Well Control Manual Saudi Aramco 6th Edition

DRILLING & WORKOVER WELL CONTROL MANUAL 6th EDITION, VOLUME I MAY, 2018

© Saudi Arabian Oil Company 2018. All rights reserved. No portion of this document may be reproduced, by any process or technique, without the express written consent of Saudi Aramco Well Control Committee

Saudi Aramco Well Control Manual Volume I, 6th Edition INTRODUCTION AND DOCUMENT CONTROL CHAPTER A

EQUIPMENT REQUIREMENTS

CHAPTER B

BOP SYSTEMS

CHAPTER C

MAINTENANCE, TESTING AND RECERTIFICATION

CHAPTER D

WELL CONTROL POLICIES

CHAPTER E

WELL CONTROL DRILLS

Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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CHAPTER A: EQUIPMENT SPECIFICATIONS AND REQUIREMENTS TABLE OF CONTENTS 1.0

2.0

3.0

PRIMARY WELL CONTROL EQUIPMENT REQUIREMENTS 1.1

General Requirements

A-3

1.2

Annular Units and Diverters

A-7

1.3

Fixed Ram Preventers and Elastomers

A-8

1.4

Variable Bore Ram Preventer Blocks and Elastomers

A-8

1.5

Shear Blind Ram (SBR) Blocks and Elastomers

A-9

1.6

Valve Removal Plugs and Blind Flanges on BOP Side Outlets

A-11

1.7

Drilling Spools

A-11

REQUIREMENTS FOR KILL, EMERGENCY KILL, CHOKE LINES AND CHOKES 2.1

Minimum Bore Size for Lines:

A-11

2.2

Material and Fabrication

A-12

2.3

Requirements for Drilling Chokes

A-15

2.4

Requirements for Valves

A-15

ACCESSORY BOP EQUIPMENT REQUIREMENTS 3.1

Pit Volume Totalizers

A-16

3.2

Mud Flow Indicators

A-17

3.3

Gas Busters

A-17

3.4

Full Opening Safety Valves

A-20

3.5

Inside BOP

A-20

3.6

Trip Tank

A-20

3.7

Bowl Protectors (Wear Bushings)

A-21

3.8

BOP Test Plugs & Cup Testers

A-22

3.9

Valve Removal Plugs

A-22

3.10 Drillpipe Float Valves

A-22

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3.11 Drillpipe Rotating or Non-Rotating Torque Protectors

A-22

3.12 Weco Connections

A-22

3.13 Chiksans / Swivel Joints

A-23

3.14 Accumulator Closing Units

A-23

3.15 Stroke Counters

A-26

3.16 Gas Detectors

A-26

3.17 Drill Rate Recorders

A-26

3.18 Pump Lines for Existing Offshore Well Kill

A-27

3.19 Studs & Nuts

A-27

TABLE A-1: WCE Recertification Intervals

A-6

TABLE A-2: Annular Units and Diverters H 2 S and Temperature

A-7

TABLE A-3: Ram BOP’s, Ram Blocks & Wetted Elastomers H 2 S and Temperature

A-8

TABLE A-4: VBR Ram Blocks & Wetted Elastomers H 2 S and Temperature

A-9

TABLE A-5: Shear Ram Blocks & Wetted Elastomers H 2 S and Temperature

A-9

TABLE A-6: Shear Blind Ram Min. Shearing Capability 10K & 15K Service

A-10

TABLE A-7: Shear Blind Ram Min. Shearing Capability 3K & 5K Service

A-11

TABLE A-8: Kill Line Min. Bore Size

A-12

TABLE A-9: Emergency Kill Line Min. Bore Size

A-12

TABLE A-10: Choke Lines Min. Bore Size

A-12

TABLE A-11: Technip COFLON Flexible Line Compatibility 3K & 5K

A-13

TABLE A-12: ContiTech/Phoenix Flexible Line Compatibility 3K & 5K

A-14

TABLE A-13: Gates Black Gold Xtreme Flexible Lines

A-14

TABLE A-14: Flange-Bolting Size & Required Torque Values

A-28

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WELL CONTROL EQUIPMENT SPECIFICATIONS AND REQUIREMENTS

This Chapter of the Well Control Manual (WCM) sets forth the specifications and requirements for Well Control Equipment (WCE) systems for use in Drilling and Workover Operations. Variations or deviations of WCE, specifications, arrangement, pressure rating or requirements from this standard requires endorsement of the Well Control Committee, and approved waiver signed by the Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling & Workover Operations Managers and Superintendents. The Rig Foreman shall verify WCM compliant equipment is available and correctly installed. If not specified in this standard all WCE shall comply with the respective API Standards and Recommended Practices. Saudi Aramco Foremen and Consultant Foremen shall maintain only IADC WellSharp certification Level 4 for Surface Installations (No IWCF). Contractor rig personnel shall maintain current well control certification through IADC WellSharp or IWCF. Drillers and Assistant Drillers are allowed IADC Driller Level or IWCF Level 3. Toolpushers, OIM’s, Rig Managers and equivalent, shall maintain IADC Supervisor Level or IWCF Level 4. 1.1

General Requirements: All Drilling and Workover Well Control Equipment shall meet the following requirements: 1.1.1

All WCE (Annular BOPs, Ram Type BOPs, Valves, Chokes, Crosses, Spools, Flexible Lines, Hard Lines, Choke & Kill Manifolds assemblies, etc.) shall be of forged material (no castings), individually Monogrammed to latest edition API 6A, 16A, 16C or other applicable API Standards as defined in 1.1.1, paragraph 1 of this manual. Maintenance, repair and PM Schedules shall be as required in API 16AR and API 53 latest editions and Saudi Aramco WCM. 1)

API Monogram and Markings: Saudi Aramco prefers that all WCE in service within Saudi Aramco D&WO Operations carry an API Monogram. Newly purchased/manufactured WCE, after release of WCE 6th Edition as confirmed by the Original Equipment Manufacturer (OEM) Certificate of Conformance (COC), will be required to carry an API Monogram. All WCE markings including; monogram (if applicable), serial number, part number, size, pressure rating, etc. MUST be clearly visible through the painted coating of the equipment. Care should be taken to preserve markings on the equipment nameplate, flange or body to prevent it being obliterated or destroyed during handling, maintenance, repair and use. Additionally, documentation and COC must be available at the rig site reflecting the full equipment details; monogram (if applicable), serial number, part number, size, pressure rating, etc.

2)

Periodic Maintenance (PM) Program: Drilling contractors must implement and record a comprehensive schedule-based WCE Periodic Maintenance (PM) Program that meets all requirements of API-53 Latest Edition. The PM Program will be an audit item for adherence and implementation. PM must include a complete list of WCE subject to the PM Program. The list will include the OEM Name, Serial Number Part Number, Size, and Pressure Rating, date of previous PM and schedule date of the next PM. The PM program shall address inspection (internal/external visual, dimensional, NDE, etc.) schedules for WCE critical components and sealing areas; bonnet gaskets, rams, shear ram blades, ram cavities and wetted elastomers (Elastomeric wellbore sealing components are any seal that comes in contact with wellbore fluids, (e.g. annular packers, ram block seals, operator rod or stem seals, valve seat, etc.). Inspections of the choke, kill lines, valves and other well control assemblies shall be performed in accordance with the OEM recommendations and PM program for wear, erosion, plugging, or other damages. BOP or drilling spool outlets connected to the choke or kill line shall be detailed in the equipment owner's PM program to include an inspection of the component for erosion at least every two years. Visual

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inspection intervals for all WCE, including; BOP bonnets, cavities and rams, is not to exceed each rig move or 90 days whichever is less. . Certain well operations or conditions (e.g. milling, well control events, bromide use, etc.) will require more frequent inspection and maintenance. NOTE: Condition-based PM is not acceptable. 1.1.2

TRACEABILITY: All major WCE 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 a unique serial or asset identification number assigned at time of manufacture by the 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’s, ram blocks, manual/hydraulic gate valves, check valves, manual/hydraulic chokes, safety valves and closing units. Documentation (e.g.; PO, invoice, certificate of compliance etc.) must be maintained at the rig site, for all parts verifying the parts are original OEM.

1.1.4

Additional 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 kill and emergency lines.

1.1.10 The kill line, emergency kill line and choke lines should be flushed and cleaned out frequently to prevent LCM or mud solids settling or caking. The BOP stack bore shall be flushed and cleaned by way of a jetting tool after cementing operations and before nipple-down. 1.1.11 The lower (secondary) choke and kill lines shall not be used in place of the upper (primary) choke and kill lines for circulation. Primary circulation lines will always be the upper lines connected to the drilling cross or upper BOP outlet if a drilling cross is not present. 1.1.12 Onshore BOP stack assemblies will be nippled-down between wells to visually inspect for internal corrosion, erosion and to check flange bolts. Offshore BOP stack assemblies will be nippled-down and visually inspected every three months as a minimum. The inspection procedure and all findings must be documented and verified by the Saudi Aramco Rig Foreman. Refer to Chapter C for maintenance procedures and requirements. 1.1.13 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 to be witnessed and co-signed by the Toolpusher and the Saudi Aramco Representative (see form #1 in Chapter C of this manual).

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1.1.14 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. 1.1.15 At time of new manufacture and repair/remanufacture, all WCE must meet NACE MR-0175/ISO 15156, and API Specifications 6A, 16A, 16AR, 16C or 16D for sour service. WCE must also meet the requirements of API 53 and API 64. 1.1.16 A full OEM certification or recertification of the WCE, must be performed at the start of a new rig contract. Thereafter OEM recertification will be as stated below. 1.1.17 All WCE ≤3,000 psi: ≤3,000 psi, regardless of gas or oil service will be 5-year recertification. 1.1.18 Gas & Offshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Gas or Offshore Oil service will be 3-year recertification and will retain the balance of current 3-year certification if moving to Onshore Oil service. EXAMPLE: A 13-5/8”, 10K BOP used in Gas or Offshore Oil for 1 year then transferred to Onshore Oil service will retain the remaining 2 years validity of the COC. OEM recertification would be required within the following 2 years. If remaining in Onshore Oil service, the new equipment COC would be valid for 5 years. 1.1.19 Onshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Onshore Oil service will be 5-year recertification. However, if ≥5,000 WCE has been in Onshore Oil service for 3 years, it cannot be transferred to Gas or Offshore Oil and retain the remaining 2-year validity of the COC . EXAMPLE: A 13-5/8”, 10K BOP used in Onshore Oil service for 2-years then transferred to Gas or Offshore Oil will not retain the remaining 3 years COC validity. The remaining validity in this example would be 1 year because of the transfer. OEM recertification would be required within the following 1 year. If remaining in Gas or Offshore Oil, the new equipment COC would be valid for 3 years. 1.1.20 The Recertification must be in accordance with the relevant API or NACE Standards for repair/remanufacture. The OEM COC and corresponding repair/remanufacture documentation package shall be kept with the equipment and must be available for inspection at the rig site by Saudi Aramco personnel. WCE for recertification includes, but is not limited to:            

BOP’s: Ram and Annular Ram blocks API Diverters Manual/hydraulic gate valves and check valves on the kill, emergency kill Manual/hydraulic gate valves on choke line and choke manifold. Hydraulic drilling chokes. Manual chokes Kill, emergency kill and choke lines (and line components) including both hard line and flexible lines. Drilling spools. Double Studded Adapters (DSA) Tees, crosses, hardline spools and buffer chamber BOP Lifting Plates or Lifting flanges shall undergo full OEM NDE when the BOP’s are recertified.

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WCE PSI ≤2,000 3,000 5,000 ≥10,000**

TABLE A-1 BOP RECERTIFICATION INTERVALS ONSHORE OFFSHORE ALL GAS OIL OIL ONSHORE or OFFSHORE* 5 YEARS 5 YEARS 5 YEARS 5 YEARS 5 YEARS 5 YEARS 5 YEARS* 3 YEARS 3 YEARS 5 YEARS* 3 YEARS 3 YEARS

1.1.21 Recertification can only be performed by the OEM or their licensee facility and shall meet the requirements of all applicable OEM and industry standards, i.e. API 6A, API 16A, API 16AR, API 16C, NACE, etc. If recertified by an OEM licensee, the document package shall include a copy of the license issued by the OEM. OEM’s and Licensee facilities are required to maintain a QA/QC Program qualified to the latest ISO 9001 or API-Q2. In-field recertification is not acceptable. 1.1.22 New equipment purchased after the release of WCM 6th Edition, must be API Monogrammed and shall be accompanied by the manufacturer's certificate of compliance and a full documentation package including inspection and test reports. Offshore Oil WCE, ≥5,000 psi, will be 3-year recertification. Transfer of Offshore Oil 5,000 psi WCE to Onshore for the reason of delaying recertification is prohibited. 1.1.23 API 6A dumb iron with 100% API specified dimensions i.e., drilling spools, Double Studded Adapters (DSA), tees, crosses, blind flanges and hardline spools, require recertification but are not required to use OEM for recertification. Instead this equipment can be inspected, repaired and recertified by any qualified API 6A Licensed facility. This does not apply to other API 6A equipment such as gate valves, check valves or manual adjustable chokes. 1.1.24 All BOPE including, but not limited to, annulars, ram type, valves, spools, crosses, tees and other end and outlet connections with working pressures of 2,000 psi and above shall have OEM welded flange, integral flange, or hubbed connections only. Threaded connections or threaded connections that have been seal welded are not permitted. 1.1.25 All Ram Type BOP cavities MUST CONTAIN Ram Blocks. Vacant ram cavities during operations are not permitted. 1.1.26 Field welding or torch cutting of any kind is not allowed on any of the WCE contained in this manual. 1.1.27 Cap Screws or bolting that attaches the shear ram blade to the ram block shall conform to:   

The requirements of API 20E BSL-3 or API 20F BSL3 and API 6A as appropriate for the material type. Manufacturer’s written specification and requirements for the chemical composition and mechanical properties. Shear ram blades, shear ram blocks, and blade retention screws or bolts shall be inspected annually by OEM visual inspection and surface NDE. The inspection results shall be verified against the manufacturer’s acceptance criteria.

1.1.28 Drilling Contractors are strongly discouraged from sharing BOP equipment between rigs without equipment owner documented basic maintenance and inspection after the previous installation. 1.1.29 Gas Testing of API 6A “dumb iron”, i.e. tee blocks, spools, tee’s, crosses, etc. is not required. Gas Testing is required when recertifying PSL-3G Gate Valves and Check Valves.

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1.1.30 All metallic materials in contact with well fluids shall meet the requirements of NACE MR-01-75 /ISO 15156 for sour service. BOP forgings must meet these minimum yield requirements; ≤5,000 PSI: 60K or higher yield and ≥10,000 PSI: 75K yield. 1.1.31 All non-metallic elastomers in contact with well fluids, shall be tested in accordance with, and shall meet all the requirements of NACE TM0187, latest version, for Elastomeric Materials in Sour Gas Environments. Hardness test requirements as per ASTM-D2240 or ASTM-D1415 as appropriate for the elastomer size and type. 1.1.32 Saudi Aramco owned WCE will be maintained and located at the Saudi Aramco Drilling & Workover Services Department, Drilling Equipment Repair Unit (DERU) Facility. The DERU facility, in line with recognized industry best practices for the repair and or maintenance of WCE, is required to maintain a QA/QC Program qualified to the latest ISO 9001 or API-Q2. Saudi Aramco owned WCE must meet the recertification requirements as stated in this manual. WCE which has been installed on Gas or Offshore Oil service at any time from the previous recertification, and is then moved to Onshore Oil Service, the re-certification will remain at 3-years. 1.1.33 Elastomeric components shall be stored in a manner recommended by the equipment manufacturer, to include climate and UV exposure control. When a WCE component, or assembly is taken out of service for an extended period of time, it shall be completely washed or steam cleaned, and machined surfaces coated with a corrosion inhibitor. BOPs shall have the rams or sealing element removed and the internal BOP body/cavities shall be thoroughly washed, inspected, and coated with a corrosion inhibitor in accordance with the equipment owner's and manufacturer's requirements. All outlet connections shall be covered and protected from environmental elements. 1.1.34 OEM Lift plates, or similar OEM means of safe handling, shall be installed on all BOP’s. The plates or lifting components must be marked with the Safe Working Load (SWL), Manufacturers Name, Mfg. Part Number and a Serial Number. The plates must have a combined load rating to allow lifting and handling of the full BOP Stack and associated Choke & Kill lines. Lift plates shall undergo full OEM NDE when recertifying the BOP. 1.2

Annular Units and Diverters: 1.2.1

All annular units must comply with the Section 1.2 specifications, in addition to the requirements in Section 1.1.

1.2.2

The minimum acceptable ratings for H 2 S and temperature are as follows:

PSI

H2S

≤2,000 3,000 – 5,000 ≥10,000

2.5% 2.5% 2.5%

TABLE A-2 Annular Units and Diverters API 16A Metallic API 16A Non-Metallic Temp Rating (F) Temp Rating T-0/2500 EAA T-0/2500 EAA T-0/3500 EAA

API 16A PR PR-1 PR-1 PR-2

NOTE: Temperature and PR Levels are defined in API-16A, Fourth Edition.

1.2.3

The acceptable annular manufacturers are Cameron (T-90 Model ≤5,000), GE-Hydril and NOVShaffer (all pressures).

1.2.4

GE Vetco KFDJ and Dril-Quip MD diverters are acceptable for offshore permanent installed rotary diverter systems in 500, 1,000 and 2,000 psi service. Dril-Quip, is currently the only approved design for the 36.5”, 500 psi onshore diverter. New permanent installed rotary diverter systems shall be monogrammed to API 16D.

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Permanent installed rotary diverter systems shall undergo an OEM (onsite or offsite) inspection and function test every 5 years. Inspection documentation shall reside at the rig. NOTE: The Dril-Quip onshore diverter is not eligible for API Monogram and is not subject to the 3-year recertification requirement. Only maintenance/repair after each nipple-up is required.

1.3

1.2.5

If a rotary diverter system is utilized on an offshore rig, the diverter control unit must have interlock functionality which activates the Diverter discharge lines to vent below the drilling package in case of H 2 S.

1.2.6

Bolted top, latched top, wedge top and screw-top annulars are acceptable.

1.2.7

30 inch 1,000 psi annulars are non-monogrammed under API specification 16A. Only maintenance/repair after each nipple-up is required.

Ram BOP’s / Ram Blocks / Wetted Elastomers: 1.3.1

All fixed ram preventers must comply with the Section 1.3 specifications, 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. No VBR Rams in the master pipe ram position.

1.3.3

The minimum acceptable ratings for H 2 S and temperature for BOP’s and Ram assemblies are:

PSI 3,000 5,000 ≥10,000 NOTE:

1.3.4

TABLE A-3 Ram BOP’s / Ram Blocks / Wetted Elastomers H2S API 16A Metallic API 16A Non-Metallic Temp Rating (F) Temp Rating 5% T-0/2500 EBD 10% T-0/2500 EBD 20% T-0/3500 EDE

API 16A PR PR-1 PR-2 PR-2

Temperature and PR Levels are defined in API-16A, Fourth Edition. All wetted elastomers must be tested in accordance with NACE TM0187-2011 for Elastomeric Materials in Sour Gas Environments.

Cameron, NOV-Shaffer (including the Model 6012) and GE-Hydril are acceptable manufacturers for ram preventers. All ram assemblies shall meet NACE Standards MR-01-75 and TM0187 (latest editions) for sour service. NOTE: VBR and fixed size rams CANNOT CLOSE on TOOL JOINTS.

1.4

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.

1.3.6

Four cavity 10K and 15K BOP stacks drilling in 5K oil service can substitute blind rams with permanent casing rams.

Variable Bore Ram Preventer Blocks and Elastomers: 1.4.1

All variable bore ram blocks must comply with the Section 1.4 specifications in addition to the requirements in Section 1.1 and 1.3.

1.4.2

Variable bore rams (VBR) are optional for tapered drill string applications in Class ‘A’ stacks with pressure rating of ≤5000 psi. In all cases the master pipe ram (bottom ram) must be a fixed ram.

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1.4.3

The minimum acceptable ratings for H 2 S and temperature for VBR's are:

PSI 3,000 5,000 NOTE:

1.4.4

TABLE A-4 Ram BOP’s / Ram Blocks / Wetted Elastomers H2S API 16A Metallic API 16A Non-Metallic Temp Rating (F) Temp Rating 5% T-0/2500 EBD 10% T-0/2500 EBD

API 16A PR PR-1 PR-2

Temperature and PR Levels are defined in API-16A, Fourth Edition. All wetted elastomers must be tested in accordance with NACE TM0187-2011 for Elastomeric Materials in Sour Gas Environments.

The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) used in the Cameron 13-5/8” U Type blowout preventer 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% H 2 S. 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 at this time.

1.5

Shear Blind Ram (SBR) Blocks and Elastomers: 1.5.1

SBR's are required on:        

1.5.2

Close Proximity Wells (All wells located near populated areas or in the vicinity of gas/oil production facilities as defined in Saudi Aramco Engineering Standard SAES-B-062 Onshore Wellsite Safety). Gas Cap Wells (Either 3,000 or 5,000 Class ‘A’ Stacks). Onshore Class ‘A’ 5,000 psi stacks (Expl./Dev. Wells >10 % H 2 S). Smart Well Completions and Downhole monitoring systems where more than one (1) line is strapped to the OD of the tubing. ESP Completions and workovers 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).

The minimum acceptable ratings for H 2 S and temperature for SBR's are:

PSI 3,000 5,000 ≥10,000 NOTE:

1.5.3

API 16A PR PR-1 PR-2 PR-2

Temperature and PR Levels are defined in API-16A, Fourth Edition. All wetted elastomers must be tested in accordance with NACE TM0187-2011 for Elastomeric Materials in Sour Gas Environments.

