section VIII, Division I, with all materials meeting requirements of NACE Standard MR-01-75/ISO15156 (Latest Revision). All welding on the vessel shall meet ASME requirements. New gas busters shall be hydrostatically tested to 190 psi to give a maximum working pressure of 150 psi, as per ASME.
FIGURE A-3.1: Mud Gas Separators for Gas Service
3.3.9 There should be a by-pass line upstream of the separator directly to the flare line and a valve on the separator inlet line to protect the separator from high pressure.
3.3.10 The mud discharge line from the separator must have a vacuum breaker stacked vent line if the discharge line outlet is lower than the bottom of the separator. This is to prevent siphoning gas from the separator to the mud pits. The vacuum breaker stack must be as high as the separator.
3.3.11 MGS/Gas Buster must be fully inspected and tested every five (5) years. Inspection will include full visual, Pressure Testing, 100% Magnetic Particle or Dye Penetrant NDE and Ultra Sonic to determine the integrity of the wall thickness. Additionally, Inspection Documentation with 3 year validity must be submitted at new rig start-up as well as for rig contract renewal.
3.4 Full Opening Safety Valves:
3.4.1 A full opening safety valve to fit each size of drill pipe and drill collar in use will be kept in the open position on the rig floor (including a closing/opening wrench).
3.4.2 A safety valve and appropriate cross-over are also required when running casing and tubing.
3.4.3 Care should be taken to ensure that valves have the proper threads and that they will go through the BOP stack and casing. This will allow the valves to be stripped into the hole below an inside BOP.
NOTE: Full Open Safety and Kelly valves must be designed and manufactured in compliance with API Spec 7-1.
The term 'full opening' does not mean that the ID of the valve is the same as the pipe, but rather that the bore through the valve is not restricted.
3.5 Inside BOP:
3.5.1 An inside BOP to fit each size of drill pipe and drill collar in use will be kept in the open position on the rig floor.
NOTE: Inside BOP must be designed and manufactured in compliance with API Spec 7-1.
3.6 Trip Tank:
3.6.1 A circulating trip tank will be used on all rigs while tripping out of or back into the hole.
3.6.2 The trip tanks shall have two (2) 60 barrel compartments.
3.6.3 There shall be two (2) independent measuring devices, a mechanical float operated pit level indicator graduated in inches and an electro-mechanical device.
FIGURE A-3.3: Typical Trip Tank
3.6.4 Calculated versus actual volumes shall be monitored and recorded in a log book recording the following data:
Volume and weight of slug
Number of strokes the slug is pumped.
Time for slug to stabilize and flow to stop in the annulus. Amount of mud to fill hole:
o 5 Stands for Drill Pipe o 2 Stands for HWDP o Every Stand for Dill Collars
NOTE: If the volume of mud used to fill the hole is not correct for any interval, stop pulling and determine the reason the hole is not taking mud properly.
Total volume of mud per trip to fill hole (calculated and measured)
3.7 Bowl Protectors (Wear Bushings):
Bowl protectors, or wear bushings, protect the hanger bowl in the casing or tubing head during drilling operations.
3.7.1 Bowl protectors shall be used in all operations when drilling through the wellhead.
NOTE: Bowl protectors, just like BOP test plugs have a Manufacturer specific profile. The bowl protector used must match the Manufacturer and Model of the Wellhead.
3.8 Valve Removal Plugs:
Valve Removal (VR) plugs are one-way check valves that can be installed through an outlet valve on a casing head, casing spool or tubing spool into a female thread in the outlet for its repair or replacement. Once the valve has been repaired or replaced the VR plug can be removed.
3.8.1 VR plugs shall be removed from the wellhead in order to have access to the annulus. This should be confirmed prior to nippling up the wellhead.
3.8.2 VR plugs are to be installed under the blind flanges on all wellheads prior to the rig move/well completion.
3.8.3 Under no circumstances should a VR plug be left in a side outlet that has a valve installed.
3.9 Drillpipe Float Valves:
Drill pipe float valves shall be run in all Saudi Aramco operations except when planned operations preclude running a float; testing, treating or squeezing. The drillpipe float valve shall be positioned directly above the bit.
3.10 Weco Connections:
3.10.1 Weco connections (other than the remote connections at the end of the catwalk) are not acceptable for kill, emergency kill or choke line service.
