Drilling & Work Over Manual-2014

SAUDI ARAMCO Back

DRILLING AND WORKOVER WELL CONTROL MANUAL VOLUME I 5th EDITION, June, 2014

Saudi Aramco Well Control Manual Volume I, 5th Edition

CHAPTER A

INTRODUCTION AND DOCUMENT CONTROL EQUIPMENT REQUIREMENTS

CHAPTER B

BOP SYSTEMS

CHAPTER C

MAINTENANCE, TESTING AND RECERTIFICATION

CHAPTER D

WELL CONTROLLED POLICIES

CHAPTER E

WELL CONTROL DRILLS

CHAPTER F

SUPPLEMENTAL REFERENCES

WELL CONTROL MANUAL: 5TH EDITION

VOLUME I

Drilling & Workover

INTRODUCTION AND DOCUMENT CONTROL

1.0

INTRODUCTION th

th

The 5 edition of the Well Control Manual has some significant changes from the 4 Edition. It is the responsibility of the authorized users of this manual to familiarize themselves with the specifications and instructions in its entirety.

2.0

REVISIONS

The Well Control Manual (WCM) will undergo a full review and revision every three (3) years. The WCM will be reviewed by the Well Control Committee (WCC), endorsed by the General Manager of Drilling and approved by the Vice President of Drilling and Workover. Document Control: The Well Control Manual (WCM) is subject to constant review, revision and updates by the Well Control Committee (WCC). The timely implementation of the policies contained in this document is critical and steps must be taken to ensure that the latest revision including published errata and amendments is available to Drilling and Workover Rigs and Management. Revisions and Updates will be controlled as follows: 1 The WCM will be fully reviewed and reissued after three (3) years. 2 Interim revisions and updates will be issued as errata or amendments as required. 3 A revision log will be maintained at the beginning of the WCM that will list and summarize any changes To ensure that the document is available to all concerned parties there will be two (2) versions of the manual available, Electronic and Printed. Electronic Version: The Electronic version will reside on the Drilling Information Highway. This document is available for viewing by all authorized DIH users. If a page or section is printed from DIH, it is considered uncontrolled as of the print date. Printed Version: Printed copies will be issued as follows: • V.P. D&WO • General Manager, Drilling • All D&WO Managers • All Drilling and Workover Rig Superintendents • All Members of the Well Control Committee. • All rigs operating under Drilling and Workover will have one copy in the Foreman’s Office. • Each Drilling or Workover Rig Contractor’s local head office. • D&WO Contracts Administration Division Updates and Revisions to printed copies will be controlled as follows: 1. When errata or an amendment is issued a notification will be sent to all D&WO personnel. The master electronic copy on the DIH will have the errata and amendments placed at the beginning of the file.

Current Revision: JUNE, 2014 Previous Revision: MAY, 2010

INT - 1

WELL CONTROL MANUAL: 5TH EDITION Drilling & Workover

VOLUME I

CHAPTER A - EQUIPMENT SPECIFICATIONS AND REQUIREMENTS

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-5

1.3

Fixed Ram Preventers and Elastomers

A-5

1.4

Variable Bore Ram Preventer Blocks and Elastomers

A-6

1.5

Shear Blind Ram (SBR) Blocks and Elastomers

A-6

1.6

Valve Removal Plugs and Blind Flanges on BOP Side Outlets

A-8

1.7

Drilling Spools

A-8

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

Minimum Bore Size for Lines:

A-9

2.2

Material and Fabrication

A-9

2.3

Requirements for Drilling Chokes

A-11

2.4

Requirements for Valves

A-11

2.5

Requirements for Cup Testers

A-12

ACCESSORY BOP EQUIPMENT REQUIREMENTS 3.1

Pit Volume Totalizers

A-12

3.2

Mud Flow Indicators

A-12

3.3

Gas Busters

A-12

3.4

Full Opening Safety Valves

A-17

3.5

Inside BOP

A-17

3.6

Trip Tank

A-18

3.7

Bowl Protectors (Wear Bushings)

A-19

3.8

Valve Removal Plugs

A-19

3.9

Drillpipe Float Valves

A-19


A-1


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3.10 Weco Connections

A-19

3.11 Chiksans

A-19

3.12 Accumulator Closing Units

A-20

3.13 Stroke Counters

A-22

3.14 Gas Detectors

A-22

3.15 Drill Rate Recorders

A-22

3.16 Pump Lines for Existing Offshore Well Kill

A-23


A-2


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1.0

WELL CONTROL EQUIPMENT SPECIFICATIONS AND REQUIREMENTS

This Chapter of the Well Control Manual sets forth the specifications and requirements for Blow Out Prevention Equipment (BOPE) and systems for use in Drilling and Workover Operations. Variations or deviations of BOPE, specifications, arrangement, pressure rating or requirements from this standard requires endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling or Workover Rig Superintendent. The Rig Foreman shall ensure that the proper equipment is available and correctly installed. If not specified in these standards all BOP equipment shall comply with API Specifications and Recommended Practices. 1.1

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

All BOPE (Annulars, Ram Type, Valves, Chokes, Crosses Flexible Lines, Hard Lines and etc.) shall be of forged material, Monogrammed to API Specification 6A, 16A, 16C, 17D or other applicable API Specification as appropriate. 1)

All equipment in service in Saudi Aramco D&WO Operations must be API Monogrammed. This includes equipment transferred from other regions whether or not it is on a rig already. Monogram and markings MUST be clearly visible through the painted coating of the equipment. Care should be taken to preserve this monogram on the equipment nameplate, flange or body to prevent it being obliterated or destroyed during handling maintenance and use. Additionally, documentation must be available at the rig site reflecting the equipment Serial Number and API Monogram Status.

2)

Any exceptions to this monogram policy (e.g.; 30" 1,000 psi annulars) are noted in the section detailing that specific equipment.

1.1.2

All major BOPE components including, but not limited to, ram BOPs, annular BOPs, drilling spools, ram blocks, valves, choke and kill lines, choke manifolds, gas busters etc. will have an unique serial or asset identification number assigned at time of manufacture by the ORIGINAL EQUIPMENT MANUFACTURER (OEM). The number must be permanently marked in the metal of the component body and should be paint stenciled in a prominent and visible location on the equipment. This number must be referenced on all accompanying certification and recertification documents. Repair numbers are not acceptable for this requirement.

1.1.3

Only OEM parts are acceptable when repairing or redressing the BOP, valves, chokes, and closing units. Documentation (e.g.; PO, invoice, certificate of compliance etc.) must be maintained for all parts verifying that they are OEM.

1.1.4

Maintenance and testing requirements may be found in Chapter C "Maintenance Testing and Certification Requirements” of this manual.

1.1.5

A drilling spool is preferred for primary choke and kill line installation. However in special cases, such as space limitation, preventer side outlets may be used in lieu of a drilling spool. The diameter of all preventer side outlets must be at least as large as the choke manifold lines. NOTE: Side outlets are used for installation of the lower choke and kill lines on 10K/15K BOPs.


A-3

© Copyright 2014, Saudi Aramco MBG


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1.1.6

The through-bore size of the preventer stack, tubing head, and any adapters used in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner hanger, packer, plug, cup tester, bowl protector or any other large diameter down-hole tools to be run in the well.

1.1.7

The pressure rating of all pressure control equipment (BOP, Valves, Lines etc.) must be greater than the MASP (Maximum Anticipated Surface Pressure).

1.1.8

The inboard manual valves on the choke and kill lines are considered master valves and normally would not, except for pressure testing, be closed unless the outside valve (HCR) has failed.

1.1.9

Check valves must be installed on normal kill lines but shall not be used on emergency kill lines.

1.1.10 The kill line, emergency kill line and choke lines should be flushed and washed out frequently to prevent mud solids settling. 1.1.11 BOP assemblies will be dismantled between wells to inspect for internal corrosion, erosion and to check flange bolts. Refer to Chapter C for maintenance procedures and requirements. 1.1.12 All Rigs shall maintain a logbook of BOP schematics detailing the components installed. The logbooks shall contain the part number, size, description, serial number (if applicable) and installation date of ram blocks, top seals, ram and annular packers and bonnet or door seals. This is be witnessed and co-signed by the Toolpusher and the Saudi Aramco Representative (see form #1 in Chapter C) of this manual). 1.1.13 All ram preventers must be equipped with manual or automatic locking devices, which must be locked whenever the rams are used to control the well. Hand crank, wrench or hand wheel systems are acceptable manual locking devices. 1.1.14 All preventers and associated equipment must meet NACE MR-0175/ISO 15156, API Specification 6A, 16A or 16C for sour service. 1.1.15 A full OEM certification or recertification of the BOP, choke manifold (including chokes) and all related equipment must be performed at the start of the contract and least once every three years thereafter. The recertification must be in accordance with the relevant API Specification for repair/remanufacture. The documentation package shall be kept with the equipment and must be available for inspection at the rig site by Saudi Aramco personnel. This includes, but is not limited to:      

Ram preventers. Annular preventers. Valves on the kill, emergency kill, choke line and choke manifold. Drilling chokes. Kill, emergency kill and choke lines (and line components) including both hard line and flexible hoses. Drilling spools.

NOTE: Recertification can only be performed by the OEM or their licensee facility. If recertified by a licensee, the document package shall include a copy of the license issued by the OEM. In-field recertification is not acceptable.


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VOLUME I


NOTE: New equipment shall be accompanied by the manufacturer's certificate of compliance and a full documentation package including inspection and test reports. 1.1.16 All BOPE including, but not limited to, annulars, ram type, valves, spools, crosses, tees and other end and outlet connections with working pressures of 3,000 psi and above shall have flanged, welded, integral, or hubbed connections only. Threaded connections and threaded connections that have been seal welded are not permitted. 1.1.17 All Ram Type BOP cavities MUST CONTAIN a Ram. Vacant Ram cavities during operations are not permitted.

1.2

Annular Units and Diverters: 1.2.1

All annular units must comply with the following in addition to the requirements in Section 1.1.

1.2.2

The minimum acceptable ratings for H2S and temperature are as follows, 2,000 3,000 5,000 10,000

psi and less psi equipment psi equipment psi equipment

2.5% H2S and 0-170°F 2.5% H2S and 0-180°F 2.5% H2S and 0-180°F 2.5% H2S and 0-180°F

1.2.3

The acceptable annular manufacturers are Cameron, GE-Hydril and NOV-Shaffer.

1.2.4

GE Vetco KFDJ and Dril-Quip MD diverters are acceptable for offshore 500, 1,000 and 2,000 psi service. Dril-Quip, is currently the only approved design, for the 500 psi onshore diverter. NOTE: The Dril-Quip onshore diverter is not eligible for API Monogram and is not subject to the 3-year recertification requirement. Only repair after each nipple-up is required.

1.3

1.2.5

If a rotary diverter system is utilized on an offshore rig, the diverter lines must have the capability of discharging below the bottom of the hull due to H2S concerns.

1.2.6

Bolted, latched and screwed top annulars are acceptable.

1.2.7

30 inch 1,000 psi annulars may not be monogrammed under API specification 16A. These annulars are exempt from the monogram requirement.

Fixed Ram Preventer Blocks and Elastomers: 1.3.1

All fixed ram preventers must comply with the following in addition to the requirements in Section 1.1 above.

1.3.2

Only fixed size rams are acceptable as the master pipe ram (bottom ram) on all BOP stacks.

1.3.3

The minimum acceptable ratings for H2S and temperature for ram assemblies are: 3,000 5,000


psi stack psi stack

5.0% H2S and 0-250°F 10.0% H2S and 0-250°F A-5



VOLUME I


10,000 15,000 1.3.4

psi stack psi stack

20.0% H2S and 0-300°F 20.0% H2S and 0-300°F

Cameron, NOV-Shaffer and GE-Hydril are acceptable manufacturers for ram preventers. All ram assemblies shall meet NACE Standard MR-01-75-2000 for sour service.

NOTE: Fixed size ram preventers CANNOT CLOSE on TOOL JOINTS 1.3.5

1.4

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.

Variable Bore Ram Preventer Blocks and Elastomers: 1.4.1

All variable bore ram preventers must comply with the following in addition to the requirements in Section 1.1 above.

1.4.2

Variable bore rams (VBR) are optional for tapered drill string applications on Class ‘A’ stacks. In all cases the master pipe ram (bottom ram) must be a fixed ram.

1.4.3

The minimum acceptable ratings for H2S and temperature for VBR's are: 3,000 5,000

1.4.4

psi stack psi stack

5.0% H2S and 0-250°F 10.0% H2S and 0-250°F

The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8” pipe sizes) for the Cameron 13-5/8” U Type blowout prevented is acceptable for 3,000 and 5,000 psi o applications ONLY. This VBR was successfully tested to 250 F with a CAMLAST elastomer rated for 20% H2S. NOTE: The Cameron ER-HT VBR-II, described above, is approved for use in 3M and 5M Class 'A' BOPs. This is the ONLY APPROVED VBR.

1.5

Shear Blind Ram (SBR) Blocks and Elastomers: 1.5.1

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

Close Proximity Wells (All Wells in Populated Areas) Gas Cap Wells (Either 3,000 or 5,000 Class ‘A’ Stacks) Onshore Class ‘A’ 5,000 psi stacks (Expl./Dev. Wells >10 % H2S) Smart Well Completions and Downhole monitoring systems where more than one (1) line is run on the OD of the tubing. ESP Completions in areas where the well can flow naturally Offshore Class ‘A’ 5,000 psi stacks (Offshore Wells) Class ‘A’ 10,000 psi stacks (Deep Gas Exploration and Development Wells) Class 'A' 15,000 psi stacks (Deep Gas Exploration and Development Wells)


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VOLUME I


1.5.2

The minimum acceptable ratings for H2S and temperature for SBR's are: 3,000 psi stack 5.0% H2S and 0-250°F 5,000 psi stack 10.0% H2S and 0-250°F 10,000 psi stack 20.0% H2S and 0-300°F 15,000 psi stack 20.0% H2S and 0-300°F

1.5.3

Approved Shear Blind Rams are as follows:   

Cameron Shearing Blind Rams Shaffer V-Shear, T-72 and LFS (Low Force Shear) Rams Hydril Blind/Shear Rams

1.5.4

All rigs utilizing SBR in 3,000 and 5,000 psi BOP equipment shall have a 3” emergency kill line. This will provide additional kill line capacity in case the SBR does not make a proper seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard manual valve shall be 2” with DSA back to 3”. Rigs with 10,000 psi and higher BOP equipment shall have dual choke and kill lines as specified in Chapter B.