Approved Shear Blind Rams are as follows:  

1.5.4

TABLE A-5 Ram BOP’s / Ram Blocks / Wetted Elastomers H2S API 16A Metallic API 16A Non-Metallic Temp Rating (F) Temp Rating 5% T-0/2500 EBD 10% T-0/2500 EBD 20% T-0/3500 EDE

Cameron Shearing Blind Rams Shaffer V-Shear and LFS (Low Force Shear) Rams

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

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shown in this manual. They may be used on Class B BOP stacks on close proximity wells (as defined in Saudi Aramco Engineering Standard SAES-B-062) 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: Dual pipe rams may not be used in conjunction with SBR’s on a Class B stack. 1.5.5

SBR’s can be used during testing and during a well control incident. SBR’s may also be used, in 3 ram configurations, as a mechanical barrier for changing upper rams or annular. If a blind ram is installed in a 4 ram configuration, then use it instead of the SBR.

1.5.6

SBR’s shall not be used as a “hole cover” against dropped items when out of the hole. A steel hole cover with locating pins should be available on the rig floor to cover the hole when pipe is out for BHA work and fluid level should be constantly monitored.

1.5.7

Shear Rams must meet all of the requirements of API 16A 4th Edition & Later for PR2 Shear Ram Testing (With Seals).

1.5.8

The below tables 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

DEEP GAS EXPL/ DEV.

BOPE SIZE - WP CLASS 18-3/4" 15M CLASS 'A'

13-5/8" 10M/15M, CLASS 'A'

11" 10M CLASS 'A'

NOTE: (1) (2) (3)

TABLE A-6 MFG.

CAMERON TL (1) NOV CAMERON U (1) NOV (1)

DRILL PIPE SHEAR CAPABILITY ALL SIZES TO 5-1/2" 24.7# G-105 ALL SIZES TO 5-1/2" 24.7# G-105 ALL SIZES TO 5-1/2" 24.7# G-105 ALL SIZES TO 5-1/2" 24.7# G-105

OPERATOR REQUIRED SIZE

'SBR'

YES/ LBT (2)

CVX-W

(1)

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SIDE PACKER TEMP (0F) 30-300

H 2 S, (%) 20

30-300

'SBR'

YES/ LBT (2)

30-300

20

6000 SBR Low Force

LBT (2) 14"/10" (3) YES/ LBT (2)

30-300

20

30-300

20

30-300

20

ALL SIZES TO 'SBR' 5" 19.5# G-105 NOV (1) ALL SIZES TO 6000 BSR 14"/10" (3) 5" 25.6# G-105 CAMERON AND NOV-SHAFFER ARE APPROVED MANUFACTURERS. CAMERON - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS. NOV SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.

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CAMERON

REQUIRED SHEAR BLIND RAM TYPE

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3,000 - 5,000 PSI SERVICE BOP SERVICE

BOPE SIZE - WP CLASS

OFFSHORE / ONSHORE EXPL/DEV. w/ H 2 S > 10% GAS CAP WELL POPULATED AREAS

NOTE: (1) (2) (3)

1.6

1.7

MFG.

DRILL PIPE SHEAR CAPABILITY

REQUIRED SHEAR BLIND RAM TYPE

OPERATOR REQUIRED SIZE

CAMERON (1)

SIDE PACKER TEMP (0F) 30-250

ALL SIZES TO 'SBR' YES/ LBT (2) 5-1/2" 24.7# G105 NOV (1) ALL SIZES TO 6000 SBR 30-250 LBT (2) 5-1/2" 24.7# GLow Force 14"/10" (3) 105 11" 3-5M CAMERON (1) ALL SIZES TO 'SBR' 30-250 YES/ LBT (2) CLASS 'A' 5" 19.5# G-105 NOV (1) ALL SIZES TO 6000 BSR 30-250 14"/10" (3) 5" 25.6# G-105 CAMERON AND NOV-SHAFFER ARE APPROVED MANUFACTURERS. CAMERON OR NOV 6012 - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS. NOV-SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.

H2S (%) 10

10

10 10

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 without VR plugs installed shall be a fluid cushion blind flange with no penetrations.



Flanges installed on the side outlets of ram preventers with VR plugs installed shall have a ½ inch NPT or an Autoclave port (depending on the pressure rating; 15K requires Autoclave) with the appropriate plug installed.

Drilling Spools: 1.7.1

All Drilling Spools shall comply with the following requirements:         

2.0

13-5/8" 3-5M CLASS 'A'

TABLE A-7

Monogrammed to API Specification 6A or 16A PSL-2 (≤5,000 psi working pressure) PSL-2 with PSL-3 Gas Test (≥10,000 psi working pressure) PR-1 (or better) MR-DD (or better) TR-U (≤5,000 psi working pressure) TR-X Suitable for 350 oF service (≥10,000 psi working pressure) ≤10,000 PSI: Forged Material, 60K Yield Minimum, No Castings ≥15,000 PSI: Forged Material, 75K Yield Minimum, No Castings

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 Choke & Kill Lines Shall Be As Follows:

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KILL LINE TABLE A-8 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 TABLE A-9 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 CHOKE LINES TABLE A-10 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

2.2

2.1.1

The complete piping system; lines, valves, chokes, tees, crosses and choke manifold upstream of the buffer chamber, will match or exceed the full working pressure of the BOP. Buffer Chamber and Gate Valves equipment downstream of the chokes may be one API pressure rating lower than the BOP and choke lines.

2.1.2

Rigs utilizing ≤5,000 psi BOP equipment shall have 3-1/8” dual choke lines and 2-1/16” and dual kill line access, (one above the lower rams and one above the lower rams). There shall be primary and emergency kill lines, with primary tie-in from the mud pumps and the emergency tie-in allowing high-pressure access by a cement unit. All configurations are as specified in Chapter B.

2.1.3

Rigs utilizing ≥10,000 psi BOP equipment shall have 4-1/16” dual choke lines and 2-1/16” dual kill line access, (one above the lower rams and one above the lower rams). There shall be primary and emergency kill lines, with primary tie-in from the mud pumps and the emergency tie-in allowing high-pressure access by a cement unit. All configurations are as specified in Chapter B.

2.1.4

Offshore applications shall access the kill line via cement line tie-in on the C&K manifold, rather than direct connection. All configurations are as specified in Chapter B.

Material and Fabrication: 2.2.1

The lines from the BOP stack to the choke manifold shall have the same working pressure, or greater, than the BOP stack. All lines and equipment shall meet API Standards 6A, 16A or 16C as applicable and NACE MR-01-75/ISO 15156 latest revision for Sour Service.

2.2.2

Choke/Kill lines for 3M and 5M applications shall be either factory manufactured AISI 4130 forged steel pipe, flexible line or a combination of the two.

2.2.3

Choke/Kill lines ≥10M shall be either factory manufactured AISI 4130 forged steel pipe or a combination of hard line and flexible Line.

2.2.4

Flexible steel line if used in combination with 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:  

Made by an approved manufacturer as listed in section 2.2.8 below. All components of the line and end fittings in possible contact with wellbore fluids meet Sour Service NACE MR-01-75/ISO 15156 latest revision.

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2.2.5

All pressure containing components shall be pressure tested and Monogrammed as per API specification 6A, 16A or 16C as appropriate.

2.2.6

Pressure containing steel choke & Kill line material shall be, at minimum; • •

≤10,000 PSI: AISI 4130, forged, 60 ksi yield (85 ksi tensile) ≥15,000 PSI: AISI 4130, forged, 75 ksi yield (95 ksi tensile)

All forgings shall meet the requirements of API specification 6A, 16A or 16C and NACE MR-0175/ISO 15156 latest revision for Sour Service. 2.2.7

New choke and kill flexible lines, purchased after release of WCM 6th Edition; ≤15,000 psi shall be of a non-bonded or bonded construction. All flexible lines shall be designed (including design validation), manufactured and tested in accordance with API 16C latest edition and Saudi Aramco Well Control Committee requirements for extended pressure and temperature testing. All choke & kill flexible lines shall meet a minimum API 16C, Flexible Specification Level FSL-2 and shall be monogrammed per API-16C. All steel materials used in the manufacture of end-fitting must be API 6A monogrammed, and meet the requirements of NACE MR-01-75, (latest edition). The end connection cannot be threaded or welded. The wire used for the reinforcement and armor layers must meet the latest NACE requirements in effect at the date of manufacture.

NOTE: Technip does not manufacture an API monogrammable 4” ID, 10K or 15K C&K Flexible line for sour service at this time. Therefore 3” ID, 10K and 15K Flexible Line for sour service with 4” end connections are acceptable. 2.2.8

Flexible choke and kill lines shall be monogrammed to API Specification 16C. If flange connections are installed on the flexible line, the flange will be monogrammed to API-6A. The only approved flexible choke and kill lines are:    

Technip/Coflexip (coflon lined) ≥10,000 Continental ContiTech-Thermo plastic lined (allowed only for ≤5,000 psi) ContiTech/Phoenix (allowed only for ≤5,000 psi) (see product compatibility table) Gates Black Gold Xtreme (allowed only for ≤5,000 psi) (see product compatibility table)

Product Compatibility of Technip COFLON Inner lined Flexible Line TABLE A-11 Medium Concentration 0oF 75oF 150oF 200oF -18oC 24oC 66oC 93oC Hydrochloric acid HCl 15% S S S S 30% S S S S Hydrofluoric acid HF 3% S S S S 7.5% S S S S Xylene C6H4 (CH3)2 100% S S S S Methanol CH3OH 100% S S S S Zinc bromide ZnBr2 Saturated S S S S Calcium bromide CaBr2 Saturated S S S S Calcium chloride CaCl2 Saturated S S S S Methane CH 4 100% S S S S Diesel 100% S S S S Crude Oil 100% S S S S Sea Water --+ + + Sodium hydroxide NaOH 50% S S L NR Hydrogen sulfide H 2 S 20% S S S S S: Satisfactory, L: Limited NR: Not Recommended L: Limited Service

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250oF 121oC S S S S S S S S S S S S NR S

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Product Compatibility of HNBR lined ContiTech/Phoenix Flexible Line TABLE A-12 Medium Concentration 0oF 75oF 150oF 200oF o o o -18 C 24 C 66 C 93oC Hydrochloric acid HCl 15% + + Hydrofluoric acid HF 0.6% + + Xylene C6H4 (CH3)2 25% + + + L Methanol CH3OH 100% + + L L Zinc bromide ZnBr2 Saturated + + L L Calcium bromide CaBr2 Saturated + + L L Calcium chloride CaCl2 Saturated + + L L Diesel 100% + + + + Sea water --+ + + Sodium hydroxide NaOH 50% L L Hydrogen sulfide H 2 S 20% + + + + (+) Suitable, (-) Not Suitable, (L) Limited Service

250oF 121oC L L L L L +

Product Compatibility of Gates Black Gold Xtreme Flexible Lines TABLE A-13 Medium Concentration 0°F 75°F 150°F 212°F 250°F -18°C 24°C 66°C 100°C 121°C HCl 15% max HF 3% max Xylene 100% + + + L Methanol 100% + + L Zinc Bromide Saturated Calcium Bromide Saturated L L L L Calcium Chloride Saturated + + L L Methane 100% + + + + L Diesel 100% + + + + L Crude Oil 100% + + + + L Sodium Hydroxide 50% max + L H2S <20% + + + + L H 2 S (wet) <20% L L L L L Water* 100% + + + L L (+) Suitable, (-) Not Suitable, (L) Limited Service *The pH value of the fluid may influence the behavior of the inner liner (See API Spec 17TR2 1st edition) 2.2.9

Field welding is not permitted on choke and kill lines. If line components are to be manufactured via fabricated, any welding must be conducted in an API 6A or 16A licensed facility to a qualified WPS welding procedure and must, at a minimum, pass hardness tests (HRC 22 or less) and radiography of the welds. The component shall also carry an API Monogram.

2.2.10 Choke and kill lines shall be as straight as possible with API 6A block: tee/cross or 450 at turns. Outlets on the BOP, block tees/cross/450 will incorporate targeted (fluid cushions), renewable flanges in the position downstream of the flow. 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.

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2.2.11 Kill, emergency kill, choke and choke manifold connections should be flanged, API licensed factory welded, integral or hubbed and shall be designed, manufactured and monogrammed to API Specification 6A or 16A. 2.2.12 Kill lines shall not be used as a fill-up line with the exception of the kill/fill line of the 36.5” Onshore Diverter. 2.3

Requirements for Drilling Chokes: 2.3.1

Remote controlled hydraulic choke(s) and manual chokes shall be installed on each manifold per the requirements of Chapter B of this manual. All hydraulic drilling chokes used in Saudi Aramco service must be from one of the approved models listed below. Acceptable models are:    

SWACO Super Choke or E-choke Cameron M3D and M3G Drilling Chokes NOV Shaffer MPX-40D Drilling Choke CORTEC CX3 Drilling Choke

NOTES: Hydraulic Choke brands and models not listed above are unacceptable. API 6A Manual Adjustable Chokes must meet the below specification but may be from manufactures other than those listed above. 2.3.2

All Chokes, regardless of make and model, shall comply with the following specifications:        

2.4

Monogrammed to API Specification 6A (manual adjustable) or 16C (hydraulic) PSL-3G (hydraulic & manual ≥10,000 psi) PSL-2 (manual ≤5000 psi) MR-DD (or higher) TR-U (≤5,000 psi) TR-X Suitable for 0-350o F service (≥10,000 psi) Forged bodies and bonnets, minimum: • ≤10,000 PSI: AISI 4130, forged, 60 ksi yield (85 ksi tensile) • ≥15,000 PSI: AISI 4130, forged, 75 ksi yield (95 ksi tensile) Alloy 625 inlaid ring grooves

2.3.3

New manufactured drilling chokes ≥10,000 psi shall undergo gas testing per API 16C, Annex B. The test shall be acceptable if there are no visible leaks and the pressure change observed on the pressure-measuring device is less than 5 % of the test pressure or 500 psi, whichever is less.

2.3.4

Drilling chokes under Re-certification shall be hydrostatic tested as per API 16C. The test shall be acceptable if there are no visible leaks and the pressure change observed on the pressuremeasuring device is less than 5 % of the test pressure or 500 psi, whichever is less.

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 are NOT ACCEPTABLE). Split gates or valves with two-piece/nested seats are capable of pressure locking so are not acceptable. Elastomeric Seals (Viton, Buna, HNBR and Nitrile) are not allowed as any part of the valve sealing mechanism. PTFE/PEEK Based Seals are acceptable. Stem Packing must be Varipak or equivalent. Gates are to be hardfaced using Praxair LW-45 or Bodycote CW-15. Manufacturers are not specified for drilling contractor owned manual and hydraulic gate valves or check valves, however, any manual, and hydraulic gate valves or check valves must meet the specifications and recertification requirements in this manual for Saudi Aramco operations. 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

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a rising stem and a balance stem on the bottom of the valve body. All Gate and Hydraulic Gate Valves must have been qualified to API 6A, Annex F, PR-1/PR-2 (as applicable) requirements. 2.4.2

All Gate Valves shall comply with the following specifications (in addition to Section 1.1):           

2.4.3

Monogrammed to API Specification 6A PSL-3G (≥10,000 psi) PSL-2 or higher (≤5,000 psi) PR-1 or higher (≤5000 psi) PR-2 (≥10,000 psi) MR-DD (or higher) TR-U (≤5,000 psi ) TR-X suitable for 0-350o F service (≥10,000 psi) Forged bodies and bonnets, minimum: • ≤10,000 PSI: AISI 4130, forged, 60 ksi yield (85 ksi tensile) • ≥15,000 PSI: AISI 4130, forged, 75 ksi yield (95 ksi tensile) Gates and seats shall be hard-faced using Praxair LW-45 or Bodycote CW-15 Alloy 625 inlaid ring grooves

All Check Valves shall comply with the following specifications (in addition to Section 1.1):            

Monogrammed to API Specification 6A PSL-3G (≥10,000 psi) PSL-2 or higher (≤5,000 psi) PR-1 or higher (≤5000 psi) PR-2 (≥10,000 psi) MR-DD (or higher) TR-U (≤5,000 psi) TR-X suitable for 0-350o F service (≥10,000 psi) Forged bodies and bonnets, minimum: • ≤10,000 PSI: AISI 4130, forged, 60 ksi yield (85 ksi tensile) • ≥15,000 PSI: AISI 4130, forged, 75 ksi yield (95 ksi tensile) Top entry valves only, no bottom body penetrations. Metal to metal seal valves only. Alloy 625 inlaid ring grooves

2.4.4

PSL-3G, ≥10,000 psi Gate and Check valves under Re-certification shall be gas tested as per API 6A, Annex J. Gate valves shall be seat/gate tested from both directions. The test shall be acceptable if there are no visible leaks. No visible bubbles shall appear in the water bath during the test hold period. A maximum reduction of the gas test pressure of 300 psi is acceptable, as long as there are no visible bubbles in the water bath during the holding period. All testing is to be recorded on a calibrated chart recorder and the charts shall be dated and signed.

2.4.5

PSL-2, ≤5,000 psi Gate and Check valves under Re-certification shall be hydrostatic tested as per API 6A. The test shall be acceptable if there are no visible leaks and the pressure change observed on the pressure-measuring device is less than 5 % of the test pressure or 500 psi, whichever is less.

3.0

ACCESSORY WCE 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.

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3.1.2 3.2

3.3

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.

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.

Mud/Gas Separator (MGS) - Gas Busters: 3.3.1

MGS/Gas busters (poor boy degassers) shall be installed on every rig.

3.3.2

The vent lines must meet the following requirements:

     

OIL Service: Vent Lines will be 8” minimum OD flanged or clamped steel line. GAS Service: Vent Lines will be 10” diverted into dual 8” OD flanged or clamped steel line at ground level. Oil and Gas vent lines minimum length will be 100’ beyond the far outside edge of the Reserve Pit. No valves allowed Same pressure and H 2 S rating (or greater) than that of the MGS. Shall be properly anchored positioned 100’ beyond the far outside edge of the reserve pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.

3.3.3

The MGS design for ‘deep gas rigs’ is shown in Figure A-1 Minimum internal capacity for Gas Rig MGS is 35 barrels.

3.3.4

The MGS design for ‘oil development rigs’ is shown in Figure A-2 Minimum internal capacity for Oil Rig MGS is 17.5 barrels.

3.3.5

MGS should be cleaned out periodically.

3.3.6

Never circulate cement returns through a MGS.

3.3.7

MGS have a tendency to shake and rattle when they are in use. They should be securely anchored.

3.3.8

All MGS shall be built in compliance to API 12J and ASME Boiler and Pressure Vessel Code, Section VIII, Division I (latest revision), 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 verify a maximum working pressure of 150 psi, as per ASME. NOTE: Pressure Relief Valves (PRV’s) are not required on the MGS.

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 isolate and protect the separator from high pressure.

3.3.10 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. There will be no valves installed on this line. 3.3.11 MGS/Gas Busters must be fully inspected every five (5) years in accordance with API-510. Inspection will include full visual, dimensional and 100% Magnetic Particle or Dye Penetrant NDE. UT inspection will be conducted to determine the integrity of the wall thickness. Additionally, Inspection Documentation with a minimum 3 year validity must be submitted at new rig start-up or rig contract renewal.

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FIGURE A-1: Mud Gas Separators for Gas Service Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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FIGURE A-2: Mud Gas Separators for Oil Service Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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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 certified lifting arrangement are also required when running casing and tubing.

3.4.3

Care should be taken to ensure that safety valves have the proper threads and that they will drift through the BOP stack and casing. This will allow the safety valves to be stripped into the hole below an inside BOP.

3.4.4

Safety valves shall be visually inspected and cycled on a frequent basis to confirm reliable operation and no ID obstructions. It is recommended that safety valves undergo OEM inspection every two years.

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.

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) Leave drill pipe wiper rubbers off pipe for the first five (5) stands to observe hole.

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FIGURE A-3: Typical Trip Tank 3.7

Bowl Protectors (Wear Bushings): Bowl protectors, or wear bushings, protect the Critical Sealing Areas of the casing or tubing head during drilling operations. These seal areas must be protected in order to achieve the proper annulus sealing when setting the tubing or casing hanger. 3.7.1

Bowl protectors shall be used in all operations when making up the BHA or drilling through the wellhead.

NOTE: Bowl protectors, have a Manufacturer specific O.D. profile. The bowl protector used must match the Manufacturer and Model of the Wellhead.

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3.8

BOP Test Plugs & Cup Testers: Test plugs matching the Wellhead Manufacturer and Model must be used when testing the BOP during drilling operations. 3.8.1

Wellhead Test plugs shall be used in all operations whenever BOP and associated WCE tests are conducted.

3.8.2

Cameron Type ‘F’ cup testers are the only approved model. All elastomers and other parts must be OEM. Spare elastomer cups shall be properly stored in OEM packaging in a climate-controlled environment and not exposed to UV. The cup expiry date and size shall be recorded in the equipment logbook. The rig contractor must maintain, on location, the correct size cups for the anticipated casing size and weight.

NOTE: As with wear bushings, test plugs, have a Manufacturer specific O.D. profile. The test plug used must match the Manufacturer and Model of the Wellhead. 3.9

Valve Removal Plugs: Valve Removal (VR) plugs 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.

3.10

3.9.1

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.

3.9.2

VR plugs are to be installed under the blind flanges on all wellheads prior to the rig move/well completion.

3.9.3

Under no circumstances should a VR plug be left in a side outlet that has a valve installed.

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 in order to prevent back-flow. The Drillpipe Float Valve is not considered a component of the well control system nor is it considered a barrier for the purpose of well control.

3.11

Drillpipe Rotating or Non-Rotating Torque Protectors: Prior to use, drill pipe rotating or non-rotating torque protectors/reducers must be approved by the WCC. The device must have undergone a series of successful shear and seal testing, confirmed by a WCC member or approved third party. Drill pipe rotating or non-rotating torque protectors/reducers should not be used on the final 500’ of drill string just prior to drilling into the hydrocarbon reservoir.