3.10.2 Factory Manufactured Integral or butt welded Figure 1502 connections are acceptable downstream of the choke manifold buffer tank for land and offshore operations. Field fabricated connections are not acceptable.
3.10.3 Weco type connections are not acceptable on well test lines upstream of the Choke & Kill Manifold.
3.10.4 2 inch Figure 602 connections are not allowed in any Saudi Aramco Drilling and Workover Operation.
3.11 Chiksans / Swivel Joint:
3.11.1 Chiksans are sections of pipe with hammer unions and two swivels in each joint. The primary use of chiksans is to run temporary lines for high pressure pumping and cementing operations. 3.11.2 Chiksans shall not be used in kill lines, emergency kill lines or choke lines.
3.12 Accumulator Closing Units:
The brand of closing unit used by the Drilling or Workover Contractor is not specified by Saudi Aramco, however, all closing units shall meet the following requirements.
Fluid Requirements:
3.12.1 The accumulator shall store enough fluid under pressure to close all preventers, open the choke HCR valve and retain 50% of the calculated closing volume with a minimum of 200 psi above pre-charge pressure without assistance from the accumulator pumps.
Design Requirements:
3.12.2 The accumulators and all fittings will be a minimum of 3,000 or 5,000 psi working pressure depending on the BOP Ram Bonnet working pressure. The Accumulator and all Hydraulic lines from the accumulator to the BOP stack shall be designed and manufactured in accordance with API Specification 16D. All Accumulators and Lines must be manufactured by an API 16D Licensed Facility. Onshore Hoses must be sleeved and shielded externally steel encased (equivalent to Gates 16 EFBOP Blow-Out Preventer Hose). Offshore hoses are not required to be externally steel encased. The hose end connection must be of a winged hammer or hex union style. All piping and connections used from the Accumulator Unit to the BOP must be ASME/ANSI SCH 160 or equivalent. Quick-Connect type connections are not allowed. Manifold and BOP hydraulic lines should be tested to the system working pressure at installation.
NOTE: All air and hydraulic BOP operating units shall be equipped with regulator valves similar to the Koomey type TR-5. These will not fail open causing loss of operating pressure.
Bottle Pre-Charge Requirements:
3.12.3 Accumulator bottles will be pre-charged with nitrogen as per manufacturer’s specifications/recommendations. The minimum required pre-charge pressure for a 3,000 psi (20.7 MPa) working pressure accumulator unit is 1,000 psi (6.9 MPa). The minimum required pre-charge pressure for a 5,000 psi (34.5 MPa) working pressure accumulator unit is 1,500 psi (10.3 MPa). The nitrogen pre-charge pressure shall be checked and adjusted prior to connecting the closing unit to the BOP stack and any other time the accumulator must be completely de-pressured.
3.12.4 The accumulator should be capable of closing each ram within 30 seconds. Closing time should not exceed 30 seconds for annulars smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of 18-3/4” and larger.
Operating Controls:
3.12.5 All operating controls shall be clearly marked with function and ram sizes. Accumulator controls must be in open or closed position, but not in neutral position. During normal drilling operations the HCR valve next to the wellhead will be closed. Unused functions shall be marked “Out of Service”, covered or have the handles removed on the main and remote units. Unused functions shall have the open/close lines plugged at the main unit.
Accumulator and Controls Locations:
3.12.6 Master Controls shall be at the accumulator. There must be at least two (2) sets of remote controls for operating the accumulator to activate the BOPs and all HCR valves. HCR valves on the choke line, kill line and the C&K manifold shall be powered by the main accumulator unit. One remote control shall be on the rig floor, accessible by and visible to the driller and the other shall be located near the Company Representative’s office.
Onshore: The accumulator shall be located at a remote location, at least 60 feet distance from the wellbore for oil wells and 100 feet for gas wells, shielded from the wellhead and protected from other operations around the rig.
Offshore: The accumulator shall be shielded from the wellhead and the drill floor and protected from other operations around the rig. It should be located as far as practically possible from the wellhead.