1.5.5

Shear Blind Rams are normally installed in Class A BOP stacks. When installed they will be in the position immediately above the drilling cross as detailed in the individual stack configurations shown in this manual. They may be used on Class B BOP stacks on close proximity wells to allow the utilization of smaller rigs. When installed in Class B stacks, the configuration must be a fixed pipe ram in the bottom position, a drilling cross above that, the SBR and then the annular. NOTE: Double rams may not be used in conjunction with SBR’s on a Class B stack. NOTE: SBR’s are only to be used during testing and a well control incident. They shall not be used to close the well when out of the hole. A steel hole cover (minimum ¼” thick with locating pins) should be available on the rig floor to cover the rotary when pipe is out of the hole.

1.5.6

The tables below indicate the shear capability of SBR for different BOP manufacturers, sizes and pressure applications. NOTE: Shear Blind Rams CANNOT BE CLOSED ON TOOL JOINTS.

SHEAR BLIND RAM CAPABILITY 10,000 - 15,000 PSI SERVICE BOP SERVICE

DEEP GAS EXPL/ DEV.

BOPE SIZE - WP CLASS

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

MFG.

CAMERON (1)

SHAFFER (1) 11" 10M CLASS 'A'

CAMERON (1)

SHAFFER (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" 19.5# G-105 ALL SIZES TO 5" 25.6# G-105

A-7

REQUIRED SHEAR BLIND RAM TYPE

OPERATOR REQUIRED SIZE

'SBR' 'V'

SIDE PACKER

YES/ LBT (2)

TEMP (0F) 0-300

H2S, (%) 20

14"/10" (3)

0-300

20

0-300

20

0-250

20

'SBR'

YES/ LBT

'T-72'

14"/10" (3)

(2)



VOLUME I


NOTE: (1) (2) (3)

CAMERON, HYDRIL AND SHAFFER ARE APPROVED MANUFACTURERS. CAMERON - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS. NOV SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.

3,000 - 5,000 PSI SERVICE BOP SERVICE

BOPE SIZE - WP CLASS

OFFSHORE ONSHORE EXPL/DEV. w/ H2S > 10% GAS CAP WELL POPULATED AREAS

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

1.6

DRILL PIPE SHEAR CAPABILITY

ALL SIZES TO 5-1/2" 24.7# G-105 DUAL TUBING STRINGS ALL SIZES TO 5-1/2" 24.7# G-105

REQUIRED SHEAR BLIND RAM TYPE

OPERATOR REQUIRED SIZE

'SBR'

YES/ LBT (2)

'V'

14"/10" (3)

ALL SIZES TO 'SBR' YES/ LBT (2) 5" 19.5# G-105 SHAFFER (1) ALL SIZES TO 'T-72' 14"/10" (3) 5" 25.6# G-105 CAMERON, HYDRIL AND SHAFFER ARE APPROVED MANUFACTURERS. CAMERON - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS. SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.

CAMERON (1)

SIDE PACKER TEM P (0F) 0-250

TE MP (0F) 20

0-250

20

0-250

20

0-250

20

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:

 

1.7

CAMERON (1)

SHAFFER (1) 11" 3-5M CLASS 'A'

NOTE: (1) (2) (3)

MFG.

Flanges installed on the side outlets of ram preventers that do not have VR plugs installed shall be blind with no penetrations. Flanges installed on the side outlets of ram preventers that have VR plugs installed shall have a ½ inch NPT or an Autoclave tap (depending on the pressure rating) and have a plug installed.

Drilling Spools: 1.7.1

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

Monogrammed to API Specification 6A or 16A PSL-2 (5,000 psi working pressure or lower) PSL-2 with PSL-3 Gas Test (10,000 psi working pressure or higher) PR-1 (or better) MR-DD (or better) TR-U (5,000 psi working pressure or lower) o TR-X Suitable for 350 F service (10,000 psi working pressure or higher) Forged bodies


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2.0

REQUIREMENTS FOR KILL, EMERGENCY KILL, CHOKE LINES AND CHOKES All Kill, Emergency Kill and Choke lines shall comply with the following in addition to Section 1.1.

2.1

The Minimum Bore Size for Kill, Emergency Kill and Choke Lines Shall Be As Follows: KILL LINE Nominal Size/Bore (in) 2-1/16" 2-1/16" 3-1/16"

Working Pressure (psi) 3,000 and 5,000 10,000 15,000

EMERGENCY KILL LINE Nominal Size/Bore (in) 2-1/16" 3-1/8" (with SBR) 3-1/8" (with SBR) 2-1/16" 3-1/16"

Working Pressure (psi) 3,000 and 5,000 3,000 5,000 10,000 15,000

CHOKE LINE Nominal Size/Bore (in) 3-1/8" 3-1/8" 4-1/16"

Working Pressure (psi) 3,000 5,000 10,000 and 15,000

2.1.2

2.2

The complete piping system, valves, chokes and choke manifold will be the full working pressure of the BOP through the block valves downstream of the chokes and the Choke Manifold Buffer Chamber.

Material and Fabrication: 2.2.1

The lines from the BOP stack to the choke manifold shall have the same working pressure (or greater) as the BOP stack. All lines shall meet Sour Service requirements for API Specifications 6A and 16C.

2.2.2

Choke lines for 3M and 5M applications shall be either steel pipe, flexible hose or a combination of these.

2.2.3

Choke lines for 10M and higher applications shall be either steel pipe or a combination of hard line and flexible hose.

2.2.4

Flexible steel hose if used in combination flanged hard line may be used for the choke, kill and emergency kill lines on 3M through 15M applications provided the following requirements are satisfied: 

Made by an approved manufacturer as listed in section 2.2.7 below.


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

All components of the hose and end fittings in possible contact with wellbore fluids meet Sour Service NACE MR-01-75/ISO 15156 (latest revision)

2.2.5

All lines and end connections shall be pressure tested and Monogrammed as per API specification 6A, 16C or 17D as appropriate.

2.2.6

Steel line material shall meet the requirements of API specification 6A or 16C for H2S service.

2.2.7

Flexible choke and kill lines shall be monogrammed to API Specification 16C. approved flexible choke and kill lines are:   

The only

Technip/Coflexip (coflon lined) Continental Contetich-Thermo plastic lined (only allowed in 5,000 psi and lower service) Phoenix HNBR (only allowed in 5,000 psi and lower service) NOTE: The Phoenix HNBR hose has the following limitations in chemical compatibility: Product compatibility of HNBR lined Phoenix Rubber hoses

(choke and kill hoses acc. to API Spec. 16C 07 C draft &hoses c\w st. st. internal carcass acc. to API Spec. 17K)

Medium Concentration Hydrochloric acid HCl 15% Hydrofluoric acid HF 0.6% Xylene C6H4 (CH3)2 25% Methanol CH3OH 100% Zinc bromide ZnBr2 Saturated Calcium bromide CaBr2 Saturated Calcium chloride CaCl2 Saturated Diesel 100% Sea water --Sodium hydroxide NaOH 50% Hydrogen sulfide H2S 20% (+) Suitable, (-) Not Suitable, (L) Limited Service

0oF -18oC + + + + + + + + + L +

75oF 24oC + + + + + + + + + L +

150oF 66oC + L L L L + + +

200oF 93oC L L L L L + +

250oF 121oC L L L L L +

2.2.8

Field welding is not permitted on choke and kill lines. These must be welded in an API licensed shop to a qualified welding procedure and must, at a minimum, pass hardness tests (HRC 22 or less) and radiography of the welds.

2.2.9

All choke and kill lines shall be as straight as possible with targeted, block tees at turns. The tees will be lead targeted with renewable target flanges. Welded or threaded tees are not acceptable. NOTE: Threaded tees that are seal welded are NOT ALLOWED in any service. NOTE: Chiksans are not acceptable for kill line, emergency kill line or choke line.

2.2.10 All kill, emergency kill, choke and choke manifold connections should be flanged, API licensed factory welded, integral or hubbed and shall be monogrammed to API Specification 6A.


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2.3

Requirements for Drilling Chokes: 2.3.1

A remote controlled hydraulic choke(s) shall be installed on each manifold. All chokes used in Saudi Aramco service must be from one of the approved models listed below. Acceptable models are:   

SWACO 'Super Choke' Cameron Drilling Choke NOV Shaffer Drilling Choke

NOTE: Choke makes and models not listed above will not be accepted. 2.3.2

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

2.4

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) o TR-X Suitable for 0-350 F service (10,000 psi working pressure or higher) Forged bodies and bonnets Alloy 625 or better, inlaid ring grooves

Requirements for Manual Gate Valves, Hydraulic Gate Valves and Check Valves: 2.4.1

Manual Gate Valves shall be non-rising stem, single slab floating gate valves with one-piece seat design (Body Bushings Not Allowed). Split gates or valves with floating or two-piece seats that can pressure lock are not acceptable. Nitrile/Buna Elastomer Seals are not allowed. PTFE/PEEK Based Seals are acceptable. Manufacturers are not specified for contractor owned manual gate valves, however, it should be noted that each valve must be re-certified by the OEM at contract start-up and every three (3) years thereafter. Hydraulic Controlled Remote (HCR) Gate Valves will be required to meet the same specification with the exception of the Stem. HCR Gate Valves are allowed to incorporate a rising stem and a balance stem on the bottom of the valve body. Approved Hydraulic Valve Manufacturers: Cameron (all sizes), Axon (7-1/16” only).

2.4.2

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

2.4.3

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher) PSL-2 (or better) (5,000 psi and lower) PR-1 (or better) MR-DD (or better) TR-U (5,000 psi working pressure or lower) o TR-X suitable for 0-350 F service (10,000 psi working pressure or higher) Forged bodies and bonnets

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

Monogrammed to API Specification 6A PSL-2 (or better) with PSL-3 Gas Test (10,000 psi and higher)


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        2.5

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) o TR-X suitable for 0-350 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.

Requirements for Cup Testers: 2.5.1

Cameron Type ‘F’ cup testers are the only approved model. All elastomers and other parts must be OEM.

3.0

ACCESSORY BOP EQUIPMENT REQUIREMENTS

3.1

Pit Volume Totalizers:

3.2

3.3

3.1.1

All rigs shall have a pit volume totalizer installed. These should be kept on at all times, even when out of the hole, changing bits or logging.

3.1.2

Charts and, or, warning devices (horn, lights etc.) should be installed at the Drill Floor, Mud Logging unit and the Toolpushers or Drilling Representative's office.

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.

Gas Busters: 3.3.1

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

3.3.2

The vent lines must meet the following requirements:   

Lines will be 8” minimum OD flanged or clamped steel line (minimum of 240’ in length, from the gas buster) Same pressure rating (or greater) than that of the gas buster. Shall terminate in a flare pit, positioned 50’ beyond the edge of the reserve/waste pits to prevent ignition of any waste hydrocarbons while circulating gas from the wellbore.

3.3.3

The gas buster design for ‘deep gas rigs’ is shown in Figure A-3.1 The minimum internal capacity for Gas Rig gas busters is 35 barrels.

3.3.4

The gas buster design for ‘oil development rigs’ is shown in Figure A-3.2 The minimum internal capacity for Oil Rig gas busters is 17.5 barrels.

3.3.5

Gas busters should be cleaned out periodically.


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3.3.6

Never circulate cement returns through a gas buster.

3.3.7

Gas busters have a tendency to shake and rattle when they are in use. securely anchored.

3.3.8

All gas busters shall be built in compliance to ASME Boiler and Pressure Vessel Code, Section VIII, Division I, with all materials meeting requirements of NACE Standard MR-01-75/ISO15156 (Latest Revision). All welding on the vessel shall meet ASME requirements. New gas busters shall be hydrostatically tested to 190 psi to give a maximum working pressure of 150 psi, as per ASME.

They should be

INTENTIONALLY LEFT BLANK


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FIGURE A-3.1: Mud Gas Separators for Gas Service 3.3.9

There should be a by-pass line upstream of the separator directly to the flare line and a valve on the separator inlet line to protect the separator from high pressure.

3.3.10 The mud discharge line from the separator must have a vacuum breaker stacked vent line if the discharge line outlet is lower than the bottom of the separator. This is to prevent siphoning gas from the separator to the mud pits. The vacuum breaker stack must be as high as the separator.


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3.3.11 MGS/Gas Buster must be fully inspected and tested every five (5) years. Inspection will include full visual, Pressure Testing, 100% Magnetic Particle or Dye Penetrant NDE and Ultra Sonic to determine the integrity of the wall thickness. Additionally, Inspection Documentation with 3 year validity must be submitted at new rig start-up as well as for rig contract renewal.



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FIGURE A-3.2: Mud Gas Separators for Oil Service Current Revision: JUNE, 2014 Previous Revision: MAY, 2010

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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 appropriate cross-over are also required when running casing and tubing.

3.4.3

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

NOTE: Full Open Safety and Kelly valves must be designed and manufactured in compliance with API Spec 7-1. The term 'full opening' does not mean that the ID of the valve is the same as the pipe, but rather that the bore through the valve is not restricted. 3.5

Inside BOP: 3.5.1

An inside BOP to fit each size of drill pipe and drill collar in use will be kept in the open position on the rig floor.

NOTE: Inside BOP must be designed and manufactured in compliance with API Spec 7-1.



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3.6

Trip Tank: 3.6.1

A circulating trip tank will be used on all rigs while tripping out of or back into the hole.

3.6.2

The trip tanks shall have two (2) 60 barrel compartments.

3.6.3

There shall be two (2) independent measuring devices, a mechanical float operated pit level indicator graduated in inches and an electro-mechanical device.