3.12

Weco Connections: 3.12.1 Weco connections (other than the remote connections at the end of the catwalk) are not acceptable for kill, emergency kill or choke line service. 3.12.2 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. 3.12.3 Weco type connections are not acceptable on well test lines upstream of the Choke & Kill Manifold.

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3.12.4 3.13

2 inch Figure 602 connections are not allowed in any Saudi Aramco Drilling and Workover Operation.

Chiksans / Swivel Joint: 3.13.1 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. 3.13.2 Chiksans shall not be used in kill lines, emergency kill lines or choke lines.

3.14

Accumulator Closing Units: Saudi Aramco does not specify the brand of closing unit used by the Drilling or Workover Contractor. There is no re-certification requirement for Accumulator Control Systems or control hoses. However, the Accumulator Control Unit and control hoses must undergo periodic maintenance every 3 months as a minimum. An OEM or OEM Qualified Designee, inspection and function test diagnostics (offsite or onsite) along with NDE and hydrostatic testing of the individual accumulator bottles is required every five years. All documentation including individual Accumulator Bottle test charts must reside on the rig. In addition, all closing units shall meet the following requirements. Fluid Requirements: 3.14.1 The accumulator unit 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. Accumulator unit electrical power shall be supplied from one or more Uninterruptable Power Supply (UPS) system(s) with backup battery capacities to operate the control system for a minimum of two hours (excluding the pump systems). The electrical power supply to electrical equipment shall automatically switch to an alternate source of electric supply when primary power is interrupted (excluding the pump systems). UPS batteries shall be a maintenance free design and sealed. Design Requirements: 3.14.2 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 latest edition. 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 hoses must meet Fire Testing to API 16D latest edition. All piping and connections used from the Accumulator Unit to the BOP must be ASME/ANSI SCH 160 or equivalent. QuickConnect type connections are not allowed. Manifold and BOP hydraulic lines should be tested to the system working pressure at installation. There is no recertification requirement for 16D hoses. Screw type quick release dry-break (non-spill) couplings, equivalent to Parker/Snap-Tite QR74 couplers are acceptable providing they meet the following specifications;       

Firesafe tested to API 16D & Lloyds Register of Shipping for fires up to 7000C. ACME Thread-to-Connect Design with Wing Nut. High Flow Capacity ONSHORE: Zinc-chromatid plated steel OFFSHORE: 316 stainless steel Working Pressure 5000 psi with connect-under-pressure capability - against pressures up to 3,000 psi Metal-to-metal sealing on the tapered nose with no elastomers that may dislodge and obstruct the flow through-bore. A Viton gasket is allowed in the female portion of the coupling only for interface with the male coupling sleeve.

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FIGURE A-4: Dry-Break (Non-Spill) Coupling Each pump system shall be protected from over-pressurization by a minimum of two (2) devices designed to limit the pump discharge pressure as follows:  

  

One device shall ensure that the pump discharge pressure does not exceed the system RWP. The second device, normally a relief valve, shall be set to relieve at not more than 10 % above the system RWP. The relief valve(s) and vent piping shall accommodate the maximum pumping capacity at not more than 133 % of system RWP. Verification shall be provided by either design calculation or testing. Devices used to prevent pump over-pressurization shall be installed directly in the control system supply line to the accumulators and shall not have isolation valves or any other means that could defeat their intended purpose. Relief devices on main hydraulic surface supplies shall be automatically resetting. Rupture discs and/or non-resetting relief valves can cause the complete loss of pressure control and shall not be used. Periodic maintenance must include pressure relief valve settings.

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: 3.14.3 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 1,200 psi (6.9 MPa). The minimum required precharge 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 depressured. 3.14.4 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: 3.14.5 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. All HCR/hydraulic gate valves on the choke and kill lines and on the choke & kill manifold shall be operated via the accumulator closing unit and remote panels. HCR/hydraulic gate valves shall not be operated via the rig floor hydraulic choke panel.

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Accumulator and Controls Locations: 3.14.6 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 operated by the main accumulator unit and remote panels. 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: 3.14.7 GENERAL: The air and hydraulic pumps must maintain control system available working pressure between 2,800 psi and 3,000 psi (3K System) and 4,800 psi to 5,000 psi (5K System). The air and hydraulic pump on-off pressure and run time settings will be as per OEM specifications. 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. The primary electric/hydraulic triplex pump system must be connected to the rig’s emergency power system. At least one pump system shall be available and operational, at all times. ONSHORE: Two pump systems are required. The required configuration is one electric/hydraulic and the second pneumatic (air)/hydraulic. The primary electric/hydraulic triplex pump systems and the secondary pneumatic/hydraulic pump systems must have independent power sources and operational when the accumulator is in use. Electric/hydraulic pump connected to the main buss and emergency generator with the pneumatic/hydraulic pump connected to an air compressor. OFFSHORE: It is permissible to have two independently powered electric/hydraulic systems. Each pump system shall have an independent power source. These pump systems shall be connected so that the loss of any one power source does not impair the operation of all of the pump systems. At least one pump system shall be available and operational, at all times. One pump may be powered from the emergency buss on an all-electric power rig. On electric drive rigs, separate electric motors and motor controllers fed from separate busses or from busses that can be isolated by means of a buss tie circuit breaker constitute independent power supplies. With the loss of one pump system or one power system, the remaining pump systems shall have the capacity to charge the main accumulator system from precharge pressure to the system RWP within 30 minutes. Each of the two systems shall have the quantity and size 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: 3.14.8 The pressure switches, regulators and solenoids for the annular and ram BOP controls will be set as per manufacturer’s specification/recommendation. All BOP Shear Blind Ram controls shall have a bypass to route maximum system working pressure to the SBR's.

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NOTES: 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. DO NOT close annular preventers on open hole for complete shut-off except in an emergency. 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: 3.14.9 The Shear Blind Ram controls are to have the following safety and alarm features:

3.15



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. NOTE: Touch Screen Control Panels incorporating and requiring dual push button for shear ram activation; will not require the plastic cover.



The covers shall be fitted with switches that will activate horns and strobe/rotating beacon 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 H 2 S or any other alarms on the rig. Touch Screen Control Panels incorporating and requiring dual push button for shear ram activation shall have the strobe/rotating beacon and horns installed. Both should activate when the dual buttons are pressed.

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. 3.15.1 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.

3.16

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.

3.17

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. 3.16.1 All rigs should have a drill rate recorder.

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3.18

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.

3.19

Studs & Nuts: Closure bolting studs and nuts for all end and side outlet connections shall be the correct size for the flange or connection. Alloy steel and carbon steel bolting shall meet all the requirements of API 16A Latest Edition for Land and Offshore Surface service Pressure Controlling/Containing, API 20E BSL-2 minimum and API 6A (for material class and mechanical testing) for NON-EXPOSED BOLTING. The bolts must be marked as required in API 20E, section 8.2 for BSL-2. Field fabricated studs, saw or flame cut, are not permitted. Bolting, flanges, studs, nuts, and pressure-containing joints in BOP systems, shall be in accordance with API 6A, API 16A, API 20E, API 20F and API-RP53, as applicable. This requirement also extends to bolting used for clamp connections. Studs and nuts shall be checked for proper size, type, and grade. After flange make-up, all nuts shall have full stud thread engagement on either end, as shown in Figure A-5 When making a pressure seal, the connection shall be established by applying the appropriate torque to the connection studs and/or bolts in accordance with API 6A. Using appropriate lubricant, torque shall be applied to studs and/or bolts in a criss-cross manner or in accordance with OEM recommendations. Bolt sizes 1-7/8” diameter and larger require make-up using hydraulic torque wrenches. When making up connections, excessive force should not be required to bring the connections into alignment. After commencement test and the initial pressure test, all bolts shall be rechecked for proper torque.

FIGURE A-5: Correct Stud & Nut Engagement

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TABLE A-14 FLANGE-BOLTING SIZE & REQUIRED TORQUE VALUES Flange Size Pressure Ring Gasket Stud & Nuts Required (in) Rating PSI Dia x Lgth (in) Torque Ft. Lbs. 2-1/16” 5,000 RX-24 7/8 x 6-1/2 319 2-1/16” 10,000 BX-152 3/4 x 5-1/2 200 3-1/8” 5,000 RX-35 1-1/8 x 7-3/4 686 3-1/16” 10,000 BX-154 1 x 7-1/4 474 3-1/16” 15,000 BX-154 1-1/8 x 8 686 4-1/16” 10,000 BX-155 1-1/8 x 8-1/2 686 4-1/16” 15,000 BX-155 1-3/8 x 9-3/4 1,281 7-1/16” 5,000 RX-46 1-3/8 x 11-1/4 1,281 7-1/16” 10,000 BX-156 1-1/2 x 11-3/4 1,677 7-1/16” 15,000 BX-156 1-1/2 x 13 1,677 11” 3,000 RX-53 1-3/8 x 10 1,281 11” 10,000 BX-158 1-3/4 x 15-1/4 2696 11” 15,000 BX-158 2 x 19-1/2 4061 13-5/8” 3,000 RX-57 1-3/8 x 10-3/4 976 13-5/8” 5,000 BX-160 1-5/8 x 12-3/4 2,146 13-5/8” 10,000 BX-159 1-7/8 x 17-3/4 3,332 13-5/8” 15,000 BX-159 2-1/4 x 21-1/4 5,822 18-3/4” 10,000 BX-164 2-1/4 x 22-3/4 5,822 18-3/4” 15,000 BX-164 3 x 26-3/4 12,654 20-3/4” 3,000 RX-74 2 x 15 4,061 21-1/4” 2,000 RX-73 1-5/8 x 12-1/4 1,635 26-3/4” 3,000 BX-168 2 x 17-1/2 4,061

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CHAPTER B: WCE SYSTEM CONFIGURATION TABLE OF CONTENTS 1.0

WCE EQUIPMENT SYSTEM CONFIGURATION 1.1

2.0

3.0

4.0

5.0

6.0

Pressure Rating of BOPE Systems

B-3

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

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

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

CLASS ‘A’ 3,000 psi BOP STACK 5.1

Usage

B-15

5.2

Class ‘A’ 3,000 psi BOP Stack Arrangement for Large Hole (Single Sized Drill Pipe)

B-15

5.3

Class ‘A’ 3,000 psi BOP Stack Arrangement for Smaller Hole (Single Sized Drill Pipe)

B-16

5.4

Class ‘A’ 3,000 psi BOP Stack Arrangement (Tapered Drill Pipe String)

B-17

CLASS ‘B’ 3,000 psi BOP STACK 6.1

Usage

B-17

6.2

Class ‘B’ 3,000 psi BOP Stack Arrangement

B-17

7.0

CLASS ‘C’ 3,000 psi BOP STACK

B-20

8.0

CLASS ‘D’ DIVERTER STACK

B-21

9.0

CLASS ‘I’ 2,000 psi WORKOVER STACK

10.0

9.1

Usage

B-22

9.2

Class ‘I’ 2,000 psi Stack Arrangement

B-22

CLASS ‘II’ 3,000 psi WORKOVER STACK 10.1 Usage

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10.2 Class ‘II’ 3,000 psi Stack Arrangement

11.0

12.0

13.0

14.0

15.0

CLASS ‘III’ 5,000 psi WORKOVER STACK 11.1 Usage

B-23

11.2 Class ‘III’ 5,000 psi Stack Arrangement

B-24

CLASS ‘IV’ 10,000 psi WORKOVER STACK 12.1 Usage

B-24

12.2 Class ‘IV’ 10,000 psi Stack Arrangement

B-24

CLASS ‘V’ 15,000 psi WORKOVER STACK 13.1 Usage

B-24

13.2 Class ‘IV’ 10,000 psi Stack Arrangement

B-24

SPECIAL WELL OPERATIONS BOP STACKS 14.1 BOP Equipment Requirements for Coil Tubing Operations

B-24

14.2 BOP Equipment Requirements for Snubbing

B-28

14.3 BOP Equipment Requirements for Electric Line Operations

B-31

CHOKE MANIFOLDS 15.1 15,000 PSI Working Pressure Choke Manifold

B-33

15.2 10,000 PSI Working Pressure Choke Manifold

B-36

15.3 5,000 PSI Working Pressure Choke Manifold

B-39

15.4 3,000 PSI Working Pressure Choke Manifold

B-42

15.5 Location

B-42

15.6 Choke Manifold Pressure Ratings

B-42

15.7 Piping Specifications

B-42

15.8 Choke Manifold Discharge and Flare Lines

B-43

15.9 Gas Buster Lines

B-44 B-3

TABLE B-1: WCE MASP Sizing

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1.0 WCE 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 Executive Director/ Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of Drilling or Workover Operations Managers and Superintendents. The Rig Foreman shall verify WCM compliant equipment is available and correctly installed. If not specified in this standard all WCE shall comply with the respective API Standards and Recommended Practices. The BOP equipment must be arranged to allow:       1.1

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. Pressure Rating of WCE Systems: The pressure rating of the WCE 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: TABLE B-1 WCE Equipment OIL WELL GAS WELL INJECTION WELL Pressure Rating MASP (in PSI) MASP (in PSI) MASP (in PSI) 3,000 PSI ≤ 2,550 ≤ 2,700 < 3000 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 table B-1. 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. Four cavity 10M and 15M BOP stacks drilling in 5M oil service can substitute blind or small pipe rams with permanent casing rams. 4-CAVITY, 15K STACK IN OIL DRILLING SERVICE SHALL BE CONFIGURED WITH: ANNULAR: TOP RAM: PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: BLIND RAMS, SMALL PIPE RAMS (IF TAPERED STRING) OR CASING RAMS (IF 5M OIL) BTM MASTER: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR.

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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" 10M or 15M flange with two (2) 3-1/16" 10M or 15M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" (minimum) 10M or 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 of a higher pressure rating than the wellhead, a double studded adapter (DSA) flange is required.

2.2.3

A flanged or studded double cavity 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/cross with fluid cushion blind flanges

The bottom outlet of the tee/cross will connect to the lower kill line. The other side of the tee/cross will have a flanged spacer spool followed by a second studded tee/cross. On each side of the second tee/cross 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 2202 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 a 3-1/16" 15M flanged spacer spool (as needed) a 3-1/16” 15M studded tees/cross with fluid cushion blind flanges (as needed) a 3-1/16” 15M flanged spacer spool a 3-1/16" 15M flanged manually operated gate valve attached directly to the studded tee/cross on the upper kill line.

NOTE: The lower (secondary) kill line is not to be used a primary circulating 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

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

a 4-1/16" 15M studded tee/cross with fluid cushion blind flanges

The bottom outlet of the tee/cross will connect to the lower choke line. The other side of the tee/cross 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 spool (as needed) a 4-1/16” 15M studded tee/cross with fluid cushion blind flanges a 4-1/16” 15M flanged spacer spool a 4-1/16" 15M flanged manually operated gate valve attached directly to the studded tee/cross on the upper choke line.

NOTES: All steel piping shall be made with 15M flanges, tees/crosses/block-tee elbows and 450 blocks with renewable fluid cushion blind flanges, and factory-manufactured 15M working pressure line. All crosses, tees and 450 blocks must have 15M renewable fluid cushion blind flanges installed on non-line outlets. (welded tees/crosses are not acceptable). Chicksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill or choke line. Coflex flexible line (refer to Chapter A, Section 2.0) may be used in combination with steel line for the choke or kill line. The lower (secondary) choke line is not to be used a primary circulating line. 2.2.6

A 15M flanged or studded double cavity 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.

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Figure B-1: Class 'A' 15,000 psi BOP Stack with Single Sized Drill Pipe Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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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:

Figure B-2: Class 'A' 15,000 psi BOP Stack with a Tapered String of Drill Pipe Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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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 MASP’s as stated in Table B-1. 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. Four cavity 10M and 15M BOP stacks drilling in 5M oil service can substitute blind or small pipe rams with permanent casing rams. 4-CAVITY, 10K STACK IN OIL DRILLING SERVICE SHALL BE CONFIGURED WITH: ANNULAR: TOP RAM: PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: BLIND RAMS, SMALL PIPE RAMS (IF TAPERED STRING) OR CASING RAMS (IF 5M OIL) BTM MASTER: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR.

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" 5M or 10M flange with two (2) 3-1/16" (minimum) 5M or 10M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" 5M or 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 DSA flange is required.

3.2.3

A flanged or studded double cavity 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/cross with fluid cushion blind flanges

The bottom outlet of the tee/cross will connect to the lower kill line. The other side of the tee/cross will have a flanged spacer spool and followed by another studded tee/cross. On each side of this tee/cross 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

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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 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 a 2-1/16" 10M flanged spacer spool a 2-1/16” 10M studded tee/cross with fluid cushion blind flanges (as needed) a 2-1/16” 10M flanged spacer spool a 2-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.

NOTE: The lower (secondary) kill line is not to be used a primary circulating 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/cross with fluid cushion blind flanges

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 a 4-1/16" 10M flanged spacer spool (as needed) a 4-1/16” 10M studded tees with fluid cushion companion flanges (as needed) a 4-1/16” 10M flanged spacer spool a 4-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper choke line.

NOTES: The lower (secondary) kill line is not to be used a primary circulating line. All steel piping shall be made with 10M flanges, tees/crosses/block-tee elbows and 450 blocks with renewable fluid cushion blind flanges, and factory-manufactured 10M working pressure line. All crosses, tees and 450 blocks must have 10M renewable fluid cushion blind flanges installed on non-line outlets. (welded tees/crosses are not acceptable). Chicksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, or choke line. Coflex line (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 cavity 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.

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Figure B-3: Class 'A' 10,000 psi BOP Stack with Single Sized Drill Pipe Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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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 Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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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 in accordance with MASP’s as stated in Table B-1. 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 line (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. NOTES: If the wellhead spool has a 5M top flange, then the side outlet valves shall be 5M. 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.

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Figure B-5: Class 'A' 5,000 and 3,000 psi BOP Stack with VBR’s Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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4.2.6

Kill Lines From the drilling cross side outlet on the kill line side, there shall be:       

a 4-1/16” X 2-1/16” 5M DSA (if needed) 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/cross with fluid cushion blind flange a 2-1/16” 5M flanged spacer spool a 2-1/16” 5M flanged tee/cross with fluid cushion blind flange (if needed)

On each side of the tee/cross there shall be a 2-1/16" 5M flanged gate valve and a 2-1/16" 5M flanged check valve. On the remote (emergency pump connection) 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. 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" 5M DSA a 2-1/16" 5M flanged manually operated gate valves a 2-1/16" 5M flanged hydraulic control gate valve a 2-1/16" 5M flanged spacer spool (if needed) a 2-1/16” 5M studded tee/cross with fluid cushion blind flanges (as needed) a 2-1/16" 5M flanged spacer spool (if needed) a 2-1/16" 5M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.

NOTE: The lower (secondary) kill line is not to be used a primary circulating line 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 line (Chapter A, Section 2.0) to a 3-1/8" 5M flanged manually operated gate valve at the choke manifold

NOTES: All steel piping shall be made with 5M flanges, tee/block-tee elbows and 450 blocks with fluid cushion blind flanges, and factory-made 5M working pressure line. All crosses, tees and 450 blocks must have 5M renewable fluid cushion blind flanges installed on non-line outlets. (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 line (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 or fixed pipe rams installed immediately below the annular. The master pipe ram must be a fixed ram. NOTES: 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" ram size). Additional information regarding the use of variable bore rams is provided in Chapter A, Section 1.4. Variable Bore Rams are not allowed in the Master Pipe Ram position (lowermost rams).

4.2.9

A 5M flanged bottom and studded top annular preventer will be installed on the top ram preventer.

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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.

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, typically 26-3/4”, 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 are in accordance with MASP’s as stated in Table B-1. 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 H 2 S, 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", 20-3/4” and 263/4" 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) 3-1/8" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 3-1/8" 3M gate valve with a 3-1/8" 3M blind flange. The other outlet shall have a manually operated 3-1/8" 3M flanged gate valve next to the wellhead and a hydraulic control 3-1/8" 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 2-1/16” 3M rated working pressure. Coflex line (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 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 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have minimum of two (2) 3-1/8" 3M side outlets.

5.2.5

A 3M flanged double ram preventer or two (2) single ram preventers shall be installed, with blind rams (2) and drill pipe rams (3).

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5.2.6

If required to cross over to the annular preventer, a double studded adapter flange (DSA) will be required on top of the upper preventer. If the bottom flange on the annular preventer matches the top flange of the previous ram preventer, a DSA is not necessary.

5.2.7

Kill Lines From the drilling cross side outlet on the kill line side, there shall be:       

a 3-1/8” X 2-1/16” 5M DSA (if needed) 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/cross with fluid cushion blind flange a 2-1/16” 5M flanged spacer spool a 2-1/16” 5M flanged tee/cross with fluid cushion blind flange (if needed)

On each side of the tee/cross there shall be a 2-1/16" 5M flanged gate valve and a 2-1/16" 5M flanged check valve. On the remote (emergency pump connection) 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" factory 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. 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" 5M DSA a 2-1/16" 5M flanged manually operated gate valves a 2-1/16" 5M flanged hydraulic control gate valve a 2-1/16" 5M flanged spacer spool (if needed) a 2-1/16” 5M studded tee/cross with fluid cushion blind flanges (as needed) a 2-1/16" 5M flanged spacer spool (if needed) a 2-1/16" 5M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.

NOTE: The lower (secondary) kill line is not to be used a primary circulating 5.2.8

Choke Lines On the choke line, from the drilling cross out, there shall be:   

a 3-1/8" 3M minimum flanged manually operated gate valve a 3-1/8" 3M minimum flanged hydraulic control gate valve a 3-1/8" 3M minimum steel flanged line or flexible line (Chapter A, Section 2.0) to a 3-1/8" 3M minimum flanged manually operated gate valve at the choke manifold

NOTE: All steel piping shall be made with 3M flanges, tee/block-tee elbows with fluid cushion blind flanges, and factory-made 3M working pressure line. All crosses and tees must have 3M renewable fluid cushion blind flanges installed on non-line outlets. (Welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the catwalk, land operation) are not acceptable. Flexible line (refer to Chapter A Section 2.0) may be used in combination with steel line for kill, emergency kill line, or choke line. 5.2.9 5.3

A 3M minimum flanged bottom and studded top annular preventer will be installed on the top ram preventer.