Pump System:
3.12.7 Two pump systems are required. The preferred configuration is to have one electric/hydraulic and the second pneumatic (air)/hydraulic. The primary electric/hydraulic pump system and the secondary pneumatic/hydraulic pump system must be independent of each other and fully operational when the accumulator is in use. The high-pressure set point for both the electric pump and air pump should be 3,000 or 5,000 psi. The low-pressure set point should be above 2,800 psi for both systems. Do not bleed off pressure due to ambient temperature rise. Pressure may vary from 3,000 to 3,400 or 5,000 to 5,400 psi in a 24-hour period.
It is permissible to have two independent electric/hydraulic systems. however, they must have separate and totally independent prime movers.
Each of the two systems shall have the quantity and sizes of pumps such that, with the accumulators isolated from service, the following steps are completed within two minutes:
The annular BOP closes on the minimum size drill pipe being used All hydraulically operated valves opened
Provide the pressure recommended by the annular BOP manufacturer to effect a seal on the annulus
Pressure Regulator Settings:
3.12.8 The pressure regulators for the annular preventer and ram preventers will be set as per manufacturer’s specification/recommendation. All BOPs with Shear Blind Rams installed shall have a bypass to route full system pressure to the SBR's.
NOTE 1 For non-emergency BOP operation, use of the lowest possible pressure will extend elastomer life. Upon completion of the daily testing the pressure regulators shall be returned to the normal operation pressure.
NOTE 2 DO NOT close annular preventers on open hole for complete shut-off except in an emergency.
NOTE 3 DO NOT close pipe rams without pipe in the hole. Pipe rams should only be closed on the proper size pipe in order to avoid damage to the rubber packer or to the ram carriers (DO NOT CLOSE on TOOL JOINTS).
Shear Ram Safety Covers and Alarms:
3.12.9 The Shear Blind Ram controls are to have the following safety and alarm features:
Safety covers (box style) shall be installed over all SBR controls. These covers will be secured with a pin (that must be removed before opening the cover) and will be of a type that must be lifted to operate the control. They should be clear plastic or have observation holes in them so the position lights may be seen. Covers shall be installed on all SBR controls at all remote stations and the accumulator.
The covers shall be fitted with switches that will activate horns and strobe lights when the cover is lifted, before the control is operated. Horns will be installed on the rig floor and at the accumulator. The alarms will be tested during each well control drill and BOP test. The alarms should emit a significantly different sound than the H2S or any other alarms on the rig.
3.13 Stroke Counters:
Stroke counters provide the Driller a method of measuring fluid volumes when displacing special fluids or lost circulation pills. It is also used to determine pumped volumes when executing well control procedures.
3.13.1 Stroke counters are required on all rigs at both the Driller's station and the choke control console.
NOTE: The kill line should not be used in conjunction with the rig pumps and a stroke counter for hole filling purposes. The kill line is an emergency piece of equipment and should not be used for routine hole fill-up during trips.
3.14 Gas Detectors:
These devices, usually found in mud logging units, are useful in detecting abnormal pressure sections as well as shows of hydrocarbons. Rig Supervisors should monitor the trip gas, connection gas, and background gas for any significant change. The presence of gas in the mud can be one of the more useful indicators of abnormal pressure. Gas Detector readings can sometimes be misleading, however, and the important things to look for are the relative trends and magnitudes, rather than the individual number of gas units reported.
3.15 Drill Rate Recorders:
These devices come in both analogue and digital styles. They are useful as correlation tools, particularly if logs are available from other wells in the area. The records can be used to detect and correlate formation tops and types, as well as in selecting bits and estimating their useful lives. A sudden increase in penetration rate can be one of the first signs of a well kick.
3.16 Pump Lines for Existing Offshore Well Kill:
Steel chicksan swivel joints, connections and piping may be used for the purpose of killing an existing well with cased hole prior to or after rig arrival. However, only factory Manufactured Integral or butt welded Figure 1502 connections are acceptable.