FIGURE A-3.3: Typical Trip Tank 3.6.4 Calculated versus actual volumes shall be monitored and recorded in a log book recording the following data:    

Volume and weight of slug Number of strokes the slug is pumped. Time for slug to stabilize and flow to stop in the annulus. Amount of mud to fill hole: o 5 Stands for Drill Pipe o 2 Stands for HWDP o Every Stand for Dill Collars

NOTE: If the volume of mud used to fill the hole is not correct for any interval, stop pulling and determine the reason the hole is not taking mud properly.  

Total volume of mud per trip to fill hole (calculated and measured) Leave drill pipe wiper rubbers off pipe for the first five (5) stands to observe hole.


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3.7

Bowl Protectors (Wear Bushings): Bowl protectors, or wear bushings, protect the hanger bowl in the casing or tubing head during drilling operations. 3.7.1

Bowl protectors shall be used in all operations when drilling through the wellhead.

NOTE: Bowl protectors, just like BOP test plugs have a Manufacturer specific profile. protector used must match the Manufacturer and Model of the Wellhead. 3.8

The bowl

Valve Removal Plugs: Valve Removal (VR) plugs are one-way check valves that can be installed through an outlet valve on a casing head, casing spool or tubing spool into a female thread in the outlet for its repair or replacement. Once the valve has been repaired or replaced the VR plug can be removed.

3.9

3.8.1

VR plugs shall be removed from the wellhead in order to have access to the annulus. This should be confirmed prior to nippling up the wellhead.

3.8.2

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

3.8.3

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

Drillpipe Float Valves: Drill pipe float valves shall be run in all Saudi Aramco operations except when planned operations preclude running a float; testing, treating or squeezing. The drillpipe float valve shall be positioned directly above the bit.

3.10

Weco Connections: 3.10.1 Weco connections (other than the remote connections at the end of the catwalk) are not acceptable for kill, emergency kill or choke line service. 3.10.2 Factory Manufactured Integral or butt welded Figure 1502 connections are acceptable downstream of the choke manifold buffer tank for land and offshore operations. Field fabricated connections are not acceptable. 3.10.3 Weco type connections are not acceptable on well test lines upstream of the Choke & Kill Manifold. 3.10.4

3.11

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

Chiksans / Swivel Joint: 3.11.1 Chiksans are sections of pipe with hammer unions and two swivels in each joint. The primary use of chiksans is to run temporary lines for high pressure pumping and cementing operations. 3.11.2 Chiksans shall not be used in kill lines, emergency kill lines or choke lines.


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3.12

Accumulator Closing Units: The brand of closing unit used by the Drilling or Workover Contractor is not specified by Saudi Aramco, however, all closing units shall meet the following requirements. Fluid Requirements: 3.12.1 The accumulator shall store enough fluid under pressure to close all preventers, open the choke HCR valve and retain 50% of the calculated closing volume with a minimum of 200 psi above pre-charge pressure without assistance from the accumulator pumps. Design Requirements: 3.12.2 The accumulators and all fittings will be a minimum of 3,000 or 5,000 psi working pressure depending on the BOP Ram Bonnet working pressure. The Accumulator and all Hydraulic lines from the accumulator to the BOP stack shall be designed and manufactured in accordance with API Specification 16D. All Accumulators and Lines must be manufactured by an API 16D Licensed Facility. Onshore Hoses must be sleeved and shielded externally steel encased (equivalent to Gates 16 EFBOP Blow-Out Preventer Hose). Offshore hoses are not required to be externally steel encased. The hose end connection must be of a winged hammer or hex union style. All piping and connections used from the Accumulator Unit to the BOP must be ASME/ANSI SCH 160 or equivalent. Quick-Connect type connections are not allowed. Manifold and BOP hydraulic lines should be tested to the system working pressure at installation. NOTE: All air and hydraulic BOP operating units shall be equipped with regulator valves similar to the Koomey type TR-5. These will not fail open causing loss of operating pressure. Bottle Pre-Charge Requirements: 3.12.3 Accumulator bottles will be pre-charged with nitrogen as per manufacturer’s specifications/recommendations. The minimum required pre-charge pressure for a 3,000 psi (20.7 MPa) working pressure accumulator unit is 1,000 psi (6.9 MPa). The minimum required pre-charge pressure for a 5,000 psi (34.5 MPa) working pressure accumulator unit is 1,500 psi (10.3 MPa). The nitrogen pre-charge pressure shall be checked and adjusted prior to connecting the closing unit to the BOP stack and any other time the accumulator must be completely de-pressured. 3.12.4 The accumulator should be capable of closing each ram within 30 seconds. Closing time should not exceed 30 seconds for annulars smaller than 18-3/4” nominal bore and 45 seconds for annular preventers of 18-3/4” and larger. Operating Controls: 3.12.5 All operating controls shall be clearly marked with function and ram sizes. Accumulator controls must be in open or closed position, but not in neutral position. During normal drilling operations the HCR valve next to the wellhead will be closed. Unused functions shall be marked “Out of Service”, covered or have the handles removed on the main and remote units. Unused functions shall have the open/close lines plugged at the main unit.


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Accumulator and Controls Locations: 3.12.6 Master Controls shall be at the accumulator. There must be at least two (2) sets of remote controls for operating the accumulator to activate the BOPs and all HCR valves. HCR valves on the choke line, kill line and the C&K manifold shall be powered by the main accumulator unit. One remote control shall be on the rig floor, accessible by and visible to the driller and the other shall be located near the Company Representative’s office. Onshore:

The accumulator shall be located at a remote location, at least 60 feet distance from the wellbore for oil wells and 100 feet for gas wells, shielded from the wellhead and protected from other operations around the rig.

Offshore:

The accumulator shall be shielded from the wellhead and the drill floor and protected from other operations around the rig. It should be located as far as practically possible from the wellhead.

Pump System: 3.12.7 Two pump systems are required. The preferred configuration is to have one electric/hydraulic and the second pneumatic (air)/hydraulic. The primary electric/hydraulic pump system and the secondary pneumatic/hydraulic pump system must be independent of each other and fully operational when the accumulator is in use. The high-pressure set point for both the electric pump and air pump should be 3,000 or 5,000 psi. The low-pressure set point should be above 2,800 psi for both systems. Do not bleed off pressure due to ambient temperature rise. Pressure may vary from 3,000 to 3,400 or 5,000 to 5,400 psi in a 24-hour period. It is permissible to have two independent electric/hydraulic systems. however, they must have separate and totally independent prime movers. Each of the two systems shall have the quantity and sizes of pumps such that, with the accumulators isolated from service, the following steps are completed within two minutes:   

The annular BOP closes on the minimum size drill pipe being used All hydraulically operated valves opened Provide the pressure recommended by the annular BOP manufacturer to effect a seal on the annulus

Pressure Regulator Settings: 3.12.8 The pressure regulators for the annular preventer and ram preventers will be set as per manufacturer’s specification/recommendation. All BOPs with Shear Blind Rams installed shall have a bypass to route full system pressure to the SBR's. NOTE 1 For non-emergency BOP operation, use of the lowest possible pressure will extend elastomer life. Upon completion of the daily testing the pressure regulators shall be returned to the normal operation pressure. NOTE 2 DO NOT close annular preventers on open hole for complete shut-off except in an emergency.


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NOTE 3 DO NOT close pipe rams without pipe in the hole. Pipe rams should only be closed on the proper size pipe in order to avoid damage to the rubber packer or to the ram carriers (DO NOT CLOSE on TOOL JOINTS). Shear Ram Safety Covers and Alarms: 3.12.9 The Shear Blind Ram controls are to have the following safety and alarm features:

3.13



Safety covers (box style) shall be installed over all SBR controls. These covers will be secured with a pin (that must be removed before opening the cover) and will be of a type that must be lifted to operate the control. They should be clear plastic or have observation holes in them so the position lights may be seen. Covers shall be installed on all SBR controls at all remote stations and the accumulator.



The covers shall be fitted with switches that will activate horns and strobe lights when the cover is lifted, before the control is operated. Horns will be installed on the rig floor and at the accumulator. The alarms will be tested during each well control drill and BOP test. The alarms should emit a significantly different sound than the H2S or any other alarms on the rig.

Stroke Counters: Stroke counters provide the Driller a method of measuring fluid volumes when displacing special fluids or lost circulation pills. It is also used to determine pumped volumes when executing well control procedures. 3.13.1 Stroke counters are required on all rigs at both the Driller's station and the choke control console. NOTE: The kill line should not be used in conjunction with the rig pumps and a stroke counter for hole filling purposes. The kill line is an emergency piece of equipment and should not be used for routine hole fill-up during trips.

3.14

Gas Detectors: These devices, usually found in mud logging units, are useful in detecting abnormal pressure sections as well as shows of hydrocarbons. Rig Supervisors should monitor the trip gas, connection gas, and background gas for any significant change. The presence of gas in the mud can be one of the more useful indicators of abnormal pressure. Gas Detector readings can sometimes be misleading, however, and the important things to look for are the relative trends and magnitudes, rather than the individual number of gas units reported.

3.15

Drill Rate Recorders: These devices come in both analogue and digital styles. They are useful as correlation tools, particularly if logs are available from other wells in the area. The records can be used to detect and correlate formation tops and types, as well as in selecting bits and estimating their useful lives. A sudden increase in penetration rate can be one of the first signs of a well kick. 3.15.1 All rigs should have a drill rate recorder.


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3.16

Pump Lines for Existing Offshore Well Kill: Steel chicksan swivel joints, connections and piping may be used for the purpose of killing an existing well with cased hole prior to or after rig arrival. However, only factory Manufactured Integral or butt welded Figure 1502 connections are acceptable.


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CHAPTER B - BOPE SYSTEM CONFIGURATION

CHAPTER B: BOPE SYSTEM CONFIGURATION TABLE OF CONTENTS 1.0

BOP 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


Usage

B-8

3.2


B-8

3.3


B-11


Usage

B-12

4.2


B-12

4.3


B-15


Usage

B-16

5.2

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

B-16

5.3

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

B-18

5.4


B-18

CLASS ‘B’ 3,000 psi BOP STACK 6.1

Usage

B-19

6.2

Class ‘B’ 3,000 psi BOP Stack Arrangement

B-19

7.0

CLASS ‘C’ 3,000 psi BOP STACK

B-21

8.0

CLASS ‘D’ DIVERTER STACK

B-22

9.0

CLASS ‘I’ 2,000 psi WORKOVER STACK 9.1

Usage

B-24

9.2

Class ‘I’ 2,000 psi Stack Arrangement

B-24


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10.0

11.0

12.0

13.0

14.0

15.0

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

B-25

10.2 Class ‘II’ 3,000 psi Stack Arrangement

B-25

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

B-25

11.2 Class ‘III’ 5,000 psi Stack Arrangement

B-26

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

B-26

12.2 Class ‘IV’ 10,000 psi Stack Arrangement

B-26

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

B-26

13.2 Class ‘IV’ 10,000 psi Stack Arrangement

B-26

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

B-26

14.2 BOP Equipment Requirements for Snubbing

B-30

14.3 BOP Equipment Requirements for Electric Line Operations

B-33

CHOKE MANIFOLDS 15.1 15,000 PSI Working Pressure Choke Manifold

B-35

15.2 10,000 PSI Working Pressure Choke Manifold

B-38


B-41


B-43

15.5 Location

B-44

15.6 Choke Manifold Pressure Ratings

B-44

15.7 Piping Specifications

B-44

15.8 Choke Manifold Discharge and Flare Lines

B-44

15.9 Gas Buster Lines

B-46


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1.0 BOP EQUIPMENT SYSTEM CONFIGURATION This Chapter of the Well Control Manual sets forth the configurations for BOP equipment systems for use in Drilling and Workover Operations. All equipment must comply with the other chapters in this manual. Variations or deviations of BOP equipment, specifications, arrangement, pressure rating or requirements from this standard requires endorsement of the Well Control Committee, and approval by the Vice President of Drilling and Workover. The enforcement of these equipment standards shall be the responsibility of the Drilling or Workover Rig Superintendent. The Rig Foreman shall ensure that the proper equipment is available and correctly installed. If not specified in these standards all BOP equipment shall comply with API Specifications and Recommended Practices. The BOP equipment must be arranged to allow:       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 BOPE Systems: The pressure rating of the BOP system is based on the MASP (Maximum Anticipated Surface Pressure). The minimum rated working pressure of the BOP system shall be selected based on MASP for each hole section as detailed in the table below: BOP Equipment OIL WELL GAS WELL INJECTION WELL Pressure Rating MASP (in PSI) MASP (in PSI) MASP (in PSI) 3,000 PSI ≤ 2,550 ≤ 2,700 < 3,000 5,000 PSI ≤ 4,250 ≤ 4,500 < 5,000 10,000 PSI ≤ 8,500 ≤ 9,000 < 10,000 15,000 PSI ≤ 12,750 ≤ 13,500 < 15,000 NOTE-1: Does not include diverter requirements. NOTE-2: BOP’s with higher rated working pressure than shown above may be used at any time.

2.0

CLASS ‘A’ 15,000 PSI BOP STACK

2.1

Usage: A Class ‘A’ 15,000 psi BOP stack shall be installed on all offshore and onshore wells with a MASP up to the limits given in the table above. If MASP exceeds these limits a higher pressure rating will be required. The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 15M.


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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" 15M flange with two (2) 3-1/16" 15M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" (minimum) 15M flanged gate valves with a blind flange installed.

2.2.2

If the top flange of the wellhead is below ground level, a spacer spool spacer is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.

2.2.3

A flanged or studded double gate ram preventer shall be installed on the wellhead or spool. The BOP shall be above ground level with master drill pipe rams in the bottom position (1) and blind rams in the top position (2).

2.2.4

A flanged drilling cross shall be installed on the double ram preventer. The drilling cross shall have two (2) 4-1/16" 15M flanged side outlets.