Class ‘A’ 3,000 psi BOP Stack Arrangement for Smaller Diameter Hole (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-5:

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5.4

5.3.1

A wellhead spool (13-3/8" landing base) with 13-5/8" 3,000 psi flange and two (2) 2-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 2-1/16" 3M gate valve with a 21/16" 3M blind flange. The other outlet shall have a manually operated 2-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 2-1/16" 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 2-1/16” 3M rated working pressure. Coflex flexible line (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 1502 WECO welded union (threaded connections are not acceptable) for connection to an emergency pump.

5.3.2

If the wellhead top flange is below ground level, a 13-5/8” 3M spacer spool may be required to raise the bottom flange of the BOP to (or above) ground level.

5.3.3

A 13-5/8” 3M flanged single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams.

5.3.4

A 13-5/8” 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have two (2) 3-1/16" 3M side outlets. The same arrangement on the kill and choke lines as for the Class ‘A’ 5,000 psi BOP stack (land operation) shall be used, as shown in Figure B-5.

5.3.5

Either two (2) 13-5/8" 3M flanged single ram preventers or a double ram preventer shall be installed, with blind rams or shear blind rams, see required applications in Section 1.7.4, (bottom) and drill pipe rams (top).

5.3.6

A 13-5/8" 3M flanged bottom with studded top annular preventer shall complete this stack.

5.3.7

Choke and kill lines shall be configured as per section 5.2 above.

Class ‘A’ 3,000 psi BOP Stack Arrangement for Tapered Drill Pipe String: The Class ‘A’ 3,000 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).

6.0

Class ‘B’ 3,000 psi BOP Stack

6.1

Usage: A Class ‘B’ 3,000 psi BOP stack (Figure B-6) shall be installed, as a minimum, on all development oil producers, water injectors, observation and water disposal wells. Class-B BOP equipment shall be 13-5/8” 3M, 20-3/4” 3M or 26-3/4, 3M with kill and choke line requirements as previously described in the Class ‘A’ 3M. The kill line shall be 3M and connected directly to the mud pumps or to the stand pipe manifold.

6.2

Class ‘B’ 3,000 psi BOP Stack Arrangement: All BOP equipment for these wells shall be arranged as described below. 6.2.1

A wellhead spool or casing head with a 3,000 psi flanged top and two (2) 2-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 2-1/16" 3M gate valve with a 2-1/16" 3M blind flange. The other outlet shall have a manually operated 2-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 2-1/16" 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 2-1/16” 3M rated working pressure. Coflex flexible line (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 1502 WECO welded union (threaded connections are not acceptable) for connection to an emergency pump.

6.2.2

If the wellhead top flange is below ground level, a 3M spacer spool may be required.

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6.2.3

A 3M psi single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams.

6.2.4

A 3M psi flanged drilling cross shall be installed on the single ram preventer. The drilling cross shall have two (2) 3-1/16" 3M side outlets.

6.2.5

A 3M psi single ram preventer shall be installed on the top of the drilling cross with blind rams.

6.2.6

A 3M psi flanged bottom with studded top annular preventer shall complete this stack.

6.2.7

Kill Lines From the drilling cross out on the kill line side, there shall be:     

a 2-1/16" 3M minimum flanged manually operated gate valve a 2-1/16" 3M minimum flanged hydraulic control gate valve a 2-1/16" 3M minimum flanged check valve a 2-1/16" 3M minimum flanged spacer spool a 2-1/16" 3M minimum tee/cross with fluid cushion flange

On the remote side, the kill line shall be 3M minimum 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 3M minimum and connected directly to the mud pumps or to the stand pipe manifold. 6.2.8

Choke Lines On the choke line, from the drilling cross out, there shall be:   

a 3-1/8" 3M minimum flanged manually operated gate valve a 3-1/8" 3M minimum flanged hydraulic control gate valve a 3-1/8" 3M minimum steel flanged line or flexible line (Chapter A, Section 2.0) to a 3-1/8" 3M minimum flanged manually operated gate valve at the choke manifold

NOTE: All steel piping shall be made with 3M flanges, tee/block-tee elbows with fluid cushion blind flanges, and factory-made 3M working pressure line. All crosses and tees must have 3M renewable fluid cushion blind flanges installed on non-line outlets. (Welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the catwalk, land operation) are not acceptable. Flexible line (refer to Chapter A Section 2.0) may be used in combination with steel line for kill line, emergency kill line, or choke line.

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Figure B-6: Class 'B' 3,000 psi BOP Stack Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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7.0

CLASS ‘C’ 3,000 PSI BOP STACK A Class ‘C’ 3,000 psi BOP stack (Figure B-7) shall be installed on all power water injector wells during the drilling and acidizing operations in the Arab-D hole section. The minimum equipment required will be an annular type preventer and a hydraulically operated dual ram preventer (or two single ram preventers) with blind rams located on top and pipe rams on bottom. Two (2) 3-1/16” 3M side outlets below the pipe rams are required, one for the kill line hook-up and other for the choke line. The kill line shall be adapted to 2-1/16” 3M and connected directly to the mud pumps or to the stand pipe manifold. A 10” 3M Ball Valve (with 9” bore) is located below the ram preventers and becomes part of the injection tree upon completion of the well.

Figure B-7: Class 'C' 3,000 psi BOP Stack

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8.0

CLASS ‘D’ DIVERTER STACK A Class ‘D’ Diverter stack (Figure B-8) will be installed on the conductor and/or next casing of all onshore exploration wells and development wells in the shallow gas area or areas where offset data indicates possible shallow gas. In addition, this diverter stack will also be required on the conductor of all offshore exploration wells and wells where offset data indicates possible shallow gas. The diverter lines shall consist of Schedule 40 steel piping. This line shall be securely anchored and terminate in the flare pit, 50’ beyond the reserve pit or overboard. Saudi Aramco requires two (2) 6-3/8 minimum ID, full bore valves and 8” lines. All lines must be as straight as possible with any turns using long radius sweep elbows to minimize erosion. Offshore, the lines must allow diversion to port and/or starboard. There shall be a Schedule 120, 2” weld X 2” EUE Nipple welded to the conductor casing with a 2” EUE threaded Ball Valve for cement returns and operational tie-in. Fabrication of the diverter lines, elbows and welding of the nipple to the conductor must be done using a WPS approved by the rig operations engineer. The emergency pump in connection shall be a 3-1/8” 2M flanged connection, located 90 degrees offset from the diverter lines (as noted in Figure B-8 below). The kill line shall be connected directly to the mud pumps or to the stand pipe manifold.

Figure B-8: Class ‘D’ Diverter BOP Stack NOTE: Some offshore rigs are fitted with a KFDJ type 49-1/2” Diverter System fixed to the rotary beams of the rig floor. This system, at the discretion of the relevant operations department, may be used in lieu of a 30” annular diverter system.

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WORKOVER BOP STACKS Maintaining control of a well during the completion and workover phases may be more complicated than well control in drilling operations. Additional complications may exist as, a) various types of workover fluids ranging from low-density diesel to high-density brine fluids may be used; b) interrelated activities may occur simultaneously, such as workovers on a platform with producing wells. Saudi Aramco has four (4) classes of BOP arrangements for workover operations. The workover program shall specify the Class BOP stack (not individual components) to be used.

9.0

CLASS ‘I’ 2,000 PSI WORKOVER STACK

9.1

Usage: This class of BOP Stack is used on water supply wells and shallow, low-pressure aquifer observation wells, where the operation to be performed on the well and/or space below the rig substructure precludes use of ram-type preventers. NOTE: This class of BOP stack with a working pressure of 2,000 psi is not defined in Table 1.1; any given 21-1/4” Annular is typically rated to 2,000 psi and it may be used on wells with a MASP of up to 1,600 psi.

9.2

Class ‘I’ 2,000 psi Workover BOP Stack Arrangement: 9.2.1

The minimum equipment required will be a Hydril, Cameron, or NOV Shaffer annular type preventer with a working pressure of 2,000 psi or greater. A 2” kill and/or fill-up line shall be connected to the landing base side outlet as shown in Figure B-10.

9.2.2

When sufficient space below the rig substructure is available, a Power Water Injection Tree (ball valve) shall be used below the annular, as shown in Figure B-9.

9.2.3

The annular preventer will be visually inspected and functionally tested prior to installation and pressure tested after installation using a cup-type tester set at a depth of approximately 60’. Test pressures, to be specified in the workover program, shall be greater than the MASP, but shall not exceed 80% of the rated casing burst.

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Figure B-9: Class 'I' Workover BOP Stack

10.0 CLASS ‘II’ 3000 PSI WORKOVER STACK 10.1

Usage: This class BOP stack is used on most onshore workovers to be performed on producing, water injection and reservoir observation wells. These wells are normally low-pressure and equipped with up to 3,000 psi WP wellhead equipment.

10.2

Class ‘II’ 3,000 psi Workover BOP Stack Arrangement: This BOP stack is identical to the Class ‘C’ Drilling stack as described in Section 7 above.

11.0 CLASS ‘III’ 5,000 PSI WORKOVER STACK 11.1

Usage: This class BOP is used on all offshore workovers with wellhead equipment rated to 3,000 or 5,000 psi and onshore workovers with wellhead equipment rated to up to 5,000 psi.

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11.2

Class ‘III’ 5,000 psi Workover BOP Stack Arrangement: This BOP stack is identical to the Class ‘A’ 5,000 psi Drilling stack as described in Section 4 and Figure B-5 above.

12.0 CLASS ‘IV’ 10,000 PSI WORKOVER STACK 12.1

Usage: This class BOP is used on all workovers with up to 10,000 psi WP wellhead equipment.

12.2

Class ‘IV’ 10,000 psi Workover BOP Stack Arrangement: The Class IV 10,000 psi workover stack is arranged the same as the Class ‘A’ 10,000 psi drilling stack. All BOP equipment in this stack shall be 11” (or larger) 10M rated working pressure, including the annular preventer. NOTE: The annular shall be 10,000 psi working pressure. All other equipment requirements are as previously discussed in Section 3.0.

13.0 CLASS ‘V’ 15,000 PSI WORKOVER STACK 13.1

Usage: This class BOP is used on all workovers with up to 15,000 psi WP wellhead equipment.

13.2

Class ‘V’ 15,000 psi Workover BOP Stack Arrangement: The Class V 15,000 psi workover stack is arranged the same as the Class ‘A’ 15,000 psi drilling stack. All BOP equipment in this stack shall be 11” (or larger to provide full opening to the tubing spool and production casing) 15M rated working pressure, except the annular preventer WHICH shall be 10,000 psi working pressure. All other equipment requirements are as previously discussed in Section 2.0.

14.0 SPECIAL WELL OPERATIONS BOP STACKS The following represents Drilling and Workover’s minimum BOP equipment requirements for coil tubing, snubbing, and wireline operations. In some cases, the service company’s internal policy may exceed these BOP requirements. 14.1

BOP Equipment Requirements for Coil Tubing Operations: BOP equipment requirements for low-pressure, high-pressure and critical well service coil tubing (CT) operations are shown in Figures B-10, B-11 and B-12, respectively. Selecting the BOP arrangement shall be based on the maximum anticipated operating or shut-in wellhead pressure. These arrangements are for standard CT operations and should be modified as needed for special or unusual applications. 14.1.1 Low-Pressure Coiled Tubing BOP Equipment Requirements: The low-pressure or standard arrangement (less than 5,000 psi WHP) includes 4 sets of rams: tubing rams on the bottom in the #1 position, slip type rams in the #2 position, cutter rams in the #3 position and blind rams on top in the #4 position. In addition, there is a flow cross with a valve installed below the cross. See Figure B-10.

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SIDE DOOR STRIPPER

SIDE DOOR SIDE DOOR STRIP DSA6 STRIPPER GATE VALVE BLIND SHEAR SHEAR

QUAD BOP BO QUAD ES46

SLIP PIPE

Figure B-10: Low Pressure Coil Tubing BOP Stack Low-pressure stacks shall comply with the following minimum requirements:          

All equipment shall meet or exceed NACE MR-01-75 and API Standards for well control Rated WP greater than the maximum anticipated well pressure Side-door stripper Minimum BOP configuration of blind, shear, slip, and pipe rams Kill line with minimum 2-1/16” flanged connection Flow cross with flanged outlets and double valves Ability to monitor wellhead pressure below the pipe rams with isolator Slip design that will minimize fatigue/deformation damage to the coil Slip rams capable of holding the pipe up to the yield point with maximum rated WP in a hang-off mode Accumulator shall be sized to operate all BOPE (close-open-close) at maximum rated WP

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14.1.2 High-Pressure (HP) and Critical Well Service (CWS) Coiled Tubing BOP Equipment Requirements: The High-Pressure arrangement (greater than 5,000 psi WHP) includes the same equipment as in the lowpressure arrangement, plus a combination BOP containing a second set shear/seal rams and a set of pipe/slip rams when flowing the well with coil tubing in the hole (i.e. treating or production logging). A second stripper is also required when treating or production logging. See Figure B-11.

SIDE DOOR STRIPPER

OVER/ UDOOR NDER SIDE STRIPPER DSU6

GATE VALVE GATE VALVE BLIND BLIND SHEAR

QQUAD UAD BOP ES46

SHEAR SLIP

SLIP

PIPE

PIPE

GATE VALVE GATE VALVE

SHEAR/SEAL DUAL COMBI BOP ES46

SHEAR/ SEAL DUAL COMBI PIPE/BOP SLIP

PIPE/SLIP

Figure B-11: High Pressure Coil Tubing BOP Stack

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The Critical Well Service arrangement (greater than 5,000 psi WHP) includes the same equipment as in the high-pressure arrangement, plus a Coil Tubing Safety Head. The lower master pipe rams on the Dual Combination BOP should be substituted for combination shear/seal and pipe/slip rams when flowing the well with coil tubing in the hole (i.e. treating or production logging). A second stripper is also required when treating or production logging. See Figure B-12.

SIDE DOOR STRIPPER

OVER/UNDER SIDE DOOR DSU6 STRIPPER

GATE VALVE GATE VALVE BLIND BLIND

QQUAD UAD

SHEAR SHEAR

BOP

ES46

SLIP SLIP

GATE VALVE GATE VALVE

PIPE

PIPE

SHEAR/SEAL DUAL COMBI BOP ES46

SHEAR/SEAL

DUAL PIPE/SLIP COMBI BOP

PIPE/SLIP

CT SAFETY HEAD Figure B-12: Critical Well Service Coil Tubing BOP Stack

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High-pressure and CWS stacks shall comply with the following minimum requirements:             14.2

All equipment comply with or exceed NACE STANDARD MR-01-75 and API Standards for well control Rated WP greater than the maximum anticipated well pressure Side-door stripper Second side-door or radial stripper is required if flowing well w/CT in hole Minimum BOP configuration of blind, shear, slip, pipe rams, and master pipe rams below flow cross Master pipe rams should be substituted for combination shear/seal and pipe/slip rams when flowing the well with CT in the hole Kill line with minimum 2-1/16” flanged connection Flow cross with flanged outlets and double valves Ability to monitor wellhead pressure below the pipe rams with isolator Slip design that will minimize fatigue/deformation damage Slip rams capable of holding the pipe up to the yield point with maximum rated WP in a hang-off mode Accumulator shall be sized to operate all BOPE (close-open-close) at maximum rated WP

BOP Equipment Requirements for Snubbing Operations: The stack arrangements in Figure B-13 and B-14 show basic set-ups for low-pressure and high-pressure snubbing operations. Selecting the BOP arrangement shall be based on the maximum anticipated operating or shut-in pressure. 14.2.1 Low-Pressure Snubbing BOP Equipment Requirements The low-pressure (less than 5000 psi WHP) or standard arrangement’s basic features are the #1 and #2 stripping rams, equalizing loop, safety, and blind rams. The primary rams are the #1 and #2 stripping rams. These rams are used in conjunction with the equalizing loop to strip the pipe into or out of the hole. The equalizing loop and vent line are used to bleed off the pressure. Note that the equalizing loop contains a fixed or positive choke to minimize the surge pressure when bleeding off the pressure. Each set of valves contains one manual and one remotely operated valve. Below the #2 rams is a set of safety or secondary rams to be used whenever either of the stripper rams begin to leak or fail. Below the safety rams is a set of blind rams to be used to shut the well in when pipe is out of the hole or landed in the hangar.

INTENTIONALLY LEFT BLANK

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Figure B-13, Low Pressure Snubbing Stack

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14.2.2 High-Pressure Snubbing BOP Equipment Requirements The high-pressure arrangement (greater than 5000 psi WHP) includes everything the standard arrangement has plus a second spool with dual outlets that contains a remotely operated choke, a set of shear blind rams, and a second set of safety rams. The shear blind rams are considered a third line of defence and are a last resort if primary control of the well is lost. In addition, a positive choke is added to the vent line to allow a slower bleed-off of pressure from the well.

Figure B-14 High Pressure Snubbing Stack

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14.3

BOP Arrangements for Electric Line Operations: The required BOP arrangement shall be determined by the electric line application (open-hole or cased hole) and maximum anticipated surface pressure during the operation. All BOP equipment shall comply with API 6A and NACE MR-01-75 (Latest Revision). 14.3.1 Open-Hole Electric Line BOP Requirements (Over-Balanced Condition) When open-hole logging an oil or gas well, an electric line BOP is not required, provided primary well control (hydrostatic pressure > formation pressure) can be maintained and confirmed. 14.3.2

Cased-Hole Electric Line BOP Requirements (Under-Balanced Condition) When perforating or logging under-balanced, an electric line BOP and lubricator are required with a wellhead adapter flange connected to the top of the test head or tree. Minimum electric line BOP requirements for various cased-hole pressure applications are summarized below. TABLE B-2 Cased-Hole Electric Line BOP Requirements: (Under-Balanced Condition) 7/32 –1/4” Line

Wells with Max. Expected WHP < 5,000 psi

Wells with Max. Expected WHP 5,000 to 10,000 psi

5,000 psi

10,000 psi

Not Acceptable

Not Acceptable

Required

Required

2

3

2500 F

3000 F

Tool Trap

Required

Required

Tool Catcher

Optional

Optional

Ball Check Valve

Required

Required

Remote Grease Injection Unit Stuffing Box with Hydraulic Operated Pack-Off

Required

Required

Required

Required

Working Pressure Manual BOP Hydraulic BOP Minimum Number of Rams Minimum Temperature Rating of Elastomer

A stuffing box (w/ hydraulic operated pack-off) is required in unperforated cased hole when running CBL, or similar logs, with + 1000 psi surface pressure while logging. An electric line BOP is optional in this situation. NOTE: Regardless of having a WL BOP on the well, an appropriate WL Cutting Tool should always on the rig floor while logging is in progress.

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Typical electric line rig-up for cased-hole operations:

Figure B-15 Electric Line BOP

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15.0 CHOKE MANIFOLDS All choke manifolds and piping shall meet Sour Service NACE MR-01-75 (Latest Revision) and API Specification 6A with the Hydraulic Chokes as per API 16C. Choke & Kill Manifold components shall be individually API monogrammed so as to allow component replacement based on individual OEM COC expiry date. Required specifications and applications for the 15,000 psi, 10,000 psi, 5,000 psi, and 3,000 psi choke manifolds are stated in the following information. 15.1

15,000 psi Working Pressure Choke Manifold:

FIGURE B-16: 4-1/16” 15M Onshore Choke Manifold Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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_________________________________________________________ 4-1/16” 15M CHOKE MANIFOLD

All 15M psi choke manifolds shall comply with the following minimum requirements: Gate valves, check valves, chokes, spools, tees, crosses and buffer chamber shall be individually monogrammed to API Specification 6A or 16C and made to the following; Manual/Hydraulic Gate Valves and Manual Chokes:          

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PR-2 (≥10,000 psi) MR-DD (or better) TR-X suitable for 0-350o F service (10,000 psi working pressure or higher) All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Forged bodies and bonnets Gates and seats shall be hard-faced using Praxair LW-45 or Bodycote CW-15 Alloy 625 inlaid ring grooves

Hydraulic Drilling Chokes:       

Monogrammed to API Specification 6A or 16C PSL-2 (or better) (With PSL-3 Gas Test) PR-2 (≥10,000 psi) MR-DD (or better) TR-X Suitable for 0-350o F service (10,000 psi working pressure or higher) Forged bodies and bonnets Alloy 625 inlaid ring grooves

Check Valve:         

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PR-2 (≥10,000 psi) MR-DD (or better) TR-X suitable for 0-350o 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. Alloy 625 inlaid ring grooves



All flanges and other components shall be monogrammed to API Spec-6A

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FIGURE B-17: 4-1/16” 15M Offshore Choke Manifold Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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15.2

10,000 psi Working Pressure Choke Manifold:

FIGURE B-18: 4-1/16” 10M Choke Manifold Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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_________________________________________________________ 4-1/16” 10M CHOKE MANIFOLD

All 10M psi (& higher) choke manifolds shall comply with the following minimum requirements: Gate valves, check valves, chokes, spools, tees, crosses and buffer chamber shall be individually monogrammed to API Specification 6A or 16C and made to the following; Manual/Hydraulic Gate Valves and Manual Chokes:          

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PR-2 (≥10,000 psi) MR-DD (or better) TR-X suitable for 0-350o F service (10,000 psi working pressure or higher) All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Forged bodies and bonnets Gates and seats shall be hard-faced using Praxair LW-45 or Bodycote CW-15 Alloy 625 inlaid ring grooves

Hydraulic Drilling Chokes:       

Monogrammed to API Specification 6A or 16C PSL-2 (or better) (With PSL-3 Gas Test) PR-2 (≥10,000 psi) MR-DD (or better) TR-X Suitable for 0-350o F service (10,000 psi working pressure or higher) Forged bodies and bonnets Alloy 625 inlaid ring grooves

Check Valve:         

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PR-2 (≥10,000 psi) MR-DD (or better) TR-X suitable for 0-350o 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. Alloy 625 inlaid ring grooves



All flanges and other components shall be monogrammed to API Spec-6A

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FIGURE B-19: 4-1/16” 10M Offshore Choke Manifold Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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15.3

5,000 psi Working Pressure Choke Manifold: Choke manifold configurations for 5,000 psi onshore and offshore applications are shown in Figure B-20 and Figure B-21 respectively. Gate valves, check valves, chokes, spools, tees, crosses and buffer chamber shall be individually monogrammed to API Specification 6A or 16C.