CHAPTER B: BOPE SYSTEM CONFIGURATION
TABLE OF CONTENTS
1.0
BOP EQUIPMENT SYSTEM CONFIGURATION
1.1 Pressure Rating of BOPE Systems B-3
2.0
CLASS ‘A’ 15,000 psi BOP STACK
2.1 Usage B-3
2.2 Class ‘A’ 15,000 psi BOP Stack Arrangement (Single Sized Drill Pipe) B-4
2.3 Class ‘A’ 15,000 psi BOP Stack Arrangement (Tapered Drill Pipe String) B-7
3.0
CLASS ‘A’ 10,000 psi BOP STACK
3.1 Usage B-8
3.2 Class ‘A’ 10,000 psi BOP Stack Arrangement (Single Sized Drill Pipe) B-8
3.3 Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered Drill Pipe String) B-11
4.0
CLASS ‘A’ 5,000 psi BOP STACK
4.1 Usage B-12
4.2 Class ‘A’ 5,000 psi BOP Stack Arrangement (Single Sized Drill Pipe) B-12
4.3 Class ‘A’ 5,000 psi BOP Stack Arrangement (Tapered Drill Pipe String) B-15
5.0
CLASS ‘A’ 3,000 psi BOP STACK
5.1 Usage B-16
5.2 Class ‘A’ 3,000 psi BOP Stack Arrangement for Large Hole (Single Sized Drill Pipe) B-16
5.3 Class ‘A’ 3,000 psi BOP Stack Arrangement for Smaller Hole (Single Sized Drill Pipe) B-18
5.4 Class ‘A’ 3,000 psi BOP Stack Arrangement (Tapered Drill Pipe String) B-18
6.0
CLASS ‘B’ 3,000 psi BOP STACK
6.1 Usage B-19
6.2 Class ‘B’ 3,000 psi BOP Stack Arrangement B-19
7.0
CLASS ‘C’ 3,000 psi BOP STACK
B-218.0
CLASS ‘D’ DIVERTER STACK
B-229.0
CLASS ‘I’ 2,000 psi WORKOVER STACK
9.1 Usage B-24
10.0 CLASS ‘II’ 3,000 psi WORKOVER STACK
10.1 Usage B-25
10.2 Class ‘II’ 3,000 psi Stack Arrangement B-25
11.0 CLASS ‘III’ 5,000 psi WORKOVER STACK
11.1 Usage B-25
11.2 Class ‘III’ 5,000 psi Stack Arrangement B-26
12.0 CLASS ‘IV’ 10,000 psi WORKOVER STACK
12.1 Usage B-26
12.2 Class ‘IV’ 10,000 psi Stack Arrangement B-26
13.0 CLASS ‘V’ 15,000 psi WORKOVER STACK
13.1 Usage B-26
13.2 Class ‘IV’ 10,000 psi Stack Arrangement B-26
14.0 SPECIAL WELL OPERATIONS BOP STACKS
14.1 BOP Equipment Requirements for Coil Tubing Operations B-26
14.2 BOP Equipment Requirements for Snubbing B-30
14.3 BOP Equipment Requirements for Electric Line Operations B-33
15.0 CHOKE MANIFOLDS
15.1 15,000 PSI Working Pressure Choke Manifold B-35
15.2 10,000 PSI Working Pressure Choke Manifold B-38
15.3 5,000 PSI Working Pressure Choke Manifold B-41
15.4 3,000 PSI Working Pressure Choke Manifold B-43
15.5 Location B-44
15.6 Choke Manifold Pressure Ratings B-44
15.7 Piping Specifications B-44
15.8 Choke Manifold Discharge and Flare Lines B-44
1.0 BOP EQUIPMENT SYSTEM CONFIGURATION
This Chapter of the Well Control Manual sets forth the configurations for BOP equipment systems for use in Drilling and Workover Operations. All equipment must comply with the other chapters in this manual. Variations or deviations of BOP equipment, specifications, arrangement, pressure rating or requirements from this standard requires endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling or Workover Rig Superintendent. The Rig Foreman shall ensure that the proper equipment is available and correctly installed. If not specified in these standards all BOP equipment shall comply with API Specifications and Recommended Practices. The BOP equipment must be arranged to allow:
A means of closing the top of the open hole, as well as around drill pipe or collars, and stripping the drill string to bottom.
A means of pumping into a hole and circulating out a well kick. A controlled release of the influx.
Redundancy in equipment in the event that any one function fails.