2.2.5

Kill Lines There shall be two (2) kill lines, an upper and a lower. Both lines shall be 3-1/16" 15M and configured as below: From the drilling cross out on the kill line side, there shall be:     

a double studded adapter flange 4-1/16" 15M to 3-1/16" 15M a 3-1/16" 15M flanged manually operated gate valve a 3-1/16" 15M flanged hydraulic control (HCR) gate valve a 3-1/16" 15M flanged spacer spool a 3-1/16" 15M studded tee

The bottom outlet of the tee will connect to the lower kill line. The other side of the tee will have a flanged spacer spool followed by a second studded tee. On each side of the second tee there shall be a 3-1/16" 15M flanged gate valve and a 3-1/16" 15M flanged check valve. On the remote (emergency pump connection) side, the kill line shall be 15M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 3" welded union. On the primary (mud pump) side, the kill line shall be connected directly to the mud pumps or to the stand pipe manifold, with a 10M manual isolation valve between the kill line and the 7,500 psi stand pipe. The lower kill line from the 4-1/16" 15M BOP master pipe ram side outlet out there shall be:    

a 4-1/16" X 3-1/16" 15M DSA two (2) 3-1/16" 15M flanged manually operated gate valves 3-1/16" 15M flanged spacer spools and studded (targeted) tees as required a 3-1/16" 15M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.


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2.2.5

Choke Lines There shall be two (2) choke lines, an upper and a lower. Both lines shall be 4-1/16" 15M and configured as below: From the drilling cross out on the choke line side there shall be:    

a 4-1/16" 15M flanged manually operated gate valve a 4-1/16" 15M flanged hydraulic control (HCR) gate valve a 4-1/16" 15M flanged spacer spool a 4-1/16" 15M studded tee

The bottom outlet of the tee will connect to the lower choke line. The other side of the tee will connect (through flanged line) to the manually operated gate valve at the choke manifold. The lower choke line from the 4-1/16" 15M BOP master pipe ram side outlet out there shall be:    

a 4-1/16" 15M flanged manually operated gate valve a 4-1/16" 15M flanged hydraulic control (HCR) gate valve a 4-1/16" 15M flanged spacer spools and studded (targeted) tees as required a 4-1/16" 15M flanged manually operated gate valve attached directly to the studded tee on the upper choke line.

NOTE: All steel piping shall be made with 15M flanges, targeted tees, block-tee elbows, and factory-manufactured 15M working pressure line. All tees must be targeted with renewable 15M blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, or choke line. Coflex hose (refer to Chapter A, Section 2.0) may be used in combination with steel line for the choke or kill line. 2.2.6

A 15M flanged or studded double gate ram preventer shall be installed on the 15M drilling cross. There shall be shear blind rams in the bottom (3) and drill pipe rams in the top (4) of the double ram preventer.

2.2.7

A 10M or 15M annular preventer will be installed on the top of the double ram preventer. The annular shall be flanged bottom X studded top.

2.2.8

A flanged rotating head, with a flanged bottom connection to match the top connection of the annular preventer and a 9" 3M flanged side outlet, may be installed on top of the annular preventer. A spacer spool may be required if annular studded top is not compatible with the rotating head flange.


B-5



Figure B-1: Class 'A' 15,000 psi BOP Stack with Single Sized Drill Pipe


B-6

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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


B-7


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3.0


3.1

Usage: A Class ‘A’ 10,000 psi BOP stack shall be installed on all offshore and onshore wells with a MASP of up to 8,000 psi. The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 10M

3.2

Class ‘A’ 10,000 psi BOP Stack Arrangement (Single Size Drill Pipe): When using a single size of drill pipe the stack arrangement (from bottom to top) shall be as described below and as shown in Figure B-3: 3.2.1

A wellhead spool or tree with a 18-3/4", 13-5/8", 11” or 7" 10M flange with two (2) 3-1/16" (minimum) 10M studded side outlets shall be installed. Each outlet shall have two (2) 3-1/16" 10M flanged gate valves with a 3-1/16” blind flange installed.

3.2.2

If the top flange of the wellhead is below ground level, a spacer spool spacer is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.

3.2.3

A flanged or studded double gate ram preventer shall be installed on the wellhead or spool. The BOP shall be above ground level with master drill pipe rams in the bottom position (1) and blind rams in the top position (2).

3.2.4

A flanged drilling cross shall be installed on the double ram preventer. The drilling cross shall have two (2) 4-1/16" 10M flanged side outlets.

3.2.5

Kill Lines There shall be two (2) kill lines, an upper and a lower. Both lines shall be 2-1/16" 10M and configured as below: From the drilling cross out on the kill line side, there shall be:     

a double studded adapter flange 4-1/16" 10M to 2-1/16" 10M a 2-1/16" 10M flanged manually operated gate valve a 2-1/16" 10M flanged hydraulic control (HCR) gate valve a 2-1/16" 10M flanged spacer spool a 2-1/16" 10M studded tee

The bottom outlet of the tee will connect to the lower kill line. The other side of the tee will have a flanged spacer spool and followed by another studded tee. On each side of this tee there shall be a 2-1/16" 10M flanged gate valve and a 2-1/16" 10M flanged check valve. On the remote (emergency pump connection) side, the kill line shall be 10M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 2" welded union. On the primary (mud pump) side, the kill line shall be connected directly to the mud pumps or to the stand pipe manifold, with a 5M manual isolation valve between the kill line and the 5,000 psi stand pipe.


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The lower kill line from the 4-1/16" 10M BOP master pipe ram side outlet out there shall be:    

3.2.6

a 4-1/16" X 2-1/16" 10M DSA two (2) 2-1/16" 10M flanged manually operated gate valves 2-1/16" 10M flanged spacer spools and studded (targeted) tees as required a 2-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper kill line.

Choke Lines There shall be two (2) choke lines, an upper and a lower. Both lines shall be 4-1/16", 10M and configured as below: From the drilling cross out on the choke line side there shall be:    

a 4-1/16" 10M flanged manually operated gate valve a 4-1/16" 10M flanged hydraulic control (HCR) gate valve a 4-1/16" 10M flanged spacer spool a 4-1/16" 10M studded tee

The bottom outlet of the tee will connect to the lower choke line. The other side of the tee will connect (through flanged line) to the manually operated gate valve at the choke manifold. The lower choke line from the 4-1/16", 10M BOP master pipe ram side outlet there shall be:    

a 4-1/16" 10M flanged manually operated gate valve a 4-1/16" 10M flanged hydraulic control (HCR) gate valve 4-1/16" 10M flanged spacer spools and studded (targeted) tees as required a 4-1/16" 10M flanged manually operated gate valve attached directly to the studded tee on the upper choke line.

NOTE: All steel piping shall be made with 10M flanges, targeted tees, block-tee elbows, and factory manufactured 10M working pressure line. All tees must be targeted with renewable 10M blind flanges (welded tees or field fabricated equipment is not acceptable). Chiksans and Weco connections (other than the remote connections at end of the catwalk) are not acceptable for kill line, or choke line. Coflex hose (refer to Chapter A Section 2.0) may be used in combination with steel line for the choke or kill line. 3.2.7

A 10M flanged or studded double gate ram preventer shall be installed on the 10M drilling cross. There shall be shear blind rams in the bottom (3) and drill pipe rams in the top (4) of the double ram preventer.

3.2.8

A 10M annular preventer will be installed on the top of the double ram preventer. The annular shall be flanged bottom X studded top.

3.2.9

A flanged rotating head, with a flanged bottom connection to match the top connection of the annular preventer and a 9" 3M flanged side outlet, may be installed on top of the annular


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preventer. A spacer spool may be required if annular studded top is not compatible with rotating head flange.

Figure B-3: Class 'A' 10,000 psi BOP Stack with Single Sized Drill Pipe


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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.


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Figure B-4 Class ‘A’ 10,000 psi BOP Stack with a Tapered String of Drill Pipe

4.0

CLASS ‘A’ 5,000 PSI BOP STACKS

4.1

Usage: A Class ‘A’ 5,000 psi BOP stack shall be installed on wells where MASP may become more than 2,401 psi but not more than 4,000 psi. All of the elements of the BOP stack shall be 5,000 psi rated working pressure. All preventers shall be installed so that rams can be changed without moving the stack. The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 18-3/4" 5M.

4.2

Class ‘A’ 5,000 psi BOP Stack Arrangement: The stack arrangement (from bottom to top) shall be as described below and as shown in Figure B-5: 4.2.1

A wellhead spool (or casing head) with a 18-3/4", 13-5/8", 11” or 7" 3M or 5M flange with two (2) 2-1/16" or 3-1/16" 3M or 5M studded side outlets shall be installed. One outlet shall have a flanged gate valve with a blind flange installed. The other outlet shall have a manually operated flanged gate valve installed next to the wellhead and a hydraulically operated (HCR) flanged gate valve connecting to the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 2” 5M rated working pressure. Flexible hose (compliant with Chapter A section 2.0) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 2" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump. Offshore the emergency kill line will extend to the emergency pump / cement unit. NOTE: If shear blind rams are utilized, then the emergency kill line shall be 3” and 5M rated working pressure. The manual gate valve shall remain as 2” with double studded adapter to 3”. NOTE: If the wellhead spool has a 5M top flange, then the side outlet valves shall be 5M. NOTE: All BOP equipment with working pressures of 3,000 psi and above shall have flanged, welded, integral, or hubbed connections only.


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Figure B-5: Class 'A' 5,000 and 3,000 psi BOP Stack with VBR’s


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4.2.2

If the top flange of the wellhead is below ground level, a spacer spool is required. If the BOP Stack is larger than the wellhead a double studded adapter flange is required.

4.2.3

A 5M flanged single ram preventer shall be installed on the wellhead spool with master drill pipe rams.

4.2.4

A 5M flanged drilling cross shall be installed on the single ram preventer. The drilling cross shall have two (2) 3-1/8" (minimum) 5M side outlets.

4.2.5

There shall be a double studded adapter flange to adapt from one of the BOP side outlets to the 2-1/16" 5M kill line and one from the other BOP side outlet to the 3-1/8” choke line.

4.2.6

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

a 2-1/16" 5M flanged manually operated gate valve a 2-1/16" 5M flanged hydraulic control gate valve a 2-1/16" 5M flanged spacer spool a 2-1/16" 5M flanged tee

On each side of the tee there shall be a 2-1/16" 5M flanged gate valve and a 2-1/16" 5M flanged check valve. On the remote side, the kill line shall be 5M and run at least 90 feet from the wellbore to the end of the catwalk, with a flange to Weco 2" welded union. On the primary side, the kill line shall be 5M and connected directly to the mud pumps or to the stand pipe manifold. 4.2.7

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

a 3-1/8" 5M flanged manually operated gate valve a 3-1/8" 5M flanged hydraulic control gate valve a 3-1/8" 5M steel flanged line or flexible hose (Chapter A, Section 2.0) to a 3-1/8" 5M flanged manually operated gate valve at the choke manifold

NOTE: All steel piping shall be made with 5M flanges, targeted tees, block-tee elbows, and factory-made 5M working pressure line. All tees must be targeted with renewable 5M blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the end of the catwalk on land operations) are not acceptable. Flexible hose (refer to Chapter A Section 2.0) may be used in combination with steel line for kill, emergency kill line, or choke line. 4.2.8

Either two (2) flanged/studded single ram preventers or a double ram preventer shall be installed, with blind rams in the position immediately above the drilling spool and VBR’s installed immediately below the annular.


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Variable bore rams are required to be used on Class ‘A’ 5M stacks. However, the master pipe ram must be a fixed ram. NOTE: Currently, Cameron’s Extended Range High Temperature VBR-II Packer is the only variable bore ram that is approved for 5M applications (3-1/2" - 5-7/8" pipe sizes). Additional information regarding the use of variable bore rams is provided in Chapter A, Section 1.4. 4.2.9

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

4.2.10 A rotating head is optional. 4.3

Class ‘A’ 5,000 psi BOP Stack Arrangement for Tapered Drill Pipe String: The Class ‘A’ 5,000 BOP Stack arrangement for tapered drill strings will be the same as it is for single sized drillpipe EXCEPT the upper pipe rams (position 3) will be sized for the smaller sized drill pipe as shown in Figure B-5. Alternatively, the upper pipe rams may be Variable Bore Rams as per Chapter A Section 1.4. NOTE: Variable Bore Rams are not allowed in the Master Pipe Ram position (lowermost rams).



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5.0


5.1

Usage: Large Diameter Hole (as with Deep Gas Wells): A Class ‘A’ 3,000 psi BOP stack shall be installed on all wells where large diameter hole (as with deep gas wells) is being drilled, as through 18-5/8" casing, and where hydrocarbon reservoirs with a MASP of up to 2,400 psi may be drilled. All preventers shall be installed so that rams can be changed without moving the stack. Smaller Diameter Hole (as with Critical Oil Wells): At the discretion of the Drilling Manager, some wells may require a Class ‘A’ 3,000 psi stack instead of a Class ‘B’ 3,000 psi stack. Shear blind rams on onshore stacks are required only on wells with high H2S, wells in gas cap areas and wells in populated areas (close proximity). Further details on the use of shear blind rams is provided in Chapter A section 1.5.

5.2

Class ‘A’ 3,000 psi BOP Stack Arrangement for Large Diameter Hole (Single Size Drill Pipe): All elements of Class ‘A’ 3,000 psi stacks shall be at least 3,000 psi rated working pressure. The through bore of the BOP stack including drilling spools, risers, DSA's and any other equipment will be at least as large as the wellhead section immediately below it. These BOP stacks are available in 7-1/16", 11", 13-5/8" and 20-3/4” and 26-3/4" 3M. Each ram preventer shall have two (2) 4-1/16" 3M side outlets. A double ram preventer will have four side outlets. When using a single size of drill pipe the stack arrangement (from bottom to top) shall be as described below and as shown in Figure B5: 5.2.1

A wellhead spool (18-5/8" landing base or casing spool) with 20-3/4" 3,000 psi flange and two (2) 3-1/16" 3M side outlets for emergency kill operations shall be installed. One outlet shall have a 3-1/16" 3M gate valve with a 3-1/16" 3M blind flange. The other outlet shall have a manually operated 3-1/16" 3M flanged gate valve next to the wellhead and a hydraulic control 3-1/16" 3M flanged gate valve tied into the emergency kill line. The emergency kill line shall be an individual line with flanged steel piping (no chiksan swings or hammer unions) and a minimum 3” 3M rated working pressure. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 3" 1502 Weco welded union (threaded connections are not acceptable) for connection to an emergency pump.