FIGURE B-20: Onshore 3-1/8” 5M Choke Manifold

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FIGURE B-21: Offshore 3-1/8” 5M Choke Manifold Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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_________________________________________________________ 3-1/8” 5M CHOKE MANIFOLD

All 5M psi choke manifolds shall comply with the following minimum requirements: Gate valves, check valves, chokes, spools, tees, crosses and buffer chamber shall be individually monogrammed to API Specification 6A or 16C and made to the following; Manual/Hydraulic Gate Valves and Manual Chokes:          

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) All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Forged bodies and bonnets Gates and seats shall be hard-faced using Praxair LW-45 or Bodycote CW-15 Alloy 625 inlaid ring grooves

Hydraulic Drilling Chokes:       

Monogrammed to API Specification 6A or 16C 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) Forged bodies and bonnets Alloy 625 inlaid ring grooves

Check Valve:          

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) Forged bodies and bonnets Top entry valves only, no bottom body penetrations. Metal to metal seal valves only. Alloy 625 inlaid ring grooves All flanges and other components shall be monogrammed to API Spec-6A

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15.4

3,000 psi Working Pressure Choke Manifold: 3-1/8” 3M CHOKE MANIFOLD

All 3M psi choke manifolds will be configured the same as the 5M and shall comply with the following minimum requirements: Gate valves, check valves, chokes, spools, tees, crosses and buffer chamber shall be individually monogrammed to API Specification 6A or 16C and made to the following; Manual/Hydraulic Gate Valves and Manual Chokes:          

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) All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Forged bodies and bonnets Gates and seats shall be hard-faced using Praxair LW-45 or Bodycote CW-15 Alloy 625 inlaid ring grooves

Hydraulic Drilling Chokes:       

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) Forged bodies and bonnets Alloy 625 inlaid ring grooves

Check Valve:           15.5

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) Forged bodies and bonnets Top entry valves only, no bottom body penetrations. Metal to metal seal valves only. Alloy 625 inlaid ring grooves All flanges and other components shall be monogrammed to API Spec-6A

Location: The choke manifold shall be skid mounted on land rig (rig floor mounted on offshore rigs) and located in an accessible area.

15.6

Choke Manifold Pressure Ratings: The complete choke manifold, chokes, valves and piping will be full working pressure of the BOP stack through the block valves down-stream of the chokes.

15.7

Piping Specifications: The piping from the BOP stack to the choke manifold shall have the same working pressure (or greater) as the BOP stack. All piping shall meet Sour Service NACE MR-01-75 (Latest Revision) and API Specification 6A.

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Choke and Kill lines for 3M – 15M applications shall either be steel pipe or flexible line (as specified in Chapter A, Section 2.0), or combination of flexible line and steel pipe. All flexible line shall be monogrammed to API Specification 16C, and all end connections monogrammed to API Specification 6A. All fabricated steel piping shall be as straight as possible, with targeted or block-tee elbows at turns. All tees must be targeted with renewable blind flanges (welded tees are not acceptable). All choke line and manifold connections shall be flanged, welded, integral, or hubbed, Chicksans and Weco connections are not acceptable. 15.8

Choke Manifold Discharge: For onshore oil and all gas drilling, provisions shall be made for the discharge from the choke manifold to be selectively diverted to: 15.8.1 Flare Lines Two (2) 3-1/2”, 9.3 #/ft., J-55, EUE flare lines, each approximately 400 feet in length, shall be required for onshore oil wells. Lines shall be tested to 1200 psi. Four (4) 4-1/2”, 26#/ft., J-55, LTC gas flare lines and one (1) 3-1/2”, 9.3#/ft., EUE liquid flare line, each 1000 feet in length, shall be required for onshore gas wells. Lines shall be tested to 1200 psi. NOTE: THE USE OF DRILL PIPE FOR FLARE LINES IS PROHIBITED. 15.8.1.1

One (1) each Flare Control Ignition Station located at choke manifold area, complete with one (1) each igniter panel.

15.8.1.2

Two (2) each diesel drip system for back-up flare ignition at flare pit will be required.

15.8.1.3

On selected well sites a third party oil / gas separator with a vertical flare stack will be required for well control.

An alternate flare pit and flare line will be rigged-up on deep gas wells (Figure B-23). This emergency flare pit will be used in well kill operations if the main flare pit cannot be utilized due to change in wind direction. Electronic flare ignition sources shall be positioned in the main flare pit, alternate flare pit, and gas buster flare pit. 15.8.2 The following lines are to be positioned at an appropriate central aft point on the drilling / workover unit and run to starboard and port sides with interconnecting piping (Ref: Chapter A, 3.11 and 3.12) to the flare booms. Listed below are the minimum piping requirements: One (4”) Gas line, Schedule -160, ASTM-106 B black pipe, H2S service manufactured and processed in accordance w / NACE MR-01-75 and ANSI B.31.3. Including manifold to divert flow to starboard or port side. Both lines must have a permanent/removable 3,000 psi WP Gate Valve (Gate Valve Specification to be the same as choke manifold valves) flanged with no hammer unions. Note: a) Onshore flare lines should be as straight as possible and fitted with TARGETED OR BLOCK –TEE ELBOWS AT TURNS. Lines to be pressure tested to 1200 psi after rig-up and prior to any flow test. b) All lines 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.

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FIGURE B-23: Deep Gas Flare Line Layout 15.9

Gas Buster Lines: There should be a bypass line up-stream of the gas buster directly to the flare line and a valve on the gas buster inlet line to protect the separator from high pressure. The mud discharge line from the gas buster 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 gas buster. One (1) 8” flanged/clamped steel vent line from the gas buster to at least 100’ beyond the far edge of the reserve pit shall be required for onshore oil wells. Two (2) 8” flanged/clamped steel vent line, from the gas buster to at least 100’ beyond the far edge of the reserve pit shall be required for onshore gas wells. The flare pit shall be positioned away from the reserve/waste pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.

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CHAPTER C: MAINTENANCE, TESTING AND CERTIFICATION REQUIREMENTS TABLE OF CONTENTS 1.0

MAINTENANCE OF BLOWOUT PREVENTION EQUIPMENT

C-3

2.0

GENERAL MAINTENANCE REQUIREMENTS

C-3

3.0

TESTING OF BLOWOUT PREVENTION EQUIPMENT

4.0

3.1

General Pressure Testing Requirements (Test Frequency)

C-6

3.2

Specific Requirements for Class ‘A’ 15,000 psi BOP Stack

C-8

3.3

Specific Requirements for Class ‘A’ 10,000 psi BOP Stack

C-9

3.4

Specific Requirements for Class ‘A’ 5,000 psi BOP Stack

C-10

3.5

Specific Requirements for Class ‘A’ 3,000 psi BOP Stack

C-11

3.6

Specific Requirements for Class ‘B’ 3,000 psi BOP Stack

C-11

3.7

Specific Requirements for Class ‘C’ or ‘II’ Workover Stack

C-12

3.8

Specific Requirements for Class ‘D’ Diverter Stack

C-13

PRESSURE TESTING PROCEDURE 4.1

Function Testing and Flow Testing

C-13

4.2

Fill the Stack with Water

C-13

4.3

Casing Test (if required)

C-14

4.4

Blind Rams (if required)

C-15

4.5

Annular Preventer

C-16

4.6

Upper Pipe Rams

C-17

4.7

Positive Sealing Chokes

C-17

4.8

Choke Manifold (continued)

C-18

4.9

Choke Manifold (continued)

C-19

4.10 Choke Manifold (continued)

C-20

4.11 Choke Line HCR Valve

C-21

4.12 Choke and Kill Line Manual Valves

C-22

4.13 Master Pipe Rams

C-23

4.14 Small Pipe Rams

C-24

4.15 Kelly, Surface Circulating Equipment, and Safety Valves

C-25

4.16 Wellhead Valves

C-26

5.0

ACCUMULATOR TESTING

C-26

6.0

HANG-OFF LIMITATIONS WHILE TESTING

C-28

7.0

TEST PRESSURE REQUIREMENTS FOR CASING RAMS

C-28

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8.0

CERTIFICATION AND RE-CERTIFICATION REQUIREMENTS 8.1

Equipment Recertification

C-28

8.2

Accumulator Control Unit

C-30

TABLE C-1: Ram Hang-Off Limits

C-28

TABLE C-2: WCE Recertification Intervals

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1.0

MAINTENANCE, TESTING AND CERTIFICATION OF BLOWOUT PREVENTION EQUIPMENT

This Chapter of the Well Control Manual sets forth the maintenance, testing and certification requirements required for Saudi Aramco BOP equipment. These policies (as well as the equipment standards and procedures throughout this well control manual) are considered mandatory. Variations or deviations from these requirements require endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these requirements shall be the responsibility of the Saudi Aramco Drilling Foreman (or Liaison-man) as directed by the Drilling Manager and Drilling Superintendent.

2.0

GENERAL MAINTENANCE REQUIREMENTS

Blowout prevention equipment is emergency equipment and must be maintained in fit for purpose working condition at all times. The Saudi Aramco Drilling Foreman is best positioned to ensure Saudi Aramco is provided with equipment that meets Saudi Aramco operational requirements and equipment specifications by being an active participant in the maintenance requirements of the well control equipment. Several maintenance items should be verified on a daily basis by the Saudi Aramco Drilling Foreman. The following represent items the Foreman is responsible for reviewing via the Driller’s pre-tour checklist or by personal observation: 2.1

Examine the fluid level in the accumulator. Make sure it is at the proper level and proper pressures are indicated on the accumulator, manifold, and annular pressure gauges.

2.2

Verify the BOP control lines are arranged to prevent damage by trucks or dropped tools.

2.3

Confirm the preventer controls are either in their proper opened or closed position (not neutral) and there are no visible leaks.

2.4

Assure the preventer stack is well guyed so that vibrations are minimized while drilling.

2.5

All preventers must be operated at least each time a trip is made (with the exception of the SBR’s). Alternate trip closures between the remote stations and the accumulator. The annular preventer does not have to be operated to complete shut-off. Do not close the pipe rams on open hole. SBR’s are not to be used as a hole cover.

2.6

The emergency kill line and choke/kill lines shall be washed out as required to prevent mud solids settling and/or immediately following any LCM operations. Clear water should be used to flush and fill the lines (except in extremely cold weather, where diesel or glycol should be used).

2.7

DO NOT circulate green cement through the preventer stack or choke manifold. Always thoroughly flush with water any item of blowout prevention or well control equipment, which has come in contact with green cement and verify the equipment is clear of any debris prior to the next nipple-up. NOTE: This requirement includes the wellhead annulus valves. If green cement is pumped through these they must be flushed well with fresh water to ensure that they will be operable.

2.8

Ensure the rig is centred over the well to reduce drill string and BOP equipment contact and abrasion.

2.9

Do not use the kill line as a fill-up line during trips.

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2.10

If possible, install the ram preventers so that the ram doors are positioned above and shield the valves installed on the casing head below.

2.11

All rigs shall maintain a logbook of BOP schematics detailing the components installed in each ram cavity. The logbooks shall contain the part number, description and installation date of ram blocks, top seals, ram or annular packers and bonnet/door seals. To be witnessed and co-signed by the Contract Toolpusher and Saudi Aramco Drilling Foreman (or Liaison-man).

2.12

Only non-expired OEM parts are acceptable when repairing or redressing the BOPE. Furthermore, only OEM approved high-temperature lubricant is acceptable for valve maintenance.

2.13

At least one spare set of ram seals (top seals and ram packers) for each ram size of casing, tubing or drill pipe, as well as ram BOP bonnet seals, must be on the rig site. All elastomer seals shall be sealed in the OEM packaging, stored in climate controlled environment, protected from UV. There is no requirement for annular BOP packer to be stored at the rig.

2.14

Ram blocks should not be dressed until ready to use.

2.15

All BOP elastomer goods shall be kept in a cool place and remain in the original packaging with manufacturer stated expiration dates.

2.16

Preventer assemblies shall be dismantled (nippled-down) and open bonnets between wells to inspect for internal corrosion, erosion or debris and to check flange bolts.

2.17

Manufacturer‘s installation, operation, and maintenance (IOM) manuals should be available on the rig for all well control equipment installed on the rig.

2.18

New ring gaskets shall be installed on every nipple-up and at every connection nippled down, which has been parted. Ring gaskets shall never be reused.

2.19

Closure bolting studs and nuts for all end and side outlet connections shall be the correct size for the flange or connection. Alloy steel and carbon steel bolting shall meet all the requirements of API 6A and 16A for Land and Offshore Surface service Pressure Controlling/Containing, API 20E BSL-2 minimum and API 6A (for material class and mechanical testing) for NON-EXPOSED BOLTING. The bolts must be marked as required in API 20E, section 8.2 for BSL-2. Field fabricated studs, saw or flame cut, are not permitted. Bolting that attaches the shear ram blade to the ram block shall conform to:   

The requirements of API 20E BSL-3 or API 20F BSL3 and API 6A as appropriate for the material type. Manufacturer’s written specification and requirements for the chemical composition and mechanical properties. Shear ram blades, shear ram blocks, and blade retention bolts shall be inspected annually by visual inspection and surface NDE. The inspection results shall be verified against the manufacturer’s acceptance criteria.

Studs and nuts should be checked for proper size and grade. Using the appropriate lubricant, torque should be applied in a crisscross manner to the flange studs. All bolts should then be re-checked for the proper torque as prescribed in API Specification 6A. Bolt sizes 1-7/8” and larger require make-up using hydraulic torque wrenches. Torque values shall be in accordance with API-6A, also detailed in Chapter A, Table A-12 of this manual.

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2.20

Field welding shall not be performed on any BOP’s or associated well control equipment. All repairs to BOP equipment must be performed at an OEM facility, or their Licensee repair facility. OEM repairs and recertification may be completed outside of Saudi Arabia if necessary.

2.21

A Maintenance Log for each item of WCE equipment shall be maintained. This log shall include, at a minimum, records of all service and inspections performed on the WCE, serial numbers for each WCE item and expiration date of all elastomers exposed to wellbore fluid. The log will travel with the Contractor-owned equipment and shall be kept in the Saudi Aramco DERU facility for Saudi Aramco-owned equipment.

2.22

API Monogram and Markings: Saudi Aramco prefers that all WCE in service within Saudi Aramco D&WO Operations carry an API Monogram. Newly purchased/manufactured WCE, after release of WCE 6th Edition as confirmed by the Original Equipment Manufacturer (OEM) Certificate of Conformance (COC), will be required to carry an API Monogram. All WCE markings including; monogram (if applicable), serial number, part number, size, pressure rating, etc. MUST be clearly visible through the painted coating of the equipment. Care should be taken to preserve markings on the equipment nameplate, flange or body to prevent it being obliterated or destroyed during handling, maintenance, repair and use. Additionally, documentation and COC must be available at the rig site reflecting the full equipment details; monogram (if applicable), serial number, part number, size, pressure rating, etc.

2.23

A full OEM certification or recertification of the WCE, must be performed at the start of new or renewed contract. Thereafter OEM recertification will be as stated below. SEE CHAPTER C, SECTION 8.

2.24

All WCE ≤3,000 psi: ≤3,000 psi, regardless of gas or oil service will be 5-year recertification.

2.25

Gas & Offshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Gas or Offshore Oil service will be 3-year recertification and will retain the balance of current 3-year certification if moving to Onshore Oil service. EXAMPLE: A 13-5/8”, 10K BOP used in Gas or Offshore Oil for 1 year then transferred to Onshore Oil service will retain the remaining 2 years validity of the COC. OEM recertification would be required within the following 2 years. If remaining in Onshore Oil service, the new equipment COC would be valid for 5 years.

2.26

Onshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Onshore Oil service will be 5-year recertification. However, if ≥5,000 WCE has been in Onshore Oil service for 3 years, it cannot be transferred to Gas or Offshore Oil and retain the remaining 2-year validity of the COC . EXAMPLE: A 13-5/8”, 10K BOP used in Onshore Oil service for 2-years then transferred to Gas or Offshore Oil will not retain the remaining 3 years COC validity. The remaining validity in this example would be 1 year because of the transfer. OEM recertification would be required within the following 1 year. If remaining in Gas or Offshore Oil, the new equipment COC would be valid for 3 years. 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.

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3.0

2.27

Accumulator bottles must have hydrostatic pressure testing completed every 5 years in accordance with 49 CFR 180.209 - Requirements for Requalification of Specification Cylinders, Subpart C, Section 180.209.

2.28

THE BOP SHOULD HAVE THE BONNETS OPENED, CAVITIES AND OTHER AREAS CLEANED, AND VISUALLY INSPECTED AFTER EVERY RIG MOVE OR 90 DAYS, WHICHEVER IS LESS, INCLUDING SERVICING THE MANUAL RAM-LOCK SCREWS AND VISUALLY INSPECTING THE SHEAR RAMS. After visual inspection the cavities should be fully coated with lubricant to protect from environmental conditions.

2.29

Elastomers having long-term exposure to wellbore fluids shall be changed at a maximum of every 12 months, unless visual inspection requires changing earlier. However, it is acceptable to use seal elements for 30” annulars up to 36 months (provided inspections of the packer element condition are satisfactory, properly documented, and the expiration date of the elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and smaller) shall be replaced no later than every 12 months, as per policy.

2.30

All BOP equipment must have documentation of last inspection and certification. Documents and Certification.

2.31

Saudi Aramco owned WCE will be maintained and located at the Saudi Aramco Drilling & Workover Services Department, Drilling Equipment Repair Unit (DERU) Facility. The DERU facility, in line with recognized industry best practices for the repair and or maintenance of WCE, is required to maintain a QA/QC Program qualified to the latest ISO 9001 or API-Q2.

TESTING OF BLOWOUT PREVENTION EQUIPMENT The objective of BOP equipment testing is to eliminate all leaks and to determine the equipment reliability in the event of unplanned formation pressure influx. This is accomplished by verifying:    3.1

Specific functions are operationally ready Pressure integrity of installed BOP equipment Compatibility between control system and BOP equipment General Pressure Testing Requirements All BOP equipment pressure tests shall be conducted in accordance with the following guidelines. Test Frequency 3.1.1

BOP equipment (including blind rams and shear blind rams) shall be pressure tested as follows:  

Initial installation Before drilling out for each string of casing, i.e. 34”, 28”, 22”, 16”, 12” 8-3/8” and 5-7/8” for Gas and 22”, 17-1/2”, 12-1/4”, 8-1/2” and 6-1/8” for Oil.  Following the disconnection or repair of any wellbore pressure seal in the wellhead/BOP stack (limited to the affected components only).

NOTE: When rams are changed, the casing and/or tubing Rams shall be pressure tested with a test plug and casing/tubing joint to 80% of the pipe collapse or the rated working pressure of the BOP (whichever is less). The annular preventer shall be tested per sections; 3.2, 3.3, 3.4 and 3.5.

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

Working Pressure: 5,000 psi and lower; Test a maximum of every 21 days (no extensions). Rig crews must be alerted when pressure test operations are underway. Only necessary personnel shall remain in the test area.



Working Pressure: 10,000 psi and higher; Test frequency will be every 21 days above the Base Jilh Dolomite (BJD) casing point and every 14 days below BJD casing point A maximum 2 day extension is allowed with Superintendent written approval. Rig crews must be alerted when pressure test operations are underway. Only necessary personnel shall remain in the test area.

3.1.2

All tests shall be performed using clean water. All lines and equipment must be flushed with clean water prior to testing.

3.1.3

When a gas well is being flow tested, the test equipment (manifolds, lines, etc.) must first be tested with nitrogen.

3.1.4

The low-pressure test of each piece of BOP equipment shall be conducted at a pressure of 250-300 psi.

3.1.5

The high-pressure test is specified in Chapter B by Class of BOP.

3.1.6

The low-pressure test shall be performed first. Do not test to the high- pressure and then bleed down to the low pressure. The higher pressure could initiate a seal after the pressure is lowered and thereby misrepresent the low-pressure test. Perform the low pressure test then bleed the test low test pressure to zero before conducting the high pressure test.

3.1.7

All valves located downstream of the valve being tested shall be placed in the OPEN position.

3.1.8

OPEN casing valves to the atmosphere when using a test plug to test the BOP stack to prevent possible leaks from rupturing the casing.

3.1.9

OPEN annular valves when testing to prevent pack-off leaks from pressuring up outer casing strings.

3.1.10 Vent the cup tester through the drillpipe when testing the upper 60 feet of casing to prevent possible leaks from rupturing the casing or applying pressure to the open hole. 3.1.11 Test all valves on the wellhead individually to their rated working pressure on installation (using a VR plug) and to 80% of casing burst on subsequent pressure tests, with a cup tester at located + 90’. 3.1.12 Casing rams shall be tested to the maximum anticipated surface pressure (refer to Section C, 6.0 for specific test pressures), with a joint of casing connected to a test plug with appropriate cross-over. 3.1.13 Variable Bore Rams (VBR’s) 3-1/2” – 5-7/8”, shall be tested with all sizes of pipe in use, excluding drill collars and bottom-hole tools. 3.1.14 All pressure tests must be conducted and witnessed by an authorized, qualified person with a minimum duration of ten (10) minutes AFTER PRESSURE STABILIZATION. Acceptance is no visible leaks or observable pressure decline over the hold period.