All preventers shall be installed so that rams can be changed without moving the stack. The drilling program shall specify the Class BOP stack (not individual components) to be used. 1.1 Pressure Rating of BOPE Systems:
The pressure rating of the BOP system is based on the MASP (Maximum Anticipated Surface Pressure). The minimum rated working pressure of the BOP system shall be selected based on MASP for each hole section as detailed in the table below:
BOP Equipment Pressure Rating
OIL WELL MASP (in PSI)
GAS WELL MASP (in PSI)
INJECTION WELL MASP (in PSI)
3,000 PSI ≤ 2,550 ≤ 2,700 < 3,000
5,000 PSI ≤ 4,250 ≤ 4,500 < 5,000
10,000 PSI ≤ 8,500 ≤ 9,000 < 10,000
15,000 PSI ≤ 12,750 ≤ 13,500 < 15,000
NOTE-1: Does not include diverter requirements.
NOTE-2: BOP’s with higher rated working pressure than shown above may be used at any time.
2.0 CLASS ‘A’ 15,000 PSI BOP STACK
2.1 Usage:A Class ‘A’ 15,000 psi BOP stack shall be installed on all offshore and onshore wells with a MASP up to the limits given in the table above. If MASP exceeds these limits a higher pressure rating will be required.
The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 15M.
2.2 Class ‘A’ 15,000 psi BOP Stack Arrangement (Single Size Drill Pipe):
When using a single size of drill pipe the stack arrangement (from bottom to top) shall be as described below and as shown in Figure B-1:
2.2.1 A wellhead spool or tree with a 18-3/4", 13-5/8", 11” or 7" 15M flange with two (2) 3-1/16" 15M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" (minimum) 15M flanged gate valves with a blind flange installed.
2.2.2 If the top flange of the wellhead is below ground level, a spacer spool spacer is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.
2.2.3 A flanged or studded double gate ram preventer shall be installed on the wellhead or spool. The BOP shall be above ground level with master drill pipe rams in the bottom position (1) and blind rams in the top position (2).
2.2.4 A flanged drilling cross shall be installed on the double ram preventer. The drilling cross shall have two (2) 4-1/16" 15M flanged side outlets.
2.2.5 Kill Lines
There shall be two (2) kill lines, an upper and a lower. Both lines shall be 3-1/16" 15M and configured as below:
From the drilling cross out on the kill line side, there shall be:
a double studded adapter flange 4-1/16" 15M to 3-1/16" 15M a 3-1/16" 15M flanged manually operated gate valve
a 3-1/16" 15M flanged hydraulic control (HCR) gate valve a 3-1/16" 15M flanged spacer spool
a 3-1/16" 15M studded tee
The bottom outlet of the tee will connect to the lower kill line. The other side of the tee will have a flanged spacer spool followed by a second studded tee. On each side of the second tee there shall be a 3-1/16" 15M flanged gate valve and a 3-1/16" 15M flanged check valve. On the remote (emergency pump connection) side, the kill line shall be 15M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 3" welded union. On the primary (mud pump) side, the kill line shall be connected directly to the mud pumps or to the stand pipe manifold, with a 10M manual isolation valve between the kill line and the 7,500 psi stand pipe.
The lower kill line from the 4-1/16" 15M BOP master pipe ram side outlet out there shall be: a 4-1/16" X 3-1/16" 15M DSA
two (2) 3-1/16" 15M flanged manually operated gate valves
3-1/16" 15M flanged spacer spools and studded (targeted) tees as required
a 3-1/16" 15M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.
2.2.5 Choke Lines
There shall be two (2) choke lines, an upper and a lower. Both lines shall be 4-1/16" 15M and configured as below:
From the drilling cross out on the choke line side there shall be: a 4-1/16" 15M flanged manually operated gate valve a 4-1/16" 15M flanged hydraulic control (HCR) gate valve a 4-1/16" 15M flanged spacer spool
a 4-1/16" 15M studded tee
The bottom outlet of the tee will connect to the lower choke line. The other side of the tee will connect (through flanged line) to the manually operated gate valve at the choke manifold.
The lower choke line from the 4-1/16" 15M BOP master pipe ram side outlet out there shall be:
a 4-1/16" 15M flanged manually operated gate valve a 4-1/16" 15M flanged hydraulic control (HCR) gate valve
a 4-1/16" 15M flanged spacer spools and studded (targeted) tees as required a 4-1/16" 15M flanged manually operated gate valve attached directly to the studded
tee on the upper choke line.
NOTE: All steel piping shall be made with 15M flanges, targeted tees, block-tee elbows, and factory-manufactured 15M working pressure line. All tees must be targeted with renewable 15M blind flanges (welded tees are not acceptable).
Chiksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, or choke line. Coflex hose (refer to Chapter A, Section 2.0) may be used in combination with steel line for the choke or kill line.
2.2.6 A 15M flanged or studded double gate ram preventer shall be installed on the 15M drilling cross. There shall be shear blind rams in the bottom (3) and drill pipe rams in the top (4) of the double ram preventer.
2.2.7 A 10M or 15M annular preventer will be installed on the top of the double ram preventer. The annular shall be flanged bottom X studded top.
2.2.8 A flanged rotating head, with a flanged bottom connection to match the top connection of the annular preventer and a 9" 3M flanged side outlet, may be installed on top of the annular preventer. A spacer spool may be required if annular studded top is not compatible with the rotating head flange.
2.3 Class ‘A’ 15,000 psi BOP Stack Arrangement (Tapered Drill Pipe String):
When using a tapered string of drill pipe the stack arrangement shall be the same as that for the single string EXCEPT the blind rams in the bottom double (2) shall be changed to pipe rams and sized for the smaller sized pipe and the master pipe rams (1) and upper pipe rams (4) shall be sized for the larger pipe as shown in Figure B-2:
3.0 CLASS ‘A’ 10,000 PSI BOP STACK
3.1 Usage:A Class ‘A’ 10,000 psi BOP stack shall be installed on all offshore and onshore wells with a MASP of up to 8,000 psi.
The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 10M
3.2 Class ‘A’ 10,000 psi BOP Stack Arrangement (Single Size Drill Pipe):
When using a single size of drill pipe the stack arrangement (from bottom to top) shall be as described below and as shown in Figure B-3:
3.2.1 A wellhead spool or tree with a 18-3/4", 13-5/8", 11” or 7" 10M flange with two (2) 3-1/16" (minimum) 10M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" 10M flanged gate valves with a 3-1/16” blind flange installed.
3.2.2 If the top flange of the wellhead is below ground level, a spacer spool spacer is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.
3.2.3 A flanged or studded double gate ram preventer shall be installed on the wellhead or spool. The BOP shall be above ground level with master drill pipe rams in the bottom position (1) and blind rams in the top position (2).
3.2.4 A flanged drilling cross shall be installed on the double ram preventer. The drilling cross shall have two (2) 4-1/16" 10M flanged side outlets.
3.2.5 Kill Lines
There shall be two (2) kill lines, an upper and a lower. Both lines shall be 2-1/16" 10M and configured as below:
From the drilling cross out on the kill line side, there shall be:
a double studded adapter flange 4-1/16" 10M to 2-1/16" 10M a 2-1/16" 10M flanged manually operated gate valve
a 2-1/16" 10M flanged hydraulic control (HCR) gate valve a 2-1/16" 10M flanged spacer spool
a 2-1/16" 10M studded tee
The bottom outlet of the tee will connect to the lower kill line. The other side of the tee will have a flanged spacer spool and followed by another studded tee. On each side of this tee there shall be a 2-1/16" 10M flanged gate valve and a 2-1/16" 10M flanged check valve. On the remote (emergency pump connection) side, the kill line shall be 10M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 2" welded union. On the primary (mud pump) side, the kill line shall be connected directly to the mud pumps or to the stand pipe manifold, with a 5M manual isolation valve between the kill line and the 5,000 psi stand pipe.
The lower kill line from the 4-1/16" 10M BOP master pipe ram side outlet out there shall be:
a 4-1/16" X 2-1/16" 10M DSA
two (2) 2-1/16" 10M flanged manually operated gate valves
2-1/16" 10M flanged spacer spools and studded (targeted) tees as required
a 2-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.
3.2.6 Choke Lines
There shall be two (2) choke lines, an upper and a lower. Both lines shall be 4-1/16", 10M and configured as below:
From the drilling cross out on the choke line side there shall be:
a 4-1/16" 10M flanged manually operated gate valve a 4-1/16" 10M flanged hydraulic control (HCR) gate valve a 4-1/16" 10M flanged spacer spool
a 4-1/16" 10M studded tee
The bottom outlet of the tee will connect to the lower choke line. The other side of the tee will connect (through flanged line) to the manually operated gate valve at the choke manifold.