5.2.2

If the wellhead top flange is below ground level a spacer spool is required. If the BOP Stack is larger than the wellhead a DSA is required.

5.2.3

A 26-3/4” or 20-3/4” 3M flanged single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams (1).

5.2.4

A 26-3/4” or 20-3/4” 3M flanged drilling cross shall be installed on the single ram preventer. A drilling cross shall have two (2) 4-1/16" 3M side outlets.


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5.2.5

Either a 26-3/4" or 20-3/4" 3M flanged double ram preventer or two (2) single ram preventers shall be installed, with blind rams (2) and drill pipe rams (3).

5.2.6

A 26-3/4” or 20-3/4" 3M to 30” 1M or 21-1/4" 2M double studded adapter flange (DSA) will be required on top of this preventer. The DSA can be eliminated if a 26-3/4” or 20-3/4" 3M psi flange is manufactured on the annular preventer.

5.2.7

A 30” 1M or 21-1/4" 2M flanged bottom annular preventer shall complete this stack.

5.2.8

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 spacer spool a 2-1/16" 3M minimum flanged tee

On each side of the tee there shall be a 2-1/16" 3M minimum flanged gate valve and a 21/16" 3M minimum flanged check valve. 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. 5.2.9

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 hose (Chapter A, Section 2.0) to a 31/8" 3M minimum flanged manually operated gate valve at the choke manifold

NOTE: All steel piping shall be made with 3M minimum flanges, targeted tees, block-tee elbows, and factory-made 3M minimum working pressure line. All tees must be targeted with renewable 3M minimum blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the catwalk, land operation) are not acceptable. Flexible hose (refer to Chapter A Section 2.0) may be used in combination with steel line for kill, emergency kill line, or choke line. 5.2.10 A 3M minimum flanged bottom and studded top annular preventer will be installed on the top ram preventer. 5.2.11 A rotating head is optional.


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5.3

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: 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 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 3” 3M rated working pressure (if SBR used) otherwise 2” 3M. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 1502 WECO welded union (threaded connections are not acceptable) for connection to an emergency pump. Note:

5.4

If shear blind rams are utilized, then the emergency kill line shall be 3” and 3M rated working pressure. The manual gate valve shall remain as 2” with double studded adapter to 3”.

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-6.

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).


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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. All BOP equipment shall be 13-5/8” 3M (or 26-1/4” when used on deep gas wells), 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. This stack will also be used for deep gas wells on 24” or 18-5/8” casing.

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 21/16" 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 3” 3M rated working pressure (if SBR used) otherwise 2” 3M. Coflex hose (coflon lined) may be used in combination with steel line. The emergency kill line shall extend from the wellbore to end of the catwalk (approximately 90 feet), with a 1502 WECO welded union (threaded connections are not acceptable) for connection to an emergency pump. Note:

If used on deep gas wells with 24” or 18-5/8” casing the side outlets will be 4” and kill lines will be 3” 3M.

6.2.2

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

6.2.3

A 3,000 psi single ram preventer shall be installed on the wellhead spool above ground level with master drill pipe rams.

6.2.4

A 3,000 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 3,000 psi single ram preventer shall be installed on the top of the drilling cross with blind rams.

6.2.6

A 3,000 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 spacer spool


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

a 2-1/16" 3M minimum flanged tee

On each side of the tee there shall be a 2-1/16" 3M minimum flanged gate valve and a 21/16" 3M minimum flanged check valve. 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 hose (Chapter A, Section 2.0) to a 31/8" 3M minimum flanged manually operated gate valve at the choke manifold

NOTE: All steel piping shall be made with 3M minimum flanges, targeted tees, block-tee elbows, and factory-made 3M minimum working pressure line. All tees must be targeted with renewable 3M minimum blind flanges (welded tees are not acceptable). Chiksans and Weco connections (other than the remote connection at the catwalk, land operation) are not acceptable. Flexible hose (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

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.


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

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” minimum ID, full bore valves and 8” lines. All lines must be as straight as possible and all turns targeted to minimize erosion. Offshore, the lines must allow diversion to port and/or starboard. 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.


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Figure B-8: Class ‘D’ Diverter BOP Stack


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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. Please note that if SBR’s are not being used, in special circumstances (such as low sub-structure height) it is permissible to leave out the drilling spool and use the BOP side outlets for line connections.

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


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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.

SIDE DOOR STRIPPER

SIDE STRIP SIDEDOOR DOOR DSA6 STRIPPER GATE VALVE BLIND SHEAR SLIP

QUAD QUADBO BOP ES46

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


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 

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

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 low-pressure 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/ UNDER SIDE DOOR DS U6 STRIPPER GATE VALVE GATE VALVE BLIND BLIND

GATE VALVE GATE VALVE

SHEAR SHEAR SLIP SLIP PIPE PIPE

QUAD

QUAD ES46 BOP

SHEAR/SEAL DUAL COMBI BOP ES46

SHEAR/ SEAL DUAL COMBI PIPE/ SLIP BOP Figure B-11: High Pressure Coil Tubing BOP Stack


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PIPE/SLIP


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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 STRIPPER DSU6

GATE VALVE GATE VALVE BLIND

BLIND

SHEAR SHEAR SLIP SLIP

GATE VALVE GATE VALVE

PIPE PIPE

QQUAD UAD

BOP

ES46

SHEAR/SEAL DUAL COMBI BOP ES46

SHEAR/SEAL

DUAL PIPE/SLIP COMBI BOP CT SAFETY 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 highpressure 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.



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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 well, an electric line BOP is not required, provided primary well control (hydrostatic pressure > formation pressure) can be maintained and confirmed. However, an electric line BOP is recommended on all gas wells. 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.

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

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

0

0

250 F

300 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

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. A typical electric line rig-up for cased-hole operations is shown in Figure B-15.


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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. Required specifications and applications for the 15,000 psi, 10,000 psi, 5,000 psi, and 3,000 psi choke manifolds are shown below. 15.1

15,000 psi Working Pressure Choke Manifold:

FIGURE B-16: 4-1/16” 15M Onshore Choke Manifold


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4-1/16” 15M CHOKE MANIFOLD

All 15M psi choke manifolds shall comply with the following minimum requirements: •

Valves and chokes shall be monogrammed to API Specification 6A or 16C and made to the following,        

•

PSL-2 or Better, (with PSL-3 Gas Test) PR-1 or Better MR-DD or Better TR-X (Suitable for 350 F service) Forged Bodies and Bonnets All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Nitrile/Buna Elastomer Seals are not permitted

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


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15.2

10,000 psi Working Pressure Choke Manifold:

FIGURE B-18: 4-1/16” 10M Choke Manifold


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4-1/16” 10M CHOKE MANIFOLD

All 10M psi (& higher) choke manifolds shall comply with the following minimum requirements: •


•

PSL-2 or Better, (with PSL-3 Gas Test) PR-1 or Better MR-DD or Better TR-X (Suitable for 350 F service) Forged Bodies and Bonnets All valves must be of a single gate (slab) design Telescoping two-piece seats are not permitted Nitrile/Buna Elastomer Seals are not permitted




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FIGURE B-19: 4-1/16” 10M Offshore Choke Manifold


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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.

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


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FIGURE B-21: Offshore 3-1/8” 5M Choke Manifold 3-1/8” 5M CHOKE MANIFOLD



•

PSL-2 or Better PR-1 or Better MR-DD or Better TR-U (Suitable for 250F service) Forged Bodies and Bonnets All valves must be of a single gate (slab) design Telescoping or floating seats are not permitted Nitrile/Buna Elastomer Seals are not permitted



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15.4

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


Valves and chokes shall be monogrammed to API Specification 6A or 16C made to the following:        

•

PSL-2 or Better PR-1 or Better MR-DD or Better TR-U Forged Bodies and Bonnets All valves must be of a single gate (slab) design Telescoping seats are not permitted Nitrile/Buna Elastomer Seals are not permitted


FIGURE B-22: 3-1/8” 3M Choke Manifold


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15.5

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. Choke lines for 3M and 5M applications shall either be steel pipe, Coflex hose (coflon lined only), or combination of Coflex and steel pipe. All flexible hose shall be monogrammed to API Specification 16C, and all end connections monogrammed to API Specification 6A. Choke lines for 10,000 and higher psi applications shall be flanged pipe only. 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. Chiksans and Weco connections are not acceptable.

15.8

Choke Manifold Discharge: 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. 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. Note:

Using drill pipe for flare line is not recommended because of the difficulty of properly making up the connections on the ground.

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.


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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, 3.10 and 3.11) to the flare booms. Listed below are the minimum piping requirements: One (3”) Oil line and 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). Note: a) flare lines should be as straight as possible and fitted with TARGETED OR BLOCK –TEE ELBOWS AT TURNS. Lines to be pressure tested to 2000 psi during scheduled BOPE testing 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’ past the back 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’ past the back 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

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–5

3.2

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

C–7

3.3


C–9

3.4


C – 10

3.5


C – 11

3.6

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

C – 12

3.7

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

C – 13

3.8

Specific Requirements for Class ‘D’ Diverter Stack

C – 14

PRESSURE TESTING PROCEDURE 4.1

Function Testing and Flow Testing

C – 15

4.2

Fill the Stack with Water

C – 15

4.3

Casing Test (if required)

C – 15

4.4

Blind Rams (if required)

C – 16

4.5

Annular Preventer

C – 17

4.6

Upper Pipe Rams

C – 18

4.7

Positive Sealing Chokes

C – 19

4.8

Choke Manifold (continued)

C – 20

4.9

Choke Manifold (continued)

C – 21

4.10 Choke Manifold (continued)

C – 22


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4.11 Choke Line HCR Valve

C – 23

4.12 Choke and Kill Line Manual Valves

C - 24

4.13 Master Pipe Rams

C – 25

4.14 Small Pipe Rams

C – 26

4.15 Kelly, Surface Circulating Equipment, and Safety Valves

C – 27

4.16 Wellhead Valves

C – 27

5.0

ACCUMULATOR TESTING

C – 27

6.0

HANG-OFF LIMITATIONS WHILE TESTING

C – 30

7.0

TEST PRESSURE REQUIREMENTS FOR CASING RAMS

C – 30

8.0

CERTIFICATION AND RE-CERTIFICATION REQUIREMENTS

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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 Liaisonman) as directed by the Drilling Superintendent.

2.0

GENERAL MAINTENANCE REQUIREMENTS

Blowout prevention equipment is emergency equipment and must be maintained in its proper working condition at all times. The Drilling Foreman can best ensure that Saudi Aramco is provided with equipment that performs to our specifications by being an active participant in the maintenance requirements of the BOP equipment. Several maintenance items, which the Drilling Foreman should verify on a daily basis, by reviewing the Driller’s pre-tour checklist or by personal observation, are listed below: 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) Verify the control lines are run to prevent damage by trucks or dropped tools. 3) Confirm the preventer controls are either in their proper opened or closed position (not neutral) and that leaks are not evident. 4) Assure the preventer stack is well guyed so that vibrations are minimized while drilling. 5) All preventers must be operated at least each time a trip is made. 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. 6) The emergency kill line and choke/kill lines shall be washed out as required to prevent mud solids settling. Clear water should be used to flush and fill the lines (except in extremely cold weather, where diesel or glycol should be used). 7) DO NOT circulate green cement through the preventer stack or choke manifold. Always thoroughly flush with water any piece of blowout prevention equipment, which has come in contact with green cement and verify the equipment is clear upon 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. 8) Ensure the rig is centred over the well to reduce drill string and BOP equipment contact and abrasion.


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9) Do not use the kill line as a fill-up line during trips. 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. 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 Liaisonman). 12) Only OEM parts are acceptable when repairing or redressing the BOPE. Furthermore, only OEM approved high-temperature lubricant is acceptable for valve maintenance. 13) At least one spare set of ram seals (top seals and packer rams) for all rams including packer rams for each size of tubing or drill pipe, as well as bonnet seals, must be on the rig site. 14) Ram blocks should not be dressed until ready to use. 15) All BOP rubber goods shall be kept in a cool place and remain in the original packaging with expiration dates. 16) Preventer assemblies shall be dismantled between wells to inspect for internal corrosion and erosion and to check flange bolts. 17) Manufacturer‘s installation, operation, and maintenance (IOM) manuals should be available on the rig for all BOP equipment installed on the rig. 18) New ring gaskets shall be installed on each nipple-up at each connection, which has been parted. Ring gaskets shall never be reused. 19) Studs and nuts should be checked for proper size and grade. Using the appropriate lubricant, torque should be applied in a criss-cross manner to the flange studs. All bolts should then be re-checked for the proper torque as prescribed in API Specification 6A. Bolt sizes 2-3/4” and larger require more make-up torque than can be provided with Hammer Wrenches. These larger sizes must be torqued using hydraulic torque units. 20) Field welding shall not be performed on any BOP or associated well control equipment. All repairs to BOP equipment must be performed at an OEM facility, or their Licensee. OEM repairs and recertification may be completed outside of Saudi Arabia if necessary. 21) A Maintenance Log for each piece of BOP equipment shall be maintained. This log shall include, at a minimum, records of all service and inspections performed on the BOP, serial numbers for each BOP 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 BOP shop for Saudi Aramco-owned equipment. 22) All BOP equipment shall be API monogrammed.