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3.1.15 Only authorized personnel shall go in the test area to inspect for leaks when the equipment is under pressure. 3.1.16 Connection tightening or equipment repair work shall be done only after pressure has been released and confirmed to zero psi, and all parties have agreed that there is no possibility of trapped pressure. 3.1.17 The BOPE flange bolt torque must be checked after every other BOP test. This will help prevent leaks from the flanged connections in the BOP stack. 3.1.18 A pressure test is required after replacing the annular packer, installation of casing rams or tubing rams. This test is limited to the components affected by the disconnection of the pressure containment seal. The bonnet seals and rams shall be tested using a test joint connected to a test plug, or cup tester, with appropriate crossover. 3.1.19 The initial pressure test performed on hydraulic chambers of annular preventers should be at least 1,500 psi. Initial pressure tests on hydraulic chambers of rams and hydraulically operated valves should be to the maximum operating pressure recommended by the manufacturer. Test should be run on both the opening and closing chambers. Subsequent pressure tests on hydraulic chambers should be upon re-installation. 3.1.20 All pressure tests shall be conducted with a test pump. Avoid the use of rig mud pumps for pressure testing. Cement units are acceptable. 3.1.21 All test results must be documented on a pressure chart, with the following information,     

Date of Test Well Name Driller Toolpusher Saudi Aramco Representative

3.1.22 COMMENCEMENT TEST: Test stumps are an acceptable method for pre-nipple up pressure testing the fully assembled BOP stack at the rig site. Test pressure shall be 100% of the BOP rated working pressure. The bottom connection (and any other connection not tested) must be tested with a test plug upon nippleup/installation of the BOP stack. 3.2 Specific Pressure Testing Requirements for Class ‘A’ 15M BOP Stack 3.2.1

The initial WCE pressure test shall be conducted after equipment installation on the well. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.2.2

For all gas wells, subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.2.3

Test frequency will be every 21 days above the Base Jilh Dolomite (BJD) casing point and every 14 days below BJD casing point.

3.2.4

The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure.

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3.2.5

All pressure tests, excluding casing tests, must be done with a test plug, due to the minimum yield strength (burst rating) of the 13-3/8” 72# and 9-5/8” 53.5# or 58.4# casing. Test plugs must be checked to insure the test plug is of the same manufacture and model as the wellhead where it is to be installed. (i.e. Cameron to Cameron, GE Gray to GE Gray, FMC to FMC and GE Wood Group to GE Wood Group.) The test plug Tong Neck must be checked to insure that the O.D is smaller than the minimum I.D. of the wellhead.

3.2.6

The initial high-pressure test of the upper/lower kelly cocks, inside BOP, and safety valves shall be conducted to their rated working pressure. Subsequent tests shall be tested to same as the BOP equipment, but not to exceed their rated working pressure.

3.2.7

Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested to the system working pressure, typically 5,000 or 7,500 psi.

3.2.8

The initial pressure test on the closing unit valves, manifold, gauges, and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

3.2.9

At nipple up, the casing shall be tested to 80% of burst rating.

3.2.10 The casing string in use shall be tested with a cup tester to 80% burst rating every 14 days (along with the scheduled BOP test). This will provide a pressure test of the casing valves in addition to verifying casing integrity. 3.3 Specific Pressure Testing Requirements for Class ‘A’ 10M BOP Stack 3.3.1

The initial WCE pressure test shall be conducted after equipment installation on the well. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.3.2

For all gas wells, subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.3.3

Delineation using MLS: If MLS rated working pressure is below that of the wellhead, test pressure will be de-rated to that of the MLC.

3.3.4

Test frequency will be every 21 days above the Base Jilh Dolomite (BJD) casing point and every 14 days below BJD casing point.

3.3.5

The pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure.

3.3.6

All pressure tests, excluding casing tests, must be done with a test plug, due to the minimum yield strength (burst rating) of the 13-3/8” 72# and 9-5/8” 53.5# or 58.4# casing. Test plugs must be checked to insure the test plug is of the same manufacture and model as the wellhead where it is to be installed. (i.e. Cameron to Cameron, Gray to Gray, FMC to FMC and Wood Group to Wood Group.) The test plug Tong Neck must be checked to insure that the O.D is smaller than the minimum I.D. of the wellhead.

3.3.7

The initial high-pressure test of the upper/lower kelly cocks, inside BOP, and safety valves shall be conducted to their rated working pressure. Subsequent tests shall be tested to same as the BOP equipment, but not to exceed their rated working pressure.

3.3.8

Subsequent pressure test(s) shall be conducted at the same pressure as the BOP.

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3.3.9

Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested to the system working pressure, typically 5,000 or 7,500 psi.

3.3.10 The initial pressure test on the closing unit valves, manifold, gauges, and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit. 3.3.11 At nipple up, the casing shall be tested to 80% of burst rating. 3.3.12 The casing string in use shall be tested with a cup tester to 80% burst rating every 14 days (along with the scheduled BOP test). This will provide a pressure test of the casing valves in addition to verifying casing integrity. 3.4 Specific Pressure Testing Requirements for Class ‘A’ 5M BOP Stack 3.4.2

The initial WCE pressure test shall be conducted after equipment installation on the well. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.4.3

Subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.4.4

Test frequency will be every 21 days.

3.4.5

The pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure. If 5M BOP is installed on 3M wellhead, test pressure will be 100% of wellhead rated working pressure. NOTE: A cup tester may be used if the high-pressure test does not exceed 80% of the casing burst rating.

3.4.6

The casing cup tester must be the appropriate size/weight for the application. When using this tester, care must be taken that the total load applied to the drill string (cup area times test pressure, plus the weight of the suspended drill string) does not exceed the string’s tensile limit.

3.4.7

The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe, vibrator hose, and piping to pumps shall be tested to same high-pressure tests (initial and subsequent), as the BOP equipment, but not to exceed their rated working pressure.

3.4.8

The initial pressure test on the manifold and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

3.4.9

At nipple up, the casing shall be tested to 80% of burst rating.

3.4.10 The casing string in use shall be tested with a cup tester to 80% burst rating every 14 days (along with the scheduled BOP test). This will provide a pressure test of the casing valves in addition to verifying casing integrity. NOTE: BOP equipment may have a higher working pressure than required, due to rig equipment availability. The high-pressure test requirement in these situations shall be site-specific (limited by the WP rating of wellhead).

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3.5

Specific Pressure Testing Requirements for Class ‘A’ 3M BOP Stack 3.5.1

The initial WCE pressure test shall be conducted after equipment installation on the well. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.5.2

Subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.5.3

The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 2100 psi (70% of the rated working pressure). NOTE: A cup tester may be used if the high-pressure test does not exceed 80% of the casing burst rating.

3.5.4

The casing cup tester must be the appropriate size/weight for the application. When using this tester, care must be taken that the total load applied to the drill string (cup area times test pressure, plus the weight of the suspended drill string) does not exceed the string’s tensile limit.

3.5.5

Test plugs must be checked to insure the plug fits the casing head.

3.5.6

The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe, vibrator hose, and piping to pumps shall be tested to same high-pressure tests (initial and subsequent), as the BOP equipment, but not to exceed their rated working pressure.

3.5.7

The initial pressure test on the manifold and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

3.5.8

At nipple up, the casing shall be tested to 80% of burst rating. NOTE: BOP equipment may have a higher working pressure than required, due to rig equipment availability. The high-pressure test requirement in these situations shall be site-specific (limited by the WP rating of wellhead).

3.6

Specific Pressure Testing Requirements for Class ‘B’ 3M BOP Stack 3.6.1

The initial WCE pressure test shall be conducted after complete installation. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.6.2

Subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.6.3

The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 2100 psi (70% of the rated working pressure). NOTE: A cup tester may be used if the high-pressure test does not exceed 80% of the casing burst rating.

3.6.4

The casing cup tester must be the appropriate size/weight for the application. When using this tester, care must be taken that the total load applied to the drill string (cup area times test pressure, plus the weight of the suspended drill string) does not exceed the string’s tensile limit.

3.6.5

Test plugs must be checked to insure the plug fits the casing head.

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3.6.6

The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe, vibrator hose, and piping to pumps shall be tested to same high-pressure tests (initial and subsequent), as the BOP equipment, but not to exceed their rated working pressure.

3.6.7

The initial pressure test on the manifold and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

3.6.8

At nipple up, the casing shall be tested to 80% of burst rating. NOTE: BOP equipment may have a higher working pressure than required, due to rig equipment availability. The high-pressure test requirement in these situations shall be site-specific (limited by the WP rating of wellhead).

3.7 Specific Pressure Testing Requirements for Class ‘C’ or ‘II’ 3M BOP Stack 3.7.1

The initial WCE pressure test shall be conducted after complete installation. The WCE test pressure is to 100% rated working pressure of the last wellhead.

3.7.2

Subsequent BOP tests shall be at 85% rated working pressure of the last wellhead rating.

3.7.3

The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 2,100 psi (70% of the rated working pressure). NOTE: A cup tester may be used if the high-pressure test does not exceed 80% of the casing burst rating.

3.7.4

The casing cup tester must be the appropriate size/weight for the application. When using this tester, care must be taken that the total load applied to the drill string (cup area times test pressure, plus the weight of the suspended drill string) does not exceed the string’s tensile limit.

3.7.5

The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe, vibrator hose, and piping to pumps shall be tested to same high-pressure tests (initial and subsequent), as the BOP equipment, but not to exceed their rated working pressure.

3.7.6

The initial pressure test on the manifold and BOP hydraulic lines shall be at the rated working pressure of the closing unit (3,000 psi). Subsequent pressure shall be performed on each well installation at the same pressure or after repairs to the hydraulic circuit.

3.7.7

At nipple up, the casing shall be tested to 80% of burst rating. NOTE: When testing a Class ‘II’ 3M Workover stack on a Power Water Injection well equipped with a ball master valve, the following must be observed: a) Check the ball valve for leaks with wellhead pressure, from below, prior to nippling-up the BOP stack. b) Report any observed leak for decision to spot a cement isolation plug. c) Test the blind ram on the ground against a blind flange prior to nipplingup the BOP stack. This will provide a pressure test on the blind ram without relying on the ball valve, which may leak at higher pressure. The pipe ram and annular can be tested with a cup tester after nippling up.

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3.8 Specific Pressure Testing Requirements for Class ‘D’ Diverter Stack

4.0

3.8.1

Activate the ‘close/open sequence’ with drillpipe or test mandrel in the diverter to verify control functions. DO NOT attempt to close the diverter on open hole except in an emergency.

3.8.2

Pump water through the diverter system at low pressure and high rates. Examine entire system for leaks, excessive vibration, and proper tie down.

3.8.3

Function test the diverter daily.

3.8.4

Diverter shall only be hydro-tested from the top when installed on un-cemented (driven) conductor.

3.8.5

For diverter installations on cemented conductor, a pressure test of up to 70% of the working pressure of the weakest component or up to the wellhead weld test pressure, but not to exceed 200 psi shall be made.

PRESSURE TESTING PROCEDURE The recommended pressure testing procedure for a Class ‘A’ 15,000 and 10,000 psi BOP configuration is given below. This test procedure can be easily amended and made applicable for the other classes of preventer stacks. Although the actual testing sequence may vary somewhat, the ultimate objective must be achieved: To test each individual preventer, valve, and all associated lines in the BOP system from the wellbore direction at a 300 psi low-pressure and then a specified high-pressure. The pressure source is shown down the drillpipe and through a perforated sub or ported test plug (excluding blind ram or casing test); although, a BOP side outlet may be used. The annular and pipe rams are tested individually in this manner. The blind rams are tested after removing the drillpipe and applying pressure through the kill line, between closed rams and test plug. NOTE: In the case of the Class ‘A’ 15,000 and 10,000 psi (non-tapered string, where a lower set of blind rams are positioned below the kill line), the test pressure must be applied through the side outlet of the BOP. In order to test each individual valve on the kill line, choke line, and manifold; proceed after pressure testing the far outside valves, (all other valves open) by opening these valves and closing each inside adjacent valve, pressure testing, and working inward to the stack. NOTE: The steps in the following procedure should be performed in numerical sequence. The instructions assume that at the beginning of each step, the equipment is arranged as in the end of the previous step. Therefore, if this particular procedure is not followed in sequence, erroneous test results may be obtained. 4.1

Function Testing and Flow Testing

Before applying test pressure to the preventers, perform the following:

4.2

4.1.1

Close and open all preventers. Do not close pipe rams or annular preventer on open hole.

4.1.2

Pump through the kill line, flow line, mud-gas separator, and choke lines and all flare lines with water to make sure none are plugged.

Fill the Stack with Water

Drain the mud from the BOP stack and fill with clear water.

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4.3

Casing Test

A casing test is generally conducted at nipple-up and when testing DV or float equipment. In addition, this test is required every 14 days (along with the scheduled BOP test), with the use of a cup tester, to provide a pressure test on casing head valves and verify casing integrity. To conduct a casing test, perform the following: 1) Connect the pressure source to the kill line and open kill line valves #4 and #5. 2) Open all valves and chokes on choke manifold. Close valve #7 on choke line. 3) Close outer casing head valves #1 and #3a. 4) Close the blind/shear blind rams (or upper pipe rams, if pipe in the hole). 5) Pump into the well through the kill line monitoring/recording the test pressure at the test pump. For all casing strings other than drive pipe or structural casing, conduct the test to 80% of the minimum internal yield (burst) of the casing. 6) To test inner casing head valves, close valves #2 and #3 and open outer valves #1 and #3a. (See Figure C.1). NOTE: Manufacturers recommend against opening rams which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur. Figure C.1 Casing Test

Shear Blind Rams

#3a

NOTE: Very Important - Monitor valves #1, #2, #3 and #3a for leaks/well flow. Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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4.4

Shear Blind Ram Test (or Blind Rams for other BOP Stack Configurations) To pressure test the Shear Blind Ram (or Blind Ram), the following is required: 1) Land test plug in the casing head and remove running tool from the wellbore. 2) Connect the pressure source to the kill line and open kill line valves #4 and #5 (see Figure C.2). 3) Open all valves and chokes on the choke manifold. 4) Open all casing head valves and close the choke line valve #7. 5) Close the shear blind rams. 6) Pump into the well through the kill line. Monitor and record the test pressure at the test pump. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test at the pressure specified in Section 3of this chapter, for Class ‘A’ 15M / 10M. NOTE: This test will also evaluate the choke line HCR valve and thereby eliminate the need for Step 3.11.

Figure C.2

Shear Blind Ram Test

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow.

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4.5

Annular Preventer Test the annular preventer as follows: 1) Land the test plug and test joint in the casing head. 2) Connect the pressure source to the test joint at the rig floor. 3) Close the kill line HCR (valve #4) and open all other kill line valves (the kill line check valve should be crippled). 4

First, open all choke line and choke manifold valves. Then close the outermost choke manifold valves #15, #16, #17, and #18 (before buffer tank). (See Figure C.3).

5

Verify that the casing head valves #2 and #3 are open.

6) Close the annular preventer and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at a pressure equal to 70% of the rated working pressure of the annular preventer. Verify the accuracy of the gauge installed downstream of choke manifold valve #19 by observing the test pressure.

Figure C.3

Annular Test

Shear Blind Rams

#19

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow.

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4.6

Upper Pipe Rams Without changing the choke manifold or testing arrangement, immediately test the upper pipe rams as follows. 1) Close choke manifold valve #19 (see Figure C.4). 2) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements. Confirm that choke manifold valve #19 is not leaking by observing a zero pressure indication on the downstream gauge.

Figure C.4 Upper Pipe Rams

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow.

4.7

Remote Hydraulic Choke Integrity Verification: Verify as described below; before proceeding to Step 3.8. 1) Open outermost choke manifold valves #15, #16, and #18. 2) Close Hydraulic Chokes (see Figure C.5).

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3) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Record bleed-off time, if any. Increase pressure to 2500+ psi (do not exceed 10,000 psi). The purpose of the test is to verify the choke is not washed-out and is capable of operating and holding adequate backpressure during well kill operations. NOTE: API Specification 16C, Second Edition for Choke and Kill Systems states in section 10.5.1: “Drilling chokes are not intended to be used as shut off valves.” NOTE: The chokes are being shell tested to both low and high pressure under section 3.6 of this manual as well as the pressure integrity test in this section. Figure C.5

Positive-Sealing Choke Test

Shear Blind Rams

#3a

NOTE:

4.8

Monitor valves #1, #2, #3 and #3a for well flow.

Choke Manifold Valves (continued) Continue testing the choke manifold valves by performing the following: 1) Open outermost choke manifold valves #15, #16, #17, and #18. 2) Open chokes.

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3) Close choke manifold valves #11, #12, and #14 (see Figure C.6). 4) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements.

Figure C.6 Choke Manifold Valves

NOTE: Monitor valves #1, #2, #3 and #3a for well flow. 4.9

Choke Manifold Valves (continued) Continue testing the choke manifold valves by performing the following: 1) Open choke manifold valves #11, #12, and #14. 2) Close choke manifold valves #9, #10, and #13 (see Figure C.7). 3) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements.

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Figure C.7

Choke Manifold Valves

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and 3a for well flow. 4.10 Choke Manifold Valves (continued) 1) Open choke manifold valves, #9, #10, and #13. 2) Close choke manifold valve #8 (see Figure C.8). 3) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements.

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Figure C.8

Choke Manifold Valves

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow. 4.11 Choke Line HCR Valve Test the choke line HCR valve by performing the following: 1)

Open choke manifold valve #8.

2)

Close outer choke line HCR (valve #7). See Figure C.9.

3)

Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements

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Figure C.9

Choke Line HCR Valve

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow.

4.12 Choke and Kill Line Manual Valves Test the inner choke and kill line valves by performing the following: 1) Open choke line HCR (valve #7). 2) Close choke line manual valve #6. 3) Open kill line HCR (valve #4). 4) Close kill line manual valve #5 (see Figure C.10). 5) Close the upper pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements. NOTE: Manufacturers recommend against opening rams which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.

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Figure C.10

Choke and Kill Line Manual Valves

Shear Blind Rams

#3a

NOTE: Monitor valves #1, #2, #3 and #3a for well flow. 4.13 Master Pipe Rams Test the master pipe rams by performing the following: 1) Open the upper pipe rams (see Figure C.11). 2) Close the master pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements. NOTE: Manufacturers recommend against opening rams which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.

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Figure C.11

Master Pipe Rams

Shear Blind Rams

#1

#2

#3

#3a

NOTE: Monitor valves #1, #2, #3 and 3a for well flow. 4.14 Small Pipe Rams Test the small pipe rams by performing the following: 1) Open the master pipe rams (see Figure C.12). 2) Pull the large test joint and test plug. Run a small test joint and plug. 3) Close the small pipe rams and pump into the well through the test joint. Conduct the low-pressure test first at a pressure of 300 psi. Conduct the high-pressure test next at the pressure specified in previous requirements. NOTE: Manufacturers recommend against opening rams which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.

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Figure C.12

Small Pipe Rams

Shear Blind Rams

#1

#2

#3

#3a

NOTE: Monitor valves #1, #2, #3 and 3a for well flow. 4.15 Kelly, Surface Circulating Equipment, and Safety Valves 1) Pick up kelly and install full-opening safety valve on bottom of lower kelly valve. 2) Using an adaptor, connect to an independent test pump or cement pump. 3) Open appropriate standpipe valves and all kelly valves. 4) Fill the system with water and close standpipe valve to test the standpipe, rotary hose, swivel, and kelly. 5) Conduct the low-pressure test first at a pressure of 300 psi. 6) Conduct the high-pressure test next at the pressure specified in previous requirements. 7) By alternating closing upstream and opening downstream valves, all the kelly valves could be tested without pressuring up again, although it may not possible to operate the upper kelly valve under pressure. 8) The inside BOP (float type) can be tested similarly by installing below the full- opening safety valve and opening all valves through the standpipe. Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

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4.16 Wellhead Valves Test all valves on the wellhead individually to their rated working pressure on installation (using a VR plug) and to 80% of casing burst on subsequent pressure tests, with a cup tester located correctly in the last casing string.

5.0

ACCUMULATOR TESTS Control system tests are for the purpose of determining the operating condition of the accumulator and BOP system. The drawdown test, shall be performed every 14 days in accordance with API-RP53 (latest edition), at the same time the BOP equipment is pressure tested, and at any other time deemed necessary by the Saudi Aramco Foreman. The results shall be noted on the Saudi Aramco BOP Pressure Test Report (see Figure C.13, or Form # 2.0 in Section S of this manual). To analyse the performance of the accumulator, the results of each test should be compared with results of several previous tests. Any increase in closure or recharge time indicates an immediate need for a thorough examination of the accumulator system. The accumulator test shall include the following, • • • •

Record the accumulator capacity and useable volume Record the accumulator pressure Record the pre-charge pressure and last date checked Record the closing and opening times for each component

NOTE: Alternate accumulator bi-weekly tests between the main nitrogen unit (with charging system isolated) and air/electric back-up system (with bottle banks isolated). Preventer functions should also be operated remotely to insure proper operation of all functions from the remote stations. The accumulator test shall also comply Saudi Aramco’s general requirements as follows: •

Closing time for ram preventers should not exceed 30 seconds.

•

Closing time for annular preventers (less than 18-3/4”) should not exceed 30 seconds.

•

Closing time for annular preventers (18-3/4” and larger) should not exceed 45 seconds.