The lower choke line from the 4-1/16", 10M BOP master pipe ram side outlet there shall be:
a 4-1/16" 10M flanged manually operated gate valve a 4-1/16" 10M flanged hydraulic control (HCR) gate valve
4-1/16" 10M flanged spacer spools and studded (targeted) tees as required
a 4-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper choke line.
NOTE: All steel piping shall be made with 10M flanges, targeted tees, block-tee elbows, and factory manufactured 10M working pressure line. All tees must be targeted with renewable 10M blind flanges (welded tees or field fabricated equipment is not acceptable).
Chiksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, or choke line. Coflex hose (refer to Chapter A Section 2.0) may be used in combination with steel line for the choke or kill line.
3.2.7 A 10M flanged or studded double gate ram preventer shall be installed on the 10M drilling cross. There shall be shear blind rams in the bottom (3) and drill pipe rams in the top (4) of the double ram preventer.
3.2.8 A 10M annular preventer will be installed on the top of the double ram preventer. The annular shall be flanged bottom X studded top.
3.2.9 A flanged rotating head, with a flanged bottom connection to match the top connection of the annular preventer and a 9" 3M flanged side outlet, may be installed on top of the annular
preventer. A spacer spool may be required if annular studded top is not compatible with rotating head flange.
3.3 Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered Drill Pipe String):
When using a tapered string of drill pipe the stack arrangement shall be the same as that for the single string EXCEPT the blind rams in the bottom double (2) shall be sized for the smaller sized pipe and the master pipe rams (1) and upper pipe rams (4) shall be sized for the larger pipe as shown in Figure B-4.
Figure B-4 Class ‘A’ 10,000 psi BOP Stack with a Tapered String of Drill Pipe
4.0 CLASS ‘A’ 5,000 PSI BOP STACKS
4.1 Usage:A Class ‘A’ 5,000 psi BOP stack shall be installed on wells where MASP may become more than 2,401 psi but not more than 4,000 psi. All of the elements of the BOP stack shall be 5,000 psi rated working pressure. All preventers shall be installed so that rams can be changed without moving the stack.
The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 5M.
4.2 Class ‘A’ 5,000 psi BOP Stack Arrangement:
The stack arrangement (from bottom to top) shall be as described below and as shown in Figure B-5:
4.2.1 A wellhead spool (or casing head) with a 18-3/4", 13-5/8", 11” or 7" 3M or 5M flange with two (2) 2-1/16" or 3-1/16" 3M or 5M studded side outlets shall be installed. One outlet shall have a flanged gate valve with a blind flange installed. The other outlet shall have a manually operated flanged gate valve installed next to the wellhead and a hydraulically operated (HCR) flanged gate valve connecting to the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 2” 5M rated working pressure. Flexible hose (compliant with Chapter A section 2.0) may be used in combination with steel line.
The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 2" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump. Offshore the emergency kill line will extend to the emergency pump / cement unit.
NOTE: If shear blind rams are utilized, then the emergency kill line shall be 3” and 5M rated working pressure. The manual gate valve shall remain as 2” with double studded adapter to 3”.
NOTE: If the wellhead spool has a 5M top flange, then the side outlet valves shall be 5M.
NOTE: All BOP equipment with working pressures of 3,000 psi and above shall have flanged, welded, integral, or hubbed connections only.
4.2.2 If the top flange of the wellhead is below ground level, a spacer spool is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.
4.2.3 A 5M flanged single ram preventer shall be installed on the wellhead spool with master drill pipe rams.
4.2.4 A 5M flanged drilling cross shall be installed on the single ram preventer. The drilling cross shall have two (2) 3-1/8" (minimum) 5M side outlets.
4.2.5 There shall be a double studded adapter flange to adapt from one of the BOP side outlets to the 2-1/16" 5M kill line and one from the other BOP side outlet to the 3-1/8” choke line.
4.2.6 Kill Lines:
From the drilling cross out on the kill line side, there shall be: a 2-1/16" 5M flanged manually operated gate valve a 2-1/16" 5M flanged hydraulic control gate valve a 2-1/16" 5M flanged spacer spool
a 2-1/16" 5M flanged tee
On each side of the tee there shall be a 2-1/16" 5M flanged gate valve and a 2-1/16" 5M flanged check valve.
On the remote side, the kill line shall be 5M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 2" welded union.