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23) A full OEM Certification of the BOP, choke manifold (including chokes), and all related equipment (i.e. kill line valves, choke line valves, Coflex hoses, etc.) shall be required at contract start-up and contract renewal with a maximum period of 3 years between OEM recertification. 24) Accumulator bottles must have hydrostatic pressure testing completed every 5 years in accordance with Department of Transportation (DOT) Cylinder Maintenance, Retest and Certification Requirements #173.34. 25) The BOP should be opened, cleaned, and visually inspected after every nipple down, including servicing the manual tie-down screws. 26) 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 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. 27) All BOP equipment must have documentation of last inspection and certification. Documents and Certification for Saudi Aramco owned BOP Equipment will be maintained and located at the Saudi Aramco BOP Facility.

3.0

TESTING OF BLOWOUT PREVENTION EQUIPMENT The objective of BOP equipment testing is to eliminate all leaks and to determine that the equipment will perform under unplanned pressure conditions. 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 1) BOP equipment (including blind rams and shear blind rams) shall be pressure tested as follows:   

When installed Before drilling out each string of casing 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 (and annular PREVENTOR) shall be pressure tested with a test plug and casing/tubing


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 

joint to 80% of the pipe collapse or the rated working pressure of the BOP (whichever is less). Working Pressure: 5,000 psi and lower; Test a maximum of every 21 days (no extensions) Working Pressure: 10,000 psi and higher; Test every 14 days. 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.

2) All tests shall be performed using clear water. 3) When a gas well is being flow tested, the test equipment (manifolds, lines, etc.) must be tested with nitrogen. 4) The low-pressure test of each piece of BOP equipment shall be conducted at a pressure of 300 psi. 5) The high-pressure test is specified in the following sections, by BOP class. 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. 7) All valves located downstream of the valve being tested shall be placed in the OPEN position. 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. 9) OPEN annular valves when testing to prevent pack-off leaks from pressuring up outer casing strings. 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. 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’. 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. 13) Variable Bore Rams (VBR) shall be tested with all sizes of pipe in use, excluding drill collars and bottom-hole tools.


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14) All pressure tests must be held for a minimum duration of ten (10) minutes with no observable pressure decline. 15) Only authorized personnel shall go in the test area to inspect for leaks when the equipment is under pressure. 16) Tightening or repair work shall be done only after pressure has been released and all parties have agreed that there is no possibility of trapped pressure. 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. 18) A pressure test is required after the 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. 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. 20) All pressure tests shall be conducted with a test pump. Avoid the use of rig pumps for pressure testing. Cement units are acceptable. 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

21) Test stumps are an acceptable method for pressure testing the BOP stack at the rig site. The bottom connection (and any other connection not tested) must be tested with a test plug upon installation of the BOP stack. 3.2

Specific Pressure Testing Requirements for Class ‘A’ 15M BOP Stack 1) The initial high-pressure test of the following equipment shall be conducted upon installation at the rated working pressure of the weakest component:   

Wellhead Ram-Type Preventers Kill Line and Valves


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  

Emergency Kill Line and Valves Choke Line and Valves Choke Manifold

2) Subsequent high-pressure test(s) of the above equipment shall be conducted to a pressure greater than the *maximum anticipated surface shut-in pressure.

Note: For Khuff development wells (Jilh Dolomite casing point)  Initial high-pressure test is 15,000 psi (full working pressure)  Subsequent high-pressure test(s) are 12,000 psi For Pre-Khuff wells (Jilh Dolomite casing point and below)  Initial high-pressure test is 15,000 psi (full working pressure)  Subsequent high-pressure test(s) are 15,000 psi For K1/MK1 wells only (where NU occurs above Jilh Dolomite casing point)  Initial high-pressure test is 15,000 psi (full working pressure)  Subsequent high-pressure test(s) are 7,500 psi minimum. (Prior to drilling into the Jilh Dolomite a high-pressure test(s) must be completed at 15,000 psi) 3) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure. 4) 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# 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. 5) 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 high-pressure test(s) shall be conducted at the maximum anticipated surface shut-in pressure. 6) Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested to 7500 psi. 7) 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. 8) At nipple up, the casing shall be tested to 80% of burst rating.


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9) 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) The initial high-pressure test of the following equipment shall be conducted upon installation at the rated working pressure of the weakest component:      

Wellhead Ram-Type Preventers Kill Line and Valves Emergency Kill Line and Valves Choke Line and Valves Choke Manifold

4) Subsequent high-pressure test(s) of the above equipment shall be conducted to a pressure greater than the *maximum anticipated surface shut-in pressure.

Note: For Khuff development wells (Jilh Dolomite casing point)  Initial high-pressure test is 10,000 psi (full working pressure)  Subsequent high-pressure test(s) are 8,500 psi For Pre-Khuff wells (Jilh Dolomite casing point and below)  Initial high-pressure test is 10,000 psi (full working pressure)  Subsequent high-pressure test(s) are 10,000 psi For K1/MK1 wells only (where NU occurs above Jilh Dolomite casing point)  Initial high-pressure test is 10,000 psi (full working pressure)  Subsequent high-pressure test(s) are 5,000 psi minimum

10) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 70% of the rated working pressure. 11) 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# 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. 12) 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 high-pressure test(s) shall be conducted at the maximum anticipated surface shut-in pressure.


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13) Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested to 5,000 psi. 14) 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. 15) At nipple up, the casing shall be tested to 80% of burst rating. 16) 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


Wellhead Ram-Type Preventers (including fixed PR, VBR, and SBR) Kill Line and Valves Emergency Kill Line and Valves Choke Line and Valves Choke Manifold

2) Subsequent high-pressure test(s) of the above equipment shall be conducted to a pressure greater than the maximum anticipated surface shut-in pressure. This test pressure will be determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating). 3) The high-pressure test (initial and subsequent) of the annular preventer shall be conducted at 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. 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. 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. 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


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performed on each well installation at the same pressure or after repairs to the hydraulic circuit. 7) At nipple up, the casing shall be tested to 80% of burst rating. 8) 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). 3.5


Wellhead Ram-Type Preventers (including fixed PR, VBR, and SBR) Kill Line and Valves Emergency Kill Line and Valves Choke Line and Valves Choke Manifold

2) Any subsequent high-pressure test(s) of the above equipment shall be conducted at 2,500 psi or maximum anticipated surface shut-in pressure (whichever is greater), as determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating). 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. 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. 5) Test plugs must be checked to insure the plug fits the casing head. 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. 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


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performed on each well installation at the same pressure or after repairs to the hydraulic circuit. 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 1) The initial high-pressure test of the following equipment shall be conducted upon installation at the rated working pressure of the weakest component:      

Wellhead Ram-Type Preventers Kill Line and Valves Emergency Kill Line and Valves Choke Line and Valves Choke Manifold

2) Any subsequent high-pressure test(s) of the above equipment shall be conducted at 2500 psi or maximum anticipated surface shut-in pressure (whichever is greater), as determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating). 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. 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. 5) Test plugs must be checked to insure the plug fits the casing head. 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. 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.


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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 1) The initial high-pressure test of the following equipment shall be conducted upon installation and at the rated working pressure of the weakest member:     

Wellhead Double Ram Preventer Kill Line and Valves Choke Line and Valves Choke Manifold

2) Any subsequent high-pressure test(s) of the above equipment shall be conducted at 2,500 psi or maximum anticipated surface shut-in pressure (whichever is greater), as determined by the particular application (i.e. formations exposed, fracture gradient or estimated fracture gradient, casing burst rating). 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.

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. 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. 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. 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.


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3.8

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 nippling-up 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. Specific Pressure Testing Requirements for Class ‘D’ Diverter Stack 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. 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) The low-pressure test on the diverter shall be conducted upon installation and at 300 psi. 4) The high-pressure test shall be based on 80% rated working pressure of the weakest component in the diverter system. 5) Function test the diverter daily.

4.0

PRESSURE TESTING PROCEDURE The recommended pressure testing procedure for a Class ‘A’ 10,000 psi BOP hook-up 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 highpressure. 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’ 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.


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4.1

Function Testing and Flow Testing

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

4.2

1)

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

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. 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. Figure C.1 Casing

Shear Blind Rams

#3

Note:

Very Important - Monitor valves #1, #2, #3 and #3a for leaks/well flow.

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).


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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: No manufacturer recommends opening rams, which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur. 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). Figure C.2

Shear Blind Ram Test

Shear Blind Rams

#3a

Note:

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

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.


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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 highpressure test next at the pressure specified in previous requirements (Section K 2.2 for Class ‘A’ 10M). Note: This test will also evaluate the choke line HCR valve and thereby eliminate the need for Step 3.11. 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). 3) 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. Figure C.3

Annular Test

Shear Blind Rams

#19

#3a


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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. 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

#3a

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


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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). 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 for Choke and Kill Systems states in section 9.9: “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:



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4.8

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. 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.

Note:



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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.

Figure C.7

Choke Manifold Valves

Shear Blind Rams

#3a

Note:

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


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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. Figure C.8

Choke Manifold Valves

Shear Blind Rams

#3a

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


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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. Figure C.9

Choke Line HCR Valve

Shear Blind Rams

#3a

Note:



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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. Figure C.10

Choke and Kill Line Manual Valves

Shear Blind Rams

#3a

Note: Monitor valves #1, #2, #3 and #3a for well flow. Note: No manufacturer recommends opening rams, which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.


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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. Figure C.11

Master Pipe Rams

Shear Blind Rams

#1

#2

#3

#3

Note: Monitor valves #1, #2, #3 and 3a for well flow. Note: No manufacturer recommends opening rams, which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.


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4.14 Small Pipe Rams Test the small pipe rams by performing the following: 1) Open the master pipe rams (see Figure C.12). 6) 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. Figure C.12

Small Pipe Rams

Shear Blind Rams

#1

#2

#3

#3a

Note: Monitor valves #1, #2, #3 and 3a for well flow. Note: No manufacturer recommends opening rams, which are holding pressure. Damage to the ram rubbers, ram blocks and ram cavities may occur.


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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. 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 at + 90’.

5.0

ACCUMULATOR TESTS These tests are for the purpose of determining the operating condition of the accumulator and BOP system. They shall be performed every 14 days, 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).


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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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Figure C.13 Saudi Aramco BOP Pressure Test Form


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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. 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 BOP, choke manifold (including chokes) and all related equipment must be performed at the start of the contract and least once every three years thereafter. The documentation package shall be kept with the equipment and must be available for inspection at the rig site by Saudi Aramco personnel. This includes, but is not limited to [See Chapter A of Saudi Aramco Well Control Manual (WCM)]:      

Ram preventers. Annular preventers. Gate, HCR and Check Valves on the kill, emergency kill, choke line and choke manifold. Drilling chokes. Kill, emergency kill and choke lines (and line components) including both hard line and flexible hoses. Drilling spools. NOTE: Recertification can only be performed by the OEM or their licensee and the 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 document package shall include a copy of the license issued by the OEM and Registration Certificates


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for the applicable API Specifications. The Repair Level (RL) for API Specification 6A equipment (Valves, Drilling Spools, Flanged Hard Lines, etc.) must correspond to the relevant Product Specification Level (PSL) as specified when manufactured. NOTE: Choke and Kill flanged hard-lines mounted in semi-permanent locations may have insitu recertification using NDT methods to accurately determine Wall Thickness (erosion or corrosion), Material Defects and Material Hardness. NOTE: Re-Certified Gate, HCR and Check Valves must correspond and comply to Repair Level RL-2 for 3000 and 5000 PSI and 10,000 and 15,000 must correspond and comply to Repair Level RL-3 with Gas Test (Ref. API 6A, Annex J and Section A of Saudi Aramco WCM, Line Item 2.4) NOTE: 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. 8.2 There is no re-certification requirement for Accumulator Control Systems. However, the Accumulator Control Unit must undergo maintenance and testing every five years with individual hydrostatic testing of the accumulator bottles. All documentation including individual Accumulator Bottle test charts must be resident at the rig.


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CHAPTER D - WELL CONTROL POLICIES

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

SPACE OUT 7.1

Space Out Data

D-5

7.2

Space Out For BOP’s With SBR’s

D-5

8.0

SLOW PUMP RATE DATA

9.0

TRIPPING PIPE

10.0

D-5

9.1

Pulling Out of Hole

D-6

9.2

Running In Hole

D-6

PERFORMING FLOW CHECKS 10.1 While Drilling

D-6

10.2 While Tripping

D-6

11.0

DISPLACING TO BRINE ON HORIZONTAL WELLS

D-7

12.0

SHUTTING IN WELL 12.1 Shutting In Well without Flow Checking

D-7

12.2 While Drilling

D-7

12.3 While Tripping

D-7

12.4 With BHA across BOP Stack

D-8

Current Revision: Previous Revision:

JUNE, 2014 MAY, 2010

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

D-8

13.0

FAILURE OF UPPER PIPE RAMS DURING A WELL KILL OPERATION

D-8

14.0

BOP CONFIGURATION WHEN RUNNING CASING OR LINERS

15.0

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

D-9

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

D-9

14.3 Running Casing or Liner W/ Class ‘A’ 10M Stack (W/ SBR)

D-9

14.4 Running 7” Liner W/ Class ‘A’ 10M Stack (W/ SBR)

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14.5 Running 4-1/2” Liner W/ Class ‘A’ 10M Stack

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14.6 Running 4-1/2” Pre-Perforated Liner W/ Class ‘A’ 10M Stack

D-10

CHANGING RAMS OR INSTALLING CASING RAMS 15.1 Isolation Policy

D-10

15.2 Pressure Testing Casing Rams

D-10

16.0

INSTALLING CASING SLIPS WITH MULTI STAGE CEMENTING

D-10

17.0

BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING

18.0

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

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

D-11

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

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BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING WITH PACKER 18.1 Running Tubing/Packer Simultaneously w/ Class ‘A’ 3 or 5M Stack

19.0

20.0

REMOVING BOP STACK OR PRODUCTION TREE 19.1 Isolation Policy for Low GOR Oil Wells

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19.2 Isolation Policy for High GOR Oil Wells

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19.3 Isolation Policy for Gas Wells

D-12

19.4 Isolation Policy for WIW Wells

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RIGGING DOWN ON HIGH GOR WELLS W/ SSSV 20.1 RD Procedure (w/ Little Clearance between Rig and Tree)

21.0

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RUNNING OR PULLING TUBING AND ESP CABLE 21.1 BOP Configuration


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22.0

23.0

21.2 Pressure Testing Annulars

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21.3 Shut-In Procedure

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BOP CONFIGURATION WHEN RUNNING TEST STRING 22.1 Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (W/ SBR)

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

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RIGGING UP SURFACE WELL TEST EQUIPMENT 23.1 Installing Surface Lines Upstream of Test Manifold

24.0

25.0

26.0

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PRESSURE TESTING WITH NITROGEN 24.1 Surface Well Test Equipment (Gas Wells)

D-14

24.2 Lubricator (Gas Wells)

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PROBLEMS WHILE LOGGING 25.1 Shutting in While Logging With Side Entry Sub (Wireline across BOP)

D-15

25.2 Fishing Procedure for Stuck Logging Tool in Open Hole

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RUNNING PDHMS AND/OR SMART-WELL LINES ON TUBING OR CASING 26.1 Oil Wells

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26.2 Gas Wells

D-16

27.0

SETTING BRIDGE PLUGS

D-17

28.0

PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS 28.1

Required Number of Mechanical Barriers of Isolation


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1.0

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 accredited school. NOTE: IWCF Certification is not acceptable for Saudi Aramco D&WO Operations.