•

The accumulator must have enough stored fluid under pressure to close all preventers, open the choke hydraulic control gate valve (HCR), and retain 50% of the calculated closing volume with a minimum of 200 psi above pre-charge pressure, without assistance of the accumulator pumps.

•

The accumulator-backup system shall be automatic, supplied by a power source independent from the power source to the primary accumulator-charging system, and possess sufficient capability to close all blowout components and hold them closed.

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6.0

HANG-OFF LIMITATIONS WHILE TESTING Many times, a portion of the bottom-hole assembly will be hung-off below the test plug while conducting a BOP test. This is done for a variety of reasons including: • •

Leaves pipe in the hole to circulate through in case the well kicks. Shortens the trip time by not having to pull completely out of the hole.

IT MUST BE REMEMBERED however, that hanging-off weight below the test plug reduces the maximum allowable BOP test pressure. The table below lists the maximum allowable hang-load for a given BOP test pressure for the wellhead manufacturers used by Saudi Aramco. This chart should be reviewed before hanging-off and testing BOP equipment. TABLE C-1 Bowl Size

0 psi

1,000 psi

2,000 psi

3,000 psi

4,000 psi

5,000 psi

6,000 psi

7,000 psi

8,000 psi

9,000 psi

10,000 psi

11”

580,000

580,000

580,000

580,000

580,000

580,000

543,000

466,000

389,000

312,000

235,000

13”

580,000

580,000

580,000

580,000

580,000

515,000

388,000

261,000

134,000

7,000

20”

580,000

580,000

580,000

580,000

580,000

580,000

-

-

-

-

-

26”

580,000

580,000

580,000

580,000

580,000

580,000

-

-

-

-

-

7.0

-

TEST PRESSURE REQUIREMENTS FOR CASING/TUBING RAMS

Casing rams (and annular preventer) shall be pressure tested with a test plug and casing/tubing joint. The test pressure shall be 80% of collapse of the pipe of the pipe or the working pressure of the flanges, whichever is less.

8.0

RE-CERTIFICATION REQUIREMENTS 8.1

A full OEM certification or recertification of the WCE, must be performed at the start of new contract. Thereafter OEM recertification will be as stated below. 8.1.1

All WCE ≤3,000 psi: ≤3,000 psi, regardless of gas or oil service will be 5-year recertification.

8.1.2

Gas & Offshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Gas or Offshore Oil service will be 3-year recertification and will retain the balance of current 3-year certification if moving to Onshore Oil service. EXAMPLE: A 13-5/8”, 10K BOP transferred to Onshore Oil service COC. OEM recertification would remaining in Onshore Oil service, years.

8.1.3

used in Gas or Offshore Oil for 1 year then will retain the remaining 2 years validity of the be required within the following 2 years. If the new equipment COC would be valid for 5

Onshore Oil WCE ≥5,000 psi: ≥5,000 WCE in Onshore Oil service will be 5-year recertification. However, if ≥5,000 WCE has been in Onshore Oil service for 3 years, it cannot be transferred to Gas or Offshore Oil and retain the remaining 2-year validity of the COC . EXAMPLE: A 13-5/8”, 10K BOP used in Onshore Oil service for 2-years then transferred to Gas or Offshore Oil will not retain the remaining 3 years COC validity. The remaining validity in this example would be 1 year because of the transfer.

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OEM recertification would be required within the following 1 year. If remaining in Gas or Offshore Oil, the new equipment COC would be valid for 3 years. 8.1.4

           

OEM Recertification must be in accordance with the relevant API or NACE Standards for repair/remanufacture. The OEM COC and corresponding repair/remanufacture documentation package shall be kept with the equipment and must be available for inspection at the rig site by Saudi Aramco personnel. WCE for recertification includes, but is not limited to: BOP’s: Ram and Annular Ram blocks API Diverters Manual/hydraulic gate valves and check valves on the kill, emergency kill Manual/hydraulic gate valves on choke line and choke manifold. Hydraulic drilling chokes. Manual chokes Kill, emergency kill and choke lines (and line components) including both hard line and flexible lines. Drilling spools. Double Studded Adapters (DSA) Tees, crosses, hardline spools and buffer chamber BOP Lifting Plates or Lifting flanges shall undergo full OEM NDE when the BOP’s are recertified. TABLE C-2 BOP RECERTIFICATION INTERVALS WCE PSI ONSHORE OFFSHORE ALL GAS OIL OIL ONSHORE or OFFSHORE* ≤2,000 5 YEARS 5 YEARS 5 YEARS 3,000 5 YEARS 5 YEARS 5 YEARS 5,000 5 YEARS* 3 YEARS 3 YEARS ≥10,000** 5 YEARS* 3 YEARS 3 YEARS

8.1.5

Recertification can only be performed by the OEM or their licensee facility and shall meet the requirements of all applicable OEM and industry standards, i.e. API 6A, API 16A, API 16AR, API 16C, NACE, etc. The OEM or ARF repair facility must be Certified and Registered to API Q1 and/or Q2 in addition to API Specification’s 6A, 16A, and 16C. If recertified by a licensee, the COC Certificate and document package shall be signed by an OEM employee (not signed by only the licensee representative) and include a copy of the ARF license issued by the OEM and Registration Certificates for the applicable API Specifications. BOP’s must correspond and comply with API-16AR Repair Level: RL-2 for 3000 and 5000 PSI and RL-3 with for 10,000 and 15,000 PSI. In-field recertification is not acceptable.

8.1.6

New equipment purchased after the release of WCM 6th Edition, must be API Monogrammed and shall be accompanied by the manufacturer's certificate of compliance and a full documentation package including inspection and test reports. Offshore Oil WCE, ≥5,000 psi, will be 3-year recertification. Transfer of Offshore Oil 5,000 psi WCE to Onshore for the reason of delaying recertification is prohibited.

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8.2

8.1.6

API 6A dumb iron with 100% API specified dimensions i.e., drilling spools, Double Studded Adapters (DSA), tees, crosses and hardline spools, do not require OEM recertification. This equipment can be inspected, repaired and recertified by any qualified API 6A Licensed facility. This does not apply to other API 6A equipment such as gate valves, check valves or manual adjustable chokes.

8.1.2

New equipment purchased after the release of WCM 6th Edition, must be API Monogrammed and shall be accompanied by the manufacturer's certificate of compliance and a full documentation package including inspection and test reports.

8.1.6

Choke and Kill flanged hard-lines mounted in semi-permanent locations may have in-situ recertification using NDT methods to accurately determine Wall Thickness (erosion or corrosion), Material Defects and Material Hardness.

8.1.7

As a minimum, recertified Gate Valves, HCR Valves and Check Valves must correspond and comply with Repair Level: RL-2 for 3000 and 5000 PSI and RL-3 with gas test for 10,000 and 15,000 PSI. (Ref. API 6A, Annex J and Section A of Saudi Aramco WCM, Line Item 2.4). Gas Testing is required when recertifying PSL3G Gate Valves and Check Valves.

8.1.9

Gas Testing of API 6A “dumb iron”, i.e. tee blocks, spools, tee’s, crosses, etc. is not required.

8.1.8

New/Repaired equipment shall be accompanied by the manufacturer's/Repair Facility certificate of compliance and a full documentation package including inspection and test reports.

8.1.9

Shear ram blades, shear ram blocks, and blade retention bolts shall be inspected annually by visual inspection and surface NDE. The inspection results shall be verified against the manufacturer’s acceptance criteria.

There is no re-certification requirement for Accumulator Control Systems. However, the Accumulator Control Unit must undergo periodic maintenance, intervals not to exceed 3 months. An OEM or OEM Qualified Designee, inspection and function test diagnostics (offsite or onsite) along with NDE and hydrostatic testing of the individual accumulator bottles is required every five years. All documentation including individual Accumulator Bottle test charts must reside on the rig.

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CHAPTER D: WELL CONTROL POLICIES TABLE OF CONTENTS 1.0

WELL CONTROL POLICIES

D-4

2.0

WELL CONTROL CERTIFICATION

D-4

3.0

USE OF DIVERTERS 3.1

Onshore Wells

D-4

3.2

Offshore Wells

D-4

4.0

LEAK IN FLANGE OR RING GASKET BETWEEN BOP AND CASING HEAD D-4

5.0

DRILL PIPE FLOAT

D-5

6.0

TAPERED STRING

D-5

7.0

MAINTAINING MINIMUM OVERBALANCE

D-5

8.0

SPACE OUT 8.1

Space Out Data

D-5

8.2

Space Out For BOP’s With SBR’s

D-5

9.0

SLOW PUMP RATE DATA

10.0

TRIPPING PIPE

11.0

D-5

10.1 Pulling Out of Hole

D-6

10.2 Running In Hole

D-6

PERFORMING FLOW CHECKS 11.1 While Drilling

D-6

11.2 While Tripping

D-6

12.0

DISPLACING TO BRINE ON HORIZONTAL WELLS

D-7

13.0

SHUTTING IN WELL 13.1 Shutting In Well without Flow Checking

D-7

13.2 While Drilling

D-7

13.3 While Tripping

D-7

13.4 With BHA across BOP Stack

D-7

13.5 Shutting In On Pre-Perforated Liner with DP and 10,000 psi Class ‘A’ BOP Stack

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14.0

FAILURE OF UPPER PIPE RAMS DURING A WELL KILL OPERATION

15.0

BOP CONFIGURATION WHEN RUNNING CASING OR LINERS

16.0

D-8

15.1 Running Casing or Liner W/ Class ‘B’ 3M Stack

D-8

15.2 Running Casing or Liner W/ Class ‘A’ 3M or 5M Stack

D-8

15.3 Running Casing W/ Class ‘A’ 10M/15M Stack (W/ SBR)

D-9

15.4 Running Liner W/ Class ‘A’ 10M/15M Stack (W/ SBR)

D-9

15.5 Running Pre-Perforated Liner W/ Class ‘A’ 10M/15M Stack

D-9

CHANGING RAMS OR INSTALLING CASING RAMS 16.1 Isolation Policy

D-9

16.2 Pressure Testing Casing Rams

D-10

17.0

INSTALLING CASING SLIPS WITH MULTI STAGE CEMENTING

D-10

18.0

BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING

19.0

18.1 Running 5-1/2” or 5-1/2” x 4-1/2” With Class ‘A’ 10M and Higher Stack

D-10

18.2 Running 4-1/2” Tubing With Class ‘A’ 10M and Higher Stack

D-10

18.3 Running Dual Strings Simultaneously With Class ‘A’ 5M Stack

D-10

BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING WITH PACKER 19.1 Running Tubing/Packer Simultaneously w/ Class ‘A’ 3 or 5M Stack

20.0

21.0

REMOVING BOP STACK OR PRODUCTION TREE 20.1 Isolation Policy for Low GOR Oil Wells

D-11

20.2 Isolation Policy for High GOR Oil Wells

D-11

20.3 Isolation Policy for Gas Wells

D-11

20.4 Isolation Policy for WIW Wells

D-11

RIGGING DOWN ON HIGH GOR WELLS W/ SSSV 21.1 RD Procedure (w/ Little Clearance between Rig and Tree)

22.0

23.0

D-11

D-12

RUNNING OR PULLING TUBING AND ESP CABLE 22.1 BOP Configuration

D-12

22.2 Pressure Testing Annulars

D-12

22.3 Shut-In Procedure

D-12

BOP CONFIGURATION WHEN RUNNING TEST STRING 23.1 Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (W/ SBR)

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23.2 Running 3-1/2” Test String w/ Class ‘A’ 5M Stack

24.0

RIGGING UP SURFACE WELL TEST EQUIPMENT 24.1 Installing Surface Lines Upstream of Test Manifold

25.0

26.0

27.0

D-13

PRESSURE TESTING WITH NITROGEN 25.1 Surface Well Test Equipment (Gas Wells)

D-13

25.2 Lubricator (Gas Wells)

D-13

PROBLEMS WHILE LOGGING 26.1 Shutting in While Logging With Side Entry Sub (Wireline across BOP)

D-14

26.2 Fishing Procedure for Stuck Logging Tool in Open Hole

D-14

RUNNING PDHMS AND/OR SMART-WELL LINES ON TUBING OR CASING 27.1 Oil Wells

D-14

27.2 Gas Wells

D-15

28.0

SETTING BRIDGE PLUGS

D-15

29.0

PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS 29.1 Required Number of Mechanical Barriers of Isolation

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WELL CONTROL POLICIES

This Chapter of the Well Control Manual sets forth the well control policies and specifications that are routinely referenced. These policies (as well as the equipment standards and procedures throughout this well control manual) are considered mandatory. Variations or deviations from these requirements require endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these requirements shall be the responsibility of the Saudi Aramco Drilling Foreman (or Liaisonman) as directed by the Drilling Superintendent.

2.0

WELL CONTROL CERTIFICATION POLICY

All Saudi Aramco Drilling and Workover Superintendents, Rig Foremen, Liaisonmen, Engineers, Engineering Supervisors, Engineering General Supervisors, Liaisonmen Consultants, Contract Toolpushers, Drillers, and Assistant Drillers shall have current Supervisor Level Well Control Certification (Well Cap) from an IADC or IWCF accredited school.

3.0

USE OF DIVERTERS

3.1

NIPPLING UP DIVERTERS ONSHORE POLICY

A Class ‘D’ diverter stack shall be installed on the conductor and/or next casing string for all exploration wells and development wells in the shallow gas area or areas where offset data indicates shallow gas wells. There shall be a Schedule 120, 2” weld X 2” EUE Nipple welded to the conductor casing with a 2” EUE threaded Ball Valve for cement returns and operational tie-in. The nipple must be welded using a WPS approved by the rig operations engineer. All other onshore areas do not need a diverter.

3.2

NIPPLING UP DIVERTERS OFFSHORE POLICY

A Class ‘D’ diverter stack shall be installed on the conductor of all offshore exploration wells and wells where offset data indicates possible shallow gas. There shall be a Schedule 120, 2” weld X 2” EUE Nipple welded to the conductor casing with a 2” EUE threaded Ball Valve for cement returns and operational tiein. The nipple must be welded using a WPS approved by the rig operations engineer. The diverter lines must have the capability of discharging to Port and / or Starboard.

4.0

LEAK IN FLANGE OR RING GASKET BETWEEN BOP STACK AND CASING HEAD (WHILE TESTING BOP STACK) If a leak is observed in a flange during a BOP test, the bolts on the flange should first be tightened to recommended torque. If tightening the bolts does not cure the leak the following should be followed for any leak which would require the removal of the BOP from the Wellhead: • Set a Cement Plug or RTTS Packer in accordance with GI: 1853.001

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5.0

DRILL PIPE FLOAT POLICY

A drill pipe float shall be run at all times (except when planned operations preclude running a float; as testing, treating, or squeezing). Ported float valves are not allowed as these ports can be easily plugged and sometimes washout.

6.0

TAPERED STRING POLICY

7.0

When working with a tapered drill string always be in a position to have at least one stand of either size pipe available to pick up.

MAINTAINING MINIMUM OVERBALANCE General Requirements for Overbalance for Drilling & Workover Applications POLICY

A minimum overbalance shall be maintained on all wells as indicated below: • • •

100 PSI overbalance on Water Reservoirs 200 PSI overbalance on PWI and Oil Wells 300 PSI overbalance on Gas Wells

NOTE: Water flows, as in Arab-C, may be drilled with flow if hydrocarbons, H 2 S, or high rates are not encountered.

8.0

SPACE OUT

8.1

SPACE OUT DATA POLICY

8.2

Space out data shall be clearly visible in the dog house and recorded in the IADC tour book each time the rig performs a bop drill.

SPACE OUT FOR BOP’s WITH SBR’s POLICY

When spacing out in BOP Stacks with SBR’s a tool joint shall be positioned 2–3 feet above the lower (Master) pipe rams. In the event that pipe is to be sheared, the following steps will be taken: 1) 2) 3) 4)

Close lower master rams Lower the tool joint lowered to land out in rams Slack off so that the pipe is relaxed (not in tension) Activate the SBR’s using proper procedures

NOTE: This procedure will negate the recoil effects of shearing free, suspended pipe allowing pipe to drop and prevent stored energy in drill string releasing suddenly causing a recoil and possible damage to top drive main shafts and lodging pipe across BOP stack.

9.0

SLOW PUMP RATE DATA POLICY

Slow pump rate shall be recorded in the IADC tour book 1) 2) 3) 4)

Tourly After a mud weight change After a bit nozzle or BHA change After each 500’ of depth

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5) 6)

After a drilling or completion fluid type change Whenever mud properties significantly change

NOTE: All flow checks shall be at least 15 minutes.

10.0 TRIPPING PIPE 10.1

Pulling Out Of Hole POLICY

The following procedure is required when POH 1) 2) 3)

Ensure a full opening safety valve, inside BOP, closing wrench, and crossover subs are on rig floor Record data on trip sheet every 5 stands for DP, 2 stands for HWDP, and every stand for DC Compare data to expected displacement values

NOTE: 10.2

Avoid pulling a wet string whenever possible.

RUNNING IN HOLE POLICY

The following procedure is required when RIH 1) 2) 3) 4) 5)

Ensure full opening safety valve, inside bop, closing wrench, and crossover subs are on rig floor Run in hole approximately one minute per stand Record data on trip sheet every 5 stands for DP, 2 stands for HWDP, and every stand for DC Compare data to expected displacement values Fill drill pipe every 10 to 20 stands

NOTE: Use the trip tank when running casing.

11.0 PERFORMING FLOW CHECKS 11.1

PERFORMING FLOW CHECKS WHILE DRILLING POLICY

A FLOW CHECK SHALL BE PERFORMED WHENEVER 1) 2) 3) 4) 5) 6)

Decrease in pump pressure Increase in pump strokes Decrease in mud weight Increase in chlorides Gradual increase in drill rate Drilling break

NOTE: All flow checks shall be at least 15 minutes. 11.2

PERFORMING FLOW CHECKS WHILE TRIPPING POLICY

A FLOW CHECK SHALL BE PERFORMED WHENEVER 1) 2) 3)* 4)* 5)

When the hole is not taking the correct amount of fluid Before pumping a slug Before pulling out of the hole After pulling 5 to 10 stands When bit enters casing shoe

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6)* Prior to pulling last 5 stands 7) Prior to pulling the BHA *

Indicates additional flow checks required when a hydrocarbon zone is open.

NOTE: All flow checks shall be at least 15 minutes.

12.0 DISPLACING TO BRINE ON HORIZONTAL WELLS POLICY

The following SHALL BE required 1) 2) 3) 4)

A brine density that will provide the same overbalance (at bottom hole temperature) as mud weight utilized Measurement of brine density in/out to verify that both are the same at same temperature A minimum of one hour to wait/observe well after displacing to brine Pumping out of the hole for minimized swabbing, continued fill-up, and improved gas displacement in the horizontal open hole

13.0 SHUTTING IN WELL 13.1

Shutting In Well Without A Flow Check POLICY

Immediate action should be taken to shut in well whenever there is: 1) 2)

13.2

Shutting In Well While Drilling POLICY

Shut-in procedure (HARD SHUT–IN) 1) 2) 3) 4) 5)

13.3

An increase in pit gain An increase in flow rate

Space OUT (SPOT TOOL JOINT) Stop mud pumps Close annular or upper ram preventer Confirm well is shut in and flow has stopped Open HCR

Shutting In Well While Tripping POLICY

Shut-in procedure (HARD SHUT–IN) 1) 2) 3) 4) 5) 6)

Space out (spot tool joint) Stab full open safety valve Close safety valve Close annular or upper ram preventer Confirm well is shut in and flow has stopped Open HCR

NOTE: DO NOT attempt to run in hole with the well flowing. 13.4

Shutting In Well With BHA Across Bop Stack POLICY

SHUT-IN PROCEDURE (hard shut–in) 1) 2) 3) 4)

Set slips Install crossover to full open safety valve Stab full open safety valve Close safety valve

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5) 6) 7) 8) 9) 10)

Close annular Confirm well is shut in and flow has stopped Open HCR Install inside BOP Open safety valve Reduce closing pressure on annular and strip-in a stand of drill pipe

NOTE: In the event of a failure in the annular (with BHA across bop stack) and uncontrolled flow, the BHA should be dropped and well shut in with the blind rams. 13.5

Shutting In On Pre-Perforated Liner with Drill Pipe POLICY

SHUT-IN PROCEDURE: 1) Set casing slips 2) Install XO's to DP 3) Make up a stand of DP and RIH 4) Stab full open safety valve and close valve 5) Install inside bop and open safety valve 6) Shut upper pipe rams 7) Open HCR NOTE:

If this procedure cannot be accomplished due to the amount of flow (or inner string), the liner shall be dropped (by closing pipe rams, hanging off, and opening pipe ram) and shutting the blind rams.

14.0 FAILURE OF UPPER PIPE RAMS DURING A WELL KILL OPERATION (10,000 + psi Class A) POLICY

RECOMMENDED ACTION TO INCLUDE 1) Close master pipe rams 2) Replace upper pipe rams with newly dressed rams. NOTE: Circulation and kill operations should continue using the secondary choke line on a Class ‘A’ 10M or 15M BOP stack and repair later. 3) Close upper pipe rams 4) Equalize pressure between upper and lower pipe rams 5) Open master pipe rams 6) Continue with well kill

15.0 BOP CONFIGURATION WHEN RUNNING CASING OR LINERS 15.1

RUNNING CASING OR LINER WITH CLASS ‘B’ 3000 PSI BOP STACK POLICY

15.2

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: USED AS CASING RAMS TOP RAM: BLIND RAMS MASTER PIPE: DRILL PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR.