On the primary side, the kill line shall be 5M and connected directly to the mud pumps or to the stand pipe manifold.
4.2.7 Choke Lines:
On the choke line, from the drilling cross out, there shall be:
a 3-1/8" 5M flanged manually operated gate valve a 3-1/8" 5M flanged hydraulic control gate valve
a 3-1/8" 5M steel flanged line or flexible hose (Chapter A, Section 2.0) to a 3-1/8" 5M flanged manually operated gate valve at the choke manifold
NOTE: All steel piping shall be made with 5M flanges, targeted tees, block-tee elbows, and factory-made 5M working pressure line. All tees must be targeted with renewable 5M blind flanges (welded tees are not acceptable).
Chiksans and Weco connections (other than the remote connection at the end of the catwalk on land operations) are not acceptable. Flexible hose (refer to Chapter A Section 2.0) may be used in combination with steel line for kill, emergency kill line, or choke line.
4.2.8 Either two (2) flanged/studded single ram preventers or a double ram preventer shall be installed, with blind rams in the position immediately above the drilling spool and VBR’s installed immediately below the annular.
Variable bore rams are required to be used on Class ‘A’ 5M stacks. However, the master pipe ram must be a fixed ram.
NOTE: Currently, Cameron’s Extended Range High Temperature VBR-II Packer is the only variable bore ram that is approved for 5M applications (3-1/2" - 5-7/8" pipe sizes). Additional information regarding the use of variable bore rams is provided in Chapter A, Section 1.4.
4.2.9 A 5M flanged bottom and studded top annular preventer will be installed on the top ram preventer.
4.2.10 A rotating head is optional.
4.3 Class ‘A’ 5,000 psi BOP Stack Arrangement for Tapered Drill Pipe String:
The Class ‘A’ 5,000 BOP Stack arrangement for tapered drill strings will be the same as it is for single sized drillpipe EXCEPT the upper pipe rams (position 3) will be sized for the smaller sized drill pipe as shown in Figure B-5. Alternatively, the upper pipe rams may be Variable Bore Rams as per Chapter A Section 1.4. NOTE: Variable Bore Rams are not allowed in the Master Pipe Ram position (lowermost rams).
5.0 CLASS ‘A’ 3,000 PSI BOP STACK
5.1 Usage:Large Diameter Hole (as with Deep Gas Wells):
A Class ‘A’ 3,000 psi BOP stack shall be installed on all wells where large diameter hole (as with deep gas wells) is being drilled, as through 18-5/8" casing, and where hydrocarbon reservoirs with a MASP of up to 2,400 psi may be drilled. All preventers shall be installed so that rams can be changed without moving the stack.
Smaller Diameter Hole (as with Critical Oil Wells):
At the discretion of the Drilling Manager, some wells may require a Class ‘A’ 3,000 psi stack instead of a Class ‘B’ 3,000 psi stack.
Shear blind rams on onshore stacks are required only on wells with high H2S, wells in gas cap areas and wells in populated areas (close proximity). Further details on the use of shear blind rams is provided in Chapter A section 1.5.
5.2 Class ‘A’ 3,000 psi BOP Stack Arrangement for Large Diameter Hole (Single Size Drill Pipe): All elements of Class ‘A’ 3,000 psi stacks shall be at least 3,000 psi rated working pressure. The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 20-3/4” and 26-3/4" 3M. Each ram preventer shall have two (2) 4-1/16" 3M side outlets. A double ram preventer will have four side outlets.
When using a single size of drill pipe the stack arrangement (from bottom to top) shall be as described below and as shown in Figure B5:
5.2.1 A wellhead spool (18-5/8" landing base or casing spool) with 20-3/4" 3,000 psi flange and two (2) 3-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 3-1/16" 3M gate valve with a 3-1/16" 3M blind flange. The other outlet shall have a manually operated 3-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 3-1/16" 3M flanged gate valve tied into the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 3” 3M rated working pressure. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 3" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump.
5.2.2 If the wellhead top flange is below ground level a spacer spool is required. If the BOP Stack is larger than the wellhead a DSA is required.
5.2.3 A 26-3/4” or 20-3/4” 3M flanged single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams (1).
5.2.4 A 26-3/4” or 20-3/4” 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have two (2) 4-1/16" 3M side outlets.