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. 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. 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). A ported float is not recommended as these ports can be easily plugged and sometimes washout.

6.0

TAPERED STRING POLICY

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.

7.0

SPACE OUT

7.1

SPACE OUT DATA POLICY

7.2

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.

8.0

SLOW PUMP RATE DATA POLICY

Slow pump rate shall be recorded in the IADC tour book 1) 2) 3) 4) 5) 6)

Tourly After a mud weight change After a bit nozzle or BHA change After each 500’ of depth After a drilling or completion fluid type change Whenever mud properties significantly change

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


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9.0

TRIPPING PIPE

9.1

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: 9.2

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.

10.0 PERFORMING FLOW CHECKS 10.1

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. 10.2

PERFORMING FLOW CHECKS WHILE TRIPPING POLICY

A FLOW CHECK SHALL BE PERFORMED WHENEVER 1) 2)


When the hole is not taking the correct amount of fluid Before pumping a slug

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3)* 4)* 5) 6)* 7)

Before pulling out of the hole After pulling 5 to 10 stands When bit enters casing shoe Prior to pulling last 5 stands 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.

11.0 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

12.0 SHUTTING IN WELL 12.1

Shutting In Well Without A Flow Check POLICY

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

12.2

Shutting In Well While Drilling POLICY

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

12.3

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)


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

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6) Open HCR NOTE: DO NOT attempt to run in hole with the well flowing. 12.4

Shutting In Well With BHA Across Bop Stack POLICY

SHUT-IN PROCEDURE (hard shut–in) 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

Set slips Install crossover to full open safety valve Stab full open safety valve Close safety valve 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. 12.5

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.

13.0 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

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14.0 BOP CONFIGURATION WHEN RUNNING CASING OR LINERS 14.1

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

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.

14.2

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

FOR SHORT LINERS (< 2000’) 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.

POLICY

FOR LONG LINERS (>2000’) LONG STRINGS BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING ANNULAR: TOP RAM: CHANGE PIPE RAMS TO CASING RAMS MIDDLE RAM: BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE: PIPE RAMS HAVE XO (CASING X DP) ON DRILL FLOOR.

14.3

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

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


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14.4

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

14.5

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.

15.0 CHANGING RAMS OR INSTALLING CASING or TUBING RAMS 15.1

ISOLATION POLICY WHEN CHANGING RAMS OR INSTALLING CASING OR TUBING RAMS POLICY

REQUIRES 2 BARRIERS FOR ISOLATION 1) Closed pipe or blind ram (mechanical shut-off) 2) Kill fluid (non-mechanical shut-off) Monitor annulus using wellhead valves. If the bottom master ram is to be changed and the well is open to the formation, a packer and storm valve with kill string is required for a mechanical barrier.

15.2

NOTE:

Refer to GI 1853.001

NOTE:

A test plug or tubing hanger with installed BPV should not be used as a mechanical barrier in this application.

PRESSURE TESTING CASING AND TUBING RAMS POLICY

Casing and Tubing Rams (and annular PREVENTOR) 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).

16.0 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)

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2) 3) 4) 5)

Open upper most DV Circulate hole clean w/ mud WOC 4 hrs. with well static (observing well for flow) 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 NOTE:

Consider pumping second stage cement before setting slips, if the packer fails and loss circulation is experienced (especially with a hydrocarbon or H2S zone open). this situation should be referred to operations management on a case by case basis.

17.0 BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING 17.1

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

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.

17.2

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

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.

17.3

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: BLIND RAMS (OR SHEAR BLIND RAMS) MASTER PIPE: DUAL RAMS

18.0 BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING AND PACKER Current Revision: Previous Revision:

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18.1

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 (tbg x DP) and (large tbg x small tbg, 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.

19.0 REMOVING BOP STACK OR PRODUCTION TREE 19.1

ISOLATION POLICY FOR LOW GOR OIL WELLS POLICY

19.2

ISOLATION POLICY FOR HIGH GOR OIL WELLS POLICY

19.3

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

ISOLATION POLICY FOR GAS WELLS POLICY

19.4

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

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

ISOLATION POLICY FOR WATER INJECTION WELLS POLICY

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

POLICY

REQUIRED BARRIERS FOR WIW WELLS (IF NOT POSITIVE WHP) 1 SHUT-OFF FOR DETAILS REFER TO G.I. 1853.001


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20.0 RIGGING DOWN ON HIGH GOR WELLS WITH OR WITHOUT SSSV 20.1

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.

21.0 RUNNING OR PULLING TUBING AND ESP CABLE 21.1

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.

21.2

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 3-1/2” 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.

21.3

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

22.0 BOP CONFIGURATION WHEN RUNNING TEST STRING 22.1

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.

22.2

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.

23.0 RIGGING UP SURFACE WELL TEST EQUIPMENT 23.1

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, CO2, and HT/HP situations).

24.0 PRESSURE TESTING WITH NITROGEN 24.1

SURFACE WELL TEST EQUIPMENT - GAS WELLS POLICY


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

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6)

24.2

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.

25.0 PROBLEMS WHILE LOGGING 25.1

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

25.2

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.

26.0 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),


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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 26.1

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.

3) 26.2

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.


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27.0 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: 1. Bridge plugs will be run in kill weight fluid 2. Perform positive test 3. Perform negative test 4. Well circulated back to kill weight fluid before tripping out of hole. 5. 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.

28.0 PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS 28.1

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

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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E-1


VOLUME I


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 Toolpusher 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 toolpusher. 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 Toolpusher 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.


JUNE, 2014 MAY, 2010

E-2


VOLUME I


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 Toolpusher 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 drillpipe pressure and casing pressure  Record time  Measure pit gain  Check choke manifold for valve positioning and leaks Derrickman  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 Derrickman on mud pits


JUNE, 2014 MAY, 2010

E-3


VOLUME I


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 Toolpusher 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 Toolpusher 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 drillpipe and casing pressure  Record time  Measure pit gain  Check choke manifold for valve positioning and leaks Derrickman  Weigh sample of mud from suction pit  Check volumes of barite, gel, and water


JUNE, 2014 MAY, 2010

E-4


VOLUME I


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 Derrickman 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), and every 14 days thereafter in conjunction with the weekly BOP pressure tests (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 drillpipe must be in the hole for the pipe rams to close on. The Saudi Aramco Drilling Foreman and Contract Toolpusher should witness all accumulator drills, but the Toolpusher 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 BOPs must have closed in less than 30 seconds with at least:


JUNE, 2014 MAY, 2010

E-5


VOLUME I




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..


JUNE, 2014 MAY, 2010

E-6

PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT RIG:

PREVIOUS TEST:

WELL NUMBER:

WELL INFORMATION

BLOWOUT PREVENTERS

HOLE

LAST CASING STRING SET BURST SHOE WT GRADE RATING DEPTH SIZE DEPTH SIZE TESTER DRILL PIPE DATA CUP PLUG NONE SIZE WT GRADE CONN

MUD WEIGHT:

THIS TEST:

UNIT

TYPE

SIZE

PRESSURE RATING

ANNULAR

PSI

PIPE RAMS BLIND RAMS PIPE RAMS PIPE RAMS

PSI PSI PSI PSI

PCF

ACCUMULATOR UNIT DATA

NOTE:

USEABLE OPERATING PRESSURE VOLUME GAL PSI GAL PRECHARGE PRESSURE DATE LAST CHECKED PSI

HYDRIL TO BE TESTED @ 70% RATED WORKING PRESSURE WITH PIPE IN HOLE

SYSTEMS CAPACITY

MANIFOLD PRESSURE ANNULAR

ACCUMULATOR

CUT-IN PRESSURE

AIR PUMPS ELECTRIC PUMPS

MANIFOLD PSI

TEST DETAILS CUT-OFF PRESSURE PSI PSI

PSI PSI

PSI

TEST OF AUXILIARY SYSTEMS AS PER SAUDI ARAMCO WELL CONTROL MANUAL KILL LINE PSI

CHOKE LINE

MANUAL

HCR

CHECK

KILL

MANUAL

HCR

CHOKE

VALVE

VALVE

VALVE

LINE

VALVE

VALVE

LINE

KELLY SWACO LEFT

RIGHT

EMERGENCY KILL LINE

UPPER

LOWER

MANUAL

HCR

KILL

COCK

COCK

VALVE

VALVE

LINE

LOW HIGH TIME LOW HIGH REMARKS:

DRILLER SIGNATURE

Revision Date: 02/01/2014 Form # 2.0

TOOLPUSHER SIGNATURE

COMPANY REPRESENTATIVE SIGNATURE

Page 1 of 2

PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT RIG:

WELL NUMBER:

PREVIOUS TEST:

THIS TEST:

ALTERNATE BI-WEEKLY TESTS WITH

BOP TEST IN PSI AND TIME

CHARGING SYSTEM ISOLATED

TEST PRESSURE LOW HIGH

UNIT

ANNULAR PIPE RAMS BLIND RAMS PIPE RAMS PIPE RAMS

PSI PSI PSI PSI PSI

DURATION OF TEST LOW HIGH PSI PSI PSI PSI PSI

CLOSE

MIN MIN MIN MIN MIN

MIN MIN MIN MIN MIN

OPEN

SEC SEC SEC SEC SEC

BOTTLE BANKS ISOLATED

CLOSE

SEC SEC SEC SEC SEC

OPEN

SEC SEC SEC SEC SEC

SEC SEC SEC SEC SEC

ARE THE BELOW ITEMS ON THE RIG AND IN GOOD WORKING ORDER: YES

YES

NO

ROTATING HEAD AND STRIPPER (PACK-OFF)

ACCUMULATOR BOTTLE AND TEST GAUGE

STRIPPING VALVE (TIW)

FILL ADAPTER FOR NITROGEN BOTTLE

DRILL PIPE BACK PRESSURE VALVE (INSIDE BOP)

SPARE NITROGEN BOTTLES

X-OVER: DC x DP

DRILL PIPE PRESSURE GAUGE

KELLY COCK WRENCH (S)

ANNULAR PRESSURE GAUGE

ADJUSTABLE CHOKES STEM AND BONNETS

DRILL PIPE FLOAT VALVE

MUD GAS SEPARATOR

DE-GASSER

P.V.T. SET TO ALARM AT 10 BBLS

ALL BOLTS, STUDS & NUTS INSTALLED AND TIGHTEN PROPERLY

CHOKE MANIFOLD LINED UP FOR A HARD SHUT-IN

ALL RING GASKETS ARE NEW

NO

REMARKS:

DRILLER SIGNATURE

Revision Date: Form # 2.0

02/01/2014



Page 2 of 2

DESCRIPTION OF BLOWOUT PREVENTERS AND INTERNAL COMPONENTS RIG:

WELL NUMBER:

BLOWOUT PREVENTERS ANNULAR PREVENTER SIZE WORKING PRESSURE

RAM PREVENTERS SIZE WORKING PRESSURE

MODEL

MAKE

SERIAL #

ELEMENT PART #

TYPE PIPE BLIND PIPE PIPE

MAKE

SERIAL #

SINGLE/DOUBLE

INTERNAL COMPONENTS UNIT

RAM SIZE

RAM BLOCK #

RAM PACKER #

TOP SEAL #

BONNET/DOOR SEAL #

CONN. ROD SEAL #

DATE INSTALLED

ANNULAR PIPE RAMS BLIND RAMS PIPE RAMS PIPE RAMS

REMARKS:

DRILLER SIGNATURE

Form # 1.0



Date: 02/01/2014

CAMERON INFORMATION SHEET

01-001

SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR) Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout Preventers PURPOSE: To provide information on qualification test results and new part numbers assigned to qualified blade and side packers Qualification Requirement: API 16A 2nd Edition, Appendix C plus additional pressure hold time at elevated temperatures Test Conditions: BOP used – Cameron 13-5/8”-10,000 psi U mounted on a special test stump with internal heating system Test Fluid – Synthetic hydrocarbon motor oil (to simulate a mineral oil based drilling mud) Test Temperatures - 250°F, 300°F, and 350°F Test Pressure – 10,000 psi Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold all test temperatures - Cameron Requirement – An additional 8 hour pressure hold - 250°F - An additional 3 hour pressure hold - 300°F and 350°F Results – Standard Cameron Blade and Side Packers qualify to API 16A, 2nd Edition, Appendix C high temperature verification test requirements and successfully complete Cameron required additional 8 hour pressure hold test at 250°F . - High Temperature Cameron Blade and Side Packers qualify to API 16A, 2nd Edition, Appendix C high temperature verification test requirements and successfully completed Cameron required additional 3 hour pressure hold test at 300°F and 350°F .