RUNNING CASING OR LINER WITH CLASS ‘A’ 3,000 OR 5,000 PSI BOP STACK (WITH OR WITHOUT SBR) POLICY

FOR CASING, SHORT OR LONG LINERS

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BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: USED AS CASING RAMS TOP RAM: PIPE RAMS MIDDLE RAM: BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR. 15.3

RUNNING CASING WITH CLASS ‘A’ 10,000 PSI (and Higher) BOP STACK (with SBR) POLICY

15.4

RUNNING LINER WITH CLASS ‘A’ 10,000 PSI (and Higher) BOP STACK (with SBR) POLICY

15.5

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: TOP RAM: CHANGE PIPE RAMS TO CASING RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: BLIND RAMS BTM MASTER: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: USED AS CASING RAMS TOP RAM: PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: BLIND RAMS BTM MASTER: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR.

RUNNING PRE-PERFORATED LINER WITH 10,000 PSI (and Higher) CLASS ‘A’ BOP STACK POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: TOP RAM: LARGE DP PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: SMALL DP PIPE RAMS BTM MASTER: LARGE DP PIPE RAMS HAVE XO’S (LINER x DP) ON DRILL FLOOR.

16.0 CHANGING RAMS OR INSTALLING CASING or TUBING RAMS 16.1

ISOLATION POLICY WHEN CHANGING RAMS OR INSTALLING CASING OR TUBING RAMS ABOVE THE BLIND RAMS POLICY

REQUIRES 2 BARRIERS FOR ISOLATION 1) Closed blind rams. Monitor annulus using wellhead valves. If the bottom master rams are to be changed, refer to Section 20 NOTE: NOTE:

Current Revision: MAY, 2018 Previous Revision: JUNE, 2014

FOR BARRIER DETAILS REFER TO G.I. 1853.001 A test plug or tubing hanger with installed BPV should not be used as a mechanical barrier in this application.

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16.2

PRESSURE TESTING CASING AND TUBING RAMS POLICY Casing and Tubing Rams (and annular BOP) shall be pressure tested with a test plug and casing joint to 80% of the pipe collapse or the rated working pressure of the BOP (whichever is less).

17.0 INSTALLING CASING SLIPS WITH MULTI STAGE CEMENTING POLICY

SET CASING SLIPS AS FOLLOWS 1) Displace 1st stage cement w/ mud ( 2nd, if 3 stage job) 2) Open upper most DV 3) Circulate hole clean w/ mud 4) WOC until the cement has attained a compressive strength of 500 psi with well static (observing well for flow). Compressive test to be confirmed through laboratory testing. 5) Break circulation every Hour to prevent cement from setting up across ports (if packer failure and Expansion) 6) Circulate bottoms up 7) Pickup BOP stack (DO NOT DROP CASING SLIPS) 8) Set casing slips prior to cementing final stage

18.0 BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING 18.1

RUNNING 5-1/2” PRODUCTION TUBING (OR 5-1/2” x 4-1/2” TUBING) AND CLASS ‘A’ 10,000 AND HIGHER PSI BOP STACK POLICY

18.2

RUNNING 4-1/2” PRODUCTION TUBING CLASS ‘A’ 10,000 AND HIGHER PSI BOP STACK POLICY

18.3

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: 5-1/2” PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: 5-1/2” PIPE RAMS BTM MASTER: 5-1/2” PIPE RAMS HAVE XO (5-1/2” x 4-1/2” TBG) ON DRILL FLOOR.

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: 4-1/2” PIPE RAMS MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: 4-1/2” PIPE RAMS BTM MASTER: RAMS TO MATCH THE LARGEST DP IN USE HAVE XO (5-1/2” DP x 4-1/2” TBG) ON DRILL FLOOR.

RUNNING DUAL STRINGS SIMULTANEOUSLY WITH CLASS ‘A’ 5,000 PSI BOP STACK POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: DUAL RAMS MIDDLE RAM: SHEAR BLIND RAMS MASTER PIPE: DUAL RAMS

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19.0 BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING AND PACKER 19.1

RUNNING PRODUCTION TUBING AND PACKER SIMULTANEOUSLY WITH CLASS ‘A’ 3,000 OR 5,000 PSI BOP STACK POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: **TUBING RAMS MIDDLE RAM: BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE: *DRILL PIPE RAMS *

Do NOT change the master pipe rams to tubing rams (they should remain drill pipe rams) this will eliminate the need for running a RBP and/or RTTS and storm valve.

**

If a tapered string is to be run, the upper pipe rams shall be changed to the size of the major section of tubing in the string.

Have XO’s (tubing x DP) and (large tubing x small tubing, for tapered strings) on the drill floor. NOTE:

In case of loss circulation, the hole shall be continuously filled (both tubing and backside) while running the completion string.

20.0 REMOVING BOP STACK OR PRODUCTION TREE OR CHANGING MASTER PIPE RAMS 20.1

ISOLATION POLICY FOR LOW GOR OIL WELLS POLICY

REQUIRED BARRIERS FOR OIL WELLS (GOR < 850 SCF/BBL) 2 SHUT-OFFS (ONE MECHANICAL) FOR BARRIER DETAILS REFER TO G.I. 1853.001

20.2

ISOLATION POLICY FOR HIGH GOR OIL WELLS POLICY

REQUIRED BARRIERS FOR OIL WELLS (GOR > 850 SCF/BBL) 3 SHUT-OFFS (TWO MECHANICAL) FOR BARRIER DETAILS REFER TO G.I. 1853.001

20.3

ISOLATION POLICY FOR GAS WELLS POLICY

REQUIRED BARRIERS FOR GAS WELLS 3 SHUT-OFFS (TWO MECHANICAL) FOR BARRIER DETAILS REFER TO G.I. 1853.001

20.4

ISOLATION POLICY FOR WATER INJECTION WELLS POLICY

REQUIRED BARRIERS FOR WIW WELLS (IF POSITIVE WHP) 2 SHUT-OFFS (ONE MECHANICAL) FOR BARRIER DETAILS REFER TO G.I. 1853.001

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POLICY

REQUIRED BARRIERS FOR WIW WELLS (IF NO POSITIVE WHP) 1 SHUT-OFF FOR BARRIER DETAILS REFER TO G.I. 1853.001

21.0 RIGGING DOWN ON HIGH GOR WELLS WITH OR WITHOUT SSSV 21.1

RIG DOWN PROCEDURE (WITH LITTLE CLEARANCE BETWEEN RIG AND TREE) POLICY

PROCEDURE 1) NU and PT tree 2) Retrieve wireline plug from tail pipe 3) Close crown valve (do not RD wireline unit) 4) Open well for clean-up 5) Close lower master valve (observe negative test) 6) RIH with wireline and set plug 7) Bleed off pressure (observe plug is holding) - barrier 1 8) Close SSSV 9) Install barrier 2: Mechanical Retrievable Barrier 10) Split tree above closed lower master valve - barrier 3 11) Move the rig out 12) Re-install tree above the lower master valve 13) Later, RU wireline unit and retrieve the plug NOTE:

A BPV may be installed instead of setting a wireline plug.

22.0 RUNNING OR PULLING TUBING AND ESP CABLE 22.1

BOP CONFIGURATION WHEN RUNNING OR PULLING TUBING AND ESP CABLE POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: ANNULAR: BOP STACK: BASED ON BOP CLASS NOTE: One annular may be used if there is 0 psi SIWHP whenever the ESP is not running or if Shear Blind Rams are installed on the BOP’s.

22.2

PRESSURE TESTING ANNULARS POLICY

PRESSURE TEST ANNULARS TO 1,000 PSI (WITH ESP CABLE). NOTE: Testing performed in the shop has shown that an annular can hold 1,000 psi with 31/2” tubing and 1” cable. However, it is normal to have small leaks when annulars are closed on cables. The annular in these instances is to slow the kick only while performing the procedure in section 21.3.

22.3

SHUT-IN PROCEDURE WHEN RUNNING OR PULLING TUBING AND ESP CABLE POLICY

SHUT-IN PROCEDURE 1) Shut-in well with annular (upper) using Saudi Aramco shut-in procedure for tripping. 2) Cut ESP cable with mechanical cutter at the rig floor (a wire line mechanical cutter must be on the floor) 3) Open annular and lower tubing

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4) Close annular (upper) around tubing

23.0 BOP CONFIGURATION WHEN RUNNING TEST STRING 23.1

RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR) POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: 5” PIPE RAMS (FOR STIFF JOINT) MIDDLE RAM: SHEAR BLIND RAMS TOP MASTER: 3-1/2” PIPE RAMS BTM MASTER: RAMS TO MATCH THE LARGEST DP IN USE CHANGE TOP 5” PIPE RAM TO 3-1/2” PRIOR TO POH WITH TEST STRING HAVE XO (3-1/2” PH6 x 3-1/2” DP) ON DRILL FLOOR.

23.2

RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 5,000 PSI BOP STACK POLICY

BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING: ANNULAR: TOP RAM: 5” PIPE RAMS (FOR STIFF JOINT) MIDDLE RAM: BLIND RAMS MASTER RAM: 3-1/2” PIPE RAMS HAVE XO (3-1/2” DP x 5” DP) ON DRILL FLOOR.

24.0 RIGGING UP SURFACE WELL TEST EQUIPMENT 24.1

INSTALLING SURFACE LINES UPSTREAM OF TEST MANIFOLD POLICY

Only connections with metal-to-metal seals are acceptable (API flanged, hubbed, or Grayloc). NOTE: Weco connections are not allowed (leaks in the lip seal can occur with gas, CO 2 , and HT/HP situations).

25.0 PRESSURE TESTING WITH NITROGEN 25.1

SURFACE WELL TEST EQUIPMENT - GAS WELLS POLICY

25.2

Test procedure on gas wells (with 10M WP surface equipment) 1) Pressure test string to 8,500 psi 2) Negative test surface safety valve (if run) and lower master valve 3) Pressure test downstream of choke manifold to 1,200 psi with water 4) Pressure test upstream of choke manifold to 10,000 psi with water 5) Pressure test downstream of choke manifold to 1,200 psi with nitrogen 6) Pressure test upstream of choke manifold to 8,000 psi (80% of water pressure test) with nitrogen

LUBRICATORS - GAS WELLS POLICY

If a lubricator is required on a gas well (for well testing, completion, or workover operations), the lubricator shall also be tested with nitrogen to 80% of water pressure test.

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26.0 PROBLEMS WHILE LOGGING 26.1

SHUTTING IN WHILE LOGGING WITH SIDE-ENTRY SUB (WIRELINE ACROSS BOP STACK) POLICY

26.2

SHUT-IN PROCEDURE 1) Close annular around drill pipe and wireline to restrict flow 2) Install wireline clamp to drill pipe 3) Cut wireline (above clamp) at rotary table with manual cutter 4) Open annular and lower DP until wireline is below bop stack 5) Close annular or uppermost ram as per approved shut-in procedure

FISHING PROCEDURE FOR STUCK LOGGING TOOL IN OPEN HOLE POLICY

STUCK NON-RADIOACTIVE TOOL 1) Pull off electric line at rope socket 2) POH with electric line 3) RIH and engage tool w/ overshot on drill string STUCK RADIOACTIVE TOOL 1) Cut and strip over electric line w/ drill string 2) Engage tool with overshot 3) Pull off electric line at rope socket 4) POH with electric line NOTE:

May consider stripping over the electric line on a non-radioactive tool if: A) B) C)

Hole conditions are poor Large hole size compared to tool OD Open hole section is not known to contain hydrocarbons

Logging companies have a ‘circulating sub’ that can be made up on the drill string (in the event of a well control situation) to hang off the electric line and enable circulation; however, this may be difficult to install with a strong flow up the drill pipe.

27.0 RUNNING PDHMS AND/OR SMART-WELL LINES ON TUBING OR CASING Pipe rams will not close and seal around lines and flat packs. The only way wells with these lines installed on the OD of the tubing can be controlled is to close the annular (does not provide a full seal), cut the line and then strip the pipe into the well until the pipe rams can be closed above the line or to shear the tubing and the line. 26.1 and 26.2 (below) outlines the requirements. 27.1

OIL WELLS POLICY

The following SHALL BE required 1) The use of Shear Blind Rams on ALL smart well and PDHMS completions is required when deep set control lines or flat packs are utilized. NOTE: The Shear Blind Rams must be capable of shearing the tubing string being run with the lines on the OD. 2)

Run multiple flat-packs with at least 2 inches of space between them. NOTE: This may require a redesign of the cable clamps.

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3) 27.2

Use a closing pressure of at least 2,000 psi on the annular BOP.

GAS WELLS POLICY

The following SHALL BE required 1) A downhole barrier 2) Kill weight mud 3) The use of Shear Blind Rams on ALL smart well and PDHMS completions are required when deep set control lines or flat packs are utilized. NOTE: The Shear Blind Rams must be capable of shearing the tubing string being run with the lines on the OD. 4) Run multiple flat-packs with at least 2 inches of space between them. 5) Use a closing pressure of at least 2,000 psi on the annular BOP.

28.0 SETTING BRIDGE PLUGS Bridge plugs are often set to serve as downhole barriers. Bridge plugs, after being tested (positive and negative tests), may be considered a mechanical barrier. They are normally run and set in kill weight mud positively tested then the hole above them is circulated to lighter fluid for the negative test. If the well is not circulated back to kill weight fluid and the plug fails while tripping out, a pipe light condition could occur which, if encountered, may not be controllable. POLICY:

The following SHALL BE required 1) 2) 3) 4) 5)

Bridge plugs will be run in kill weight fluid Perform positive test Perform negative test Well circulated back to kill weight fluid before tripping out of hole. Bridge Plug must incorporate Elastomer seals and 2 slip sets rated for the well conditions. The Slips must prevent plug movement and achieve positive anchoring.

29.0 PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS 29.1

REQUIRED NUMBER OF MECHANICAL BARRIERS OF ISOLATION POLICY

All wells on the same platform shall be shut-in prior to workover operations using two (2) mechanical methods of isolation, BARRIER 1 CLOSED AND TESTED SURFACE CONTROLLED SUB-SURFACE SAFETY VALVE. AT SURFACE CLOSED MASTER VALVE

*

Prior to moving in a rig, insure that the above referenced barriers are in place and effective.

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CHAPTER E: WELL CONTROL DRILLS TABLE OF CONTENTS 1.0

2.0

3.0

PIT DRILLS 1.1

Equipment

E-2

1.2

Frequency

E-2

1.3

Procedure

E-3

TRIP DRILLS 2.1

Frequency

E-4

2.2

Procedure

E-4

ACCUMULATOR DRILL 3.1

Procedure

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INTRODUCTION Shutting-in the well quickly to minimize the size of the influx is a major element of successful well control. Drilling crews can only get proficient in this action through training and practice. The Drilling Foreman should ensure that the Contract Tool-pusher administers training in the areas of kick detection and shut-in procedures until proficiency is demonstrated. The training must be repetitive and frequent enough so that shutting-in the well becomes automatic whenever a kick is detected. The Drilling Foreman can judge the level of crew shut-in proficiency through the use of pit drills and trip drills. These drills should always be coordinated with the Contract Tool-pusher. Proper drills and training can prevent panic and provide for orderly operation if a kick should occur. The following discussions describe how to conduct the drills and provide a basis for crew evaluation.

1.0

PIT DRILLS The pit drill is designed to simulate an actual kick while drilling ahead and is designed as both a teaching and a testing tool. While drilling ahead, it teaches the drilling crews to be alert for positive indicators of a kick and provides practice in the proper Saudi Aramco shutin procedures. It also defines and reinforces the assigned duties of every member of the drilling crew in well control situations. Pit drills are conducted unannounced so that realism is created and so the crews can be observed under actual operating conditions. Pit drills train the Driller to be constantly aware of the fluid level in the mud pits and the return mud flow, much as the driver of an automobile subconsciously checks his speedometer. This training is expected to prepare the driller to detect a kick at the first surface indication and with a minimum of reservoir fluid influx. He will then be able to take correct preventive action, lessening chances of disaster. Pit drills should be supervised by the Contract Tool-pusher and coordinated through the Drilling Foreman.

1.1

Equipment All equipment required for pit drills is to be installed prior to drilling and kept in good operating condition. A multi-float pit level indicator and flow show device must be available. A pre-arranged horn or siren signal is an essential part of the pit drill. At the signal, each crewmember must go immediately to his assigned post and execute his assigned duties. The Drilling Foreman should note the times required (in minutes) for various aspects of the pit drills and record them on the tour report. The number and times for these drills should be relayed to the office.

1.2

Frequency One or more pit drills should be conducted each day until the crews become proficient; then at least twice weekly per crew, or more often if deemed advisable by the Drilling Foreman. Pit drills should be held at least one each day on offshore wells, wildcats, and wells where above-normal bottom hole pressure could exist. New drillers should be given special drills and thorough explanation of this practice. It is one of the most important safety measures that can be initiated and followed.

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Drills are to be conducted during both routine and special operations. Typical times would be while drilling, shut down for equipment repairs, logging, waiting on orders, circulating, the Driller has gone to eat and is replaced by one of his men, the Driller is talking to someone, or any other time there is open hole and blowout preventers installed. 1.3

Procedure 1)

The Tool-pusher simulates the kick by raising a float in the mud pits or by raising the arm on the flow show indicator and making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.

2)

The Driller must detect the kick and sound the alarm. The time of the alarm should be noted. Upon hearing the alarm, all members of the drilling crew should immediately execute their assigned duties.

3)

The Driller should prepare to shut in the well using the approved Saudi Aramco Shutin Procedure While Drilling. The Drilling Foreman should be on the rig floor to announce to the driller that the exercise is only a drill and to stop him before he actually closes the blowout preventers. The time should be noted when the driller is prepared to shut in the well.

4)

Members of the drilling crew should report back to the rig floor having completed their assigned duties. These duties may include: Driller  Shut in the well (simulated)  Record drill-pipe pressure and casing pressure  Record time  Measure pit gain  Check choke manifold for valve positioning and leaks Derrick-man  Weigh sample of mud from suction pit  Check volumes of barite, gel, and water on location Floor Hand #1  Check accumulator pressures and pumps  Check BOP stack for leaks and proper valve positions  Turn on water jets to diesel exhausts Floor Hand #2  Assist Driller on rig floor Floor Hand #3  Assist Derrick-man on mud pits

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2.0

TRIP DRILLS The trip drill is designed to train the drilling crews to recognize and respond to kick indications, which occur while tripping pipe. Like the pit drill, the trip drill is useful for both teaching and testing purposes. The pit drill also proves that essential detection equipment is installed and in good operating condition. The trip drill is supervised by the Contract Tool-pusher with the knowledge of the Saudi Aramco Drilling Foreman. All parts of the well control system must be kept hooked up and in good condition, ready for drills.

2.1

Frequency When a new rig is picked-up, trip drills should be conducted during each trip (both while pulling out and going into the hole) while the bit is up in the casing. When the crew becomes proficient, trip drills should be conducted at least twice weekly per crew, conditions allowing.

2.2

Procedure 1)

The Tool-pusher simulates the kick by raising a float in the mud pits and making a note of the time. The Drilling Foreman should assist in observing the crew and recording completion times.

2)

The Driller must detect the kick and sound the alarm. The time of the alarm should be noted. Upon hearing the alarm, all members of the drilling crew should immediately execute their assigned duties.

3)

The Driller should prepare to shut in the well using the approved Saudi Aramco Shutin Procedure While Tripping. This will include spacing out and stabbing/closing the full open safety valve. After the safety valve is installed and the Driller is ready to close the preventers, the Drilling Foreman should announce to the Driller that the exercise is only a drill and that it is not necessary to close the preventers. The time should be noted when the driller is prepared to shut-in the well.

4)

Members of the drilling crew should proceed with their assigned duties and report back to the rig floor upon completion. These duties may include: Driller  Shut in the well (simulated)  Record drill-pipe and casing pressure  Record time  Measure pit gain  Check choke manifold for valve positioning and leaks Derrick-man  Weigh sample of mud from suction pit  Check volumes of barite, gel, and water

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Floor Hand #1  Check accumulator pressures and pumps  Check BOP stack for leaks  Turn on water jets to diesel exhausts Floor Hand #2  Stab safety valve. Close safety valve  Stab inside BOP. Open safety valve  Assist Driller on rig floor Floor Hand #3  Assist Derrick-man on mud pits

3.0

ACCUMULATOR DRILL Accumulator drills are designed to verify that the accumulator/closing system is in good working order and that it is properly sized for the particular blowout preventer stack. Accumulator performance must be proven with an accumulator drill when the blowout preventers are first installed (which verifies proper sizing). After initial installation, the accumulator unit performance will be proven and verified in conjunction with the BOP pressure tests schedule (which checks for hydraulic leaks). Results of the accumulator drill, including closing times of the rams and annular preventer, and initial final accumulator pressures are to be reported on the Blowout Preventer Test and Equipment Checklist. A notation should also be made on the tour report that an accumulator drill was conducted. Accumulator drills must be conducted when the drill pipe is not in open hole, but up in the casing. At least one joint of drill-pipe must be in the hole for the pipe rams to close on. The Saudi Aramco Drilling Foreman and Contract Tool-pusher should witness all accumulator drills, but the Tool-pusher is responsible for the actual supervision of the drill. Use the remote station to close the preventers every other drill.

3.1

Procedure 1)

Turn off all accumulator-pressurizing pumps.

2)

Record the initial accumulator, manifold, and annular pressures.

3)

Close all of the preventers (except the blind rams). Substitute a re-opening of a pipe ram to simulate the blind ram closure when applicable. Open the HCR valve.

4)

Measure and record the closing times for each preventer with a stopwatch.

5)

Record the final accumulator, manifold, and annular pressures.

6)

To pass the accumulator test, all BOP’s must have closed in less than 30 seconds with at least:

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

1500 psi accumulator pressure remaining (for a 3000 psi accumulator) Note: Equipment that does not meet these requirements either has insufficient capacity, insufficient pre-charge or needs repair. Closing time for annular preventers 20" and larger should not exceed 45 seconds.

7)

Observe the remaining pressure for at least 5 minutes to detect any possible am piston seal leaks.

8)

Turn the accumulator pump(s) back on. Record the time required to charge system back up (re-charge time).

9)

Open BOP’s.

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