U BOP Shearing Blind Ram

CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13

U BOP H2S Shearing Blind Ram

1


01-001

SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR) Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout Preventers Applicable Part Numbers BOP Size - Pressure Rating

Up to 250°F & 5% H2S

Description

Up to 350°F & 35% H2S

11’-10,000 psi

Blade Packer Side Packer Side Packer Top Seal

046910-04-00-01 046751-04-00-01 046752-04-00-01 644217-01-00-01

644834-04-00-01 2164284-04 2164285-04 644703-01-00-01

13-5/8”-10,000 psi

Blade Packer Side Packer Side Packer Top Seal

644435-01-00-01 046751-01-00-02 046752-01-00-02 644223-01-00-01

644834-01-00-01 645427-01 645428-01 644707-01-00-01

For additional information contact Cameron Elastomer Technology (CET), Katy Texas or your local Cameron representative.

29501 Katy Freeway, Katy, Texas 77494

CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13

Tel: 281-391-4615 Fax: 281-391-4640

2

Spare Parts List for 13-5/8” 10M Type “U” Large Bore Shear Bonnet and Shear Rams High Temperature and H2S Service Item

Part Number

Description BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for 13-5/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, PER API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE), NACE, EST. NET WT. = 3,850 LBS. BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for 135/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, PER API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE), NACE, EST. NET WT. = 3,850 LBS. BONNET BOLT: for LARGE BORE SHEAR Bonnets, 13-5/8" 10M WP TYPE 'U' BOP, MODEL II BONNET REBUILD KIT: for LARGE BORE SHEAR RAM, 13-5/8" 3M/5M/10M WP TYPE 'U' BOP (parts for ONE BONNET), 350 DEG SERVICE

Qty

1 EA

1.

2011803-01

2.

2011803-02

3.

041366-12

4.

2164210-09

5.

644573-03-00-01

BONNET SEAL: for 13-5/8" 3M/5M/10M 'U' BOP, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE)

2 EA

6.

645077-36-00-01

SEAL, LIP: CONNECTING ROD; for 13-5/8" 3M-15M, 20-3/4" 3M, 21-1/4" 2M and 26-3/4 3M TYPE 'U' BOP, 5.505" OD X 4.008" ID X 0.938" LG, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE)

2 EA

7.

644781-03

RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 13-5/8" 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM)

1 EA

8.

644781-04

RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 13-5/8" 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM)

1 EA

9.

644581-01-00-01

INSERT BLADE: UPPER, H2S SBR, for 13-5/8" 10M WP TYPE 'U' AND 'T' BOP, PER QP-10005-01

1 EA

10.

644581-02-00-01

INSERT BLADE: LOWER, H2S SBR, for 13-5/8" 10M WP TYPE 'U' AND 'T' BOP, PER QP-10005-01

1 EA

11.

644834-01-00-01

BLADE PACKER: SBR, for 13-5/8" 3M-15M WP TYPE 'U' BOP, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE)

1 EA

12.

645427-01

SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP, CAMRAM 350 (TM)

2 EA

13.

645428-01

SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP, CAMRAM 350 (TM)

2 EA

14.

644707-01-00-01

TOP SEAL: for 13-5/8" SBR, 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF"

2 EA

15.

644582-01

MODIFIED SET SCREW: for 13-5/8" 10M TYPE ‘U’ UPPER SHEARING BLIND RAM, .750-10 UN-2

2 EA

16.

200231

PIN: SPIROL - .250 X 1.000 SST 18-8

2 EA

17.

2164148-02

REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR ORIGINAL STYLE, 11" 15M AND 13-5/8" 3M-10M TYPE 'U' BOP (QUANITY for 1 UNIT)

1 EA

1 EA

8 EA 2 EA

09/15/02

Spare Parts List for 11” 10M Type “U” Large Bore Shear Bonnet and Shear Rams High Temperature and H2S Service Item

Part Number

Description

Qty

2164067-02

BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for 11" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE), NACE, EST. NET WT. 2,620 LBS.

1 EA

2.

2164067-01

BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for 11" 10M WP TYPE 'U' BOP, WITH TANDEM BOOSTER, MANUAL LOCKING SCREW AND BONNET BOLTS, API 16A, T-20, OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE), NACE, EST. NET WT. 2,620 LBS.

1 EA

3.

041366-05

BONNET BOLT: for LARGE BORE SHEAR RAM, 11" 10M WP TYPE 'U' BOP, MODEL II

8 EA

4.

2164210-12

BONNET REBUILD KIT: for LARGE BORE SHEAR RAM, 11" 3M/5M/10M WP TYPE 'U' BOP (PARTS for ONE BONNET), 350 DEGREE SERVICE

2 EA

5.

644573-02-00-01

BONNET SEAL: 11" 3M/5M/10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

6.

645077-38-00-01

SEAL, LIP: CONNECTING ROD; fOR 11" 5M/10M WP TYPE 'U' BOP, - 4.867" OD x 3.383" ID x 0.688" LG, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

7.

645011-01-00-01

RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 11" 5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF' (0-350 DEGREE SERVICE)

1 EA

8.

645011-02-00-01

RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 11" 5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF' (0-350 DEGREE SERVICE)

1 EA

9.

645010-01-00-01

INSERT BLADE: UPPER, H2S SBR, for 11" 5M/10M WP TYPE 'U' BOP, API 16A

1 EA

10.

645010-02-00-01

INSERT BLADE: LOWER, H2S SBR, for 11" 5M/10M WP TYPE 'U' BOP, API 16A

1 EA

11.

644834-04-00-01

BLADE PACKER: SBR, for 11" 3M-15M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

1 EA

12.

2164284-04

SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

13.

2164285-04

SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)

2 EA

14.

644703-01-00-01

TOP SEAL: for 11" SBR, 3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF"

2 EA

15.

644582-01

MODIFIED SET SCREW: for 11" 10M TYPE ‘U’ UPPER SHEARING BLIND RAM, .750-10 UN-2

2 EA

16.

200231

PIN: SPIROL - .250 X 1.000 SST 18-8

2 EA

17.

2164148-03

REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR ORIGINAL STYLE WITH ST/STL END CAP, for 11" 3/5/10M TYPE 'U' BOP (QUANTITY FOR ONE UNIT)

1 EA

1.

09/15/02

Shaffer A Varco Company

Spare Parts List for 13-5/8” 10M Model ‘SL’ Large Bore ‘V’ Shear Rams High Temperature and H2S Service Item

Part Number

Description

Qty

1.

124992

BOOSTER KIT: 10” BOOSTER ASSEMBLY CONVERSION KIT FOR 13-5/8” 10M WP TYPE ‘SL’ RAM BOP, NACE (COMPLETE WITH 22 COMPONENTS).

2 EA

2.

114651

RAM SHAFT: POSLOCK FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE.

2 EA

3.

132492

RAM SHAFT SUB-ASSEMBLY (RSSA): FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE.

2 EA

4.

030102

CYLINDER O-RING:

2 EA

5.

030791

CYLINDER O-RING:

2 EA

6.

030105

CYLINDER BACK-UP RING:

2 EA

7.

030061

MANIFOLD O-RING:

8 EA

8.

030065

HINGE BRACKET O-RING:

4 EA

9.

134481

POSLOCK PISTON ASSEMBLY: FOR 13-5/8" 10M WP TYPE 'SL' BOP, NACE.

2 EA

10.

RAM V-SHEAR: COMPLETE WITH 13-5/8” 10M WP ULTRATEMP ™ ELASTOMERS (350 DEGREES F AND 20% H2S)

1 EA

11.

RAM RUBBER ASSEMBLY: UPPER, V-SHEAR, ULTRATEMP ™ (350 DEGREES F AND 20% H2S)

1 EA

12.

RAM RUBBER ASSEMBLY: LOWER, V-SHEAR, ULTRATEMP ™ (350 DEGREES F AND 20% H2S)

1EA

10/01/02


02-001

SUBJECT: Cameron Extended Range High Temperature VBR-II Packers for Cameron 13-5/8” U Type Blowout Preventers PURPOSE: To provide information on qualification test results and new part numbers assigned to 250°F - 5000 psi Extended Range HT VBR-II packers for the 13-5/8" Cameron U BOP. Qualification Requirement: API 16A 2nd Edition, Appendix C plus additional pressure hold time at elevated temperature. Test Conditions: BOP used – Cameron 13-5/8”-10,000 psi U BOP mounted on a special test stump with internal heating system. Test Fluid – Synthetic hydrocarbon oil (to simulate a mineral oil based drilling mud). Test Temperatures - 250°F Test Pressure – 5,000 psi Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold at 250°F - Cameron-Saudi Aramco Requirement – An additional 7-hour pressure hold at 250°F Results – Extended Range HT VBR-II Packers P/N 2164765-01 successfully completed: 1-API 16A, 2nd Edition, Appendix C high temperature verification test requirements for one hour on both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi. 2-Cameron-Saudi Aramco requirement - an additional 7 hour pressure hold test on both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi. Total time at 250°F and 5000 psi, 16 hours. 3-API 16A fatigue test (546 closures and 78 pressure tests) at ambient temperature.

Ram Subassembly P/N 2164806-01 Top Seal P/N 2164807-01

Ram P/N 2164404-01

Extended Range HT VBR-II Packer P/N 2164765-01

250°F - 5000 psi Extended Range HT VBR-II Packer & Top Seal

CIS 02-001 / 6-11-02 / Ext Range HT VBR-II

1


02-001

SUBJECT: Cameron Extended Range High Temperature VBR-II Packers for Cameron 13-5/8” U Type Blowout Preventers Applicable Part Numbers BOP Size Pressure Rating 13-5/8”

5,000 psi

Description

Part Number

Ram subassembly Ram Ext. Range HT VBR-II Packer HT/SS VBR Top Seal

2164806-01 2164404-01 2164765-01 2164807-01

Note: The Extended Range HT VBR-II packers and HT/SS top seals are molded using CAMLAST(tm) elastomer, which provides H2S resistance up to 35%.

For additional information contact Cameron Elastomer Technology (CET), Katy Texas or your local Cameron representative.

29501 Katy Freeway, Katy, Texas 77494

CIS 02-001 / 6-11-02 / Ext Range HT VBR-II

Tel: 281-391-4615 Fax: 281-391-4640

2

Engineering Standard SAES-B-062

23 July 2009

Onshore Wellsite Safety Loss Prevention Standards Committee Members Ashoor, Esam Ahmed, Chairman Fadley, Gary Lowell, Vice Chairman Ageel, Adel Abdulaziz Churches, David Kenneth Cole, Anthony Richard Ghobari, Ali Mahdi Hassar, Fahad Abdullah Janaby, Mohammad Taqy Juraifani, Hatim Hamad Sayed, Salah Moh'D Al-Housseiny Seba, Zaki Ahmed Solomon Jr, Clarence Ray Sultan, Sultan Abdul Hadi Utaibi, Abdul Aziz Saud Zahrani, Mansour Jamman

Saudi Aramco DeskTop Standards Table of Contents 1 2 3 4 5 6 7 8 9

Scope............................................................. 2 Conflicts and Deviations................................. 2 References..................................................... 2 Definitions....................................................... 3 Determination of Rupture Exposure Radius (RER).......................................... 8 Wellsite Location............................................ 9 Well Safety Valves and Wellsite Hardware.. 13 Abandoned Wells......................................... 15 Drilling Rig Access Routes........................... 16

Appendix 1 – Procedure for Determining RER of Oil and Gas Wells.................................... 17

Previous Issue: 31 March 2009 Next Planned Update: 31 March 2014 Primary contact: Ashoor, Esam Ahmed on 966-3-8728431 Copyright©Saudi Aramco 2009. All rights reserved.

Page 1 of 32

Document Responsibility: Loss Prevention Standards Committee Issue Date: 23 July 2009 Next Planned Update: 31 March 2014

1

2

3

SAES-B-062 Onshore Wellsite Safety

Scope 1.1

This Standard covers the minimum mandatory requirements for site layout, wellhead protection, access, and flow isolation for all wells that are drilled into or through a geological zone that contains hydrocarbons such as oil and gas production wells, water injection wells, observation wells, abandoned wells, suspended wells, and waste disposal wells.

1.2

This standard shall apply in the following circumstances: 1.2.1

All new wellsites.

1.2.2

All new wells drilled at existing wellsites.

1.2.3

Re-activation of previously abandoned or suspended wells or re-drilling of existing wells such as drilling of new laterals or deepening.

1.2.4

Existing wells located in areas that have become populated per this Standard shall be upgraded with automated shut-in systems, vehicle crash protection, fencing, wind socks, and other items only when a workover is required for other remedial work.

Conflicts and Deviations 2.1

Any conflicts between this Standard and other applicable Saudi Aramco Engineering Standards (SAESs), Saudi Aramco Materials System Specifications (SAMSSs), Saudi Aramco Standard Drawings (SASDs), or industry standards, codes, and forms shall be resolved in writing by the Company or Buyer Representative through the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

2.2

Direct all requests to deviate from the Standard in writing to the Company or Buyer Representative, who shall follow internal company procedure SAEP-302 and forward such requests to the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

References All referenced specifications, standards, codes, forms, drawings, and similar material shall be of the latest issue (including all revisions, addenda, and supplements) unless stated otherwise. 3.1

Saudi Aramco References Safety Management Guides [http://lp.aramco.com.sa/]

Page 2 of 32



Emergency Management Guide Safety Management Guide for Emergency Preparedness Saudi Aramco Engineering Procedure SAEP-302

Instructions for Obtaining a Waiver of a Mandatory Saudi Aramco Engineering Requirement

Saudi Aramco Engineering Standards SAES-B-064

Onshore and Nearshore Pipeline Safety

SAES-F-007

System Design Criteria of Flares

SAES-J-505

Combustible Gas and Hydrogen Sulfide in Air Detection Systems

SAES-L-410

Design of Pipelines

SAES-M-006

Fencing

Saudi Aramco Materials System Specification 34-SAMSS-624

Wellhead Control, Monitoring and Shutdown Systems

45-SAMSS-005

Wellhead Equipment

Saudi Aramco Standard Drawings

3.2

AA-036454

Remote Controls for Onshore Wells

AB-036685

Wellhead Guard Barrier

Industry Codes and Standards American Petroleum Institute API RP 14B

4

Design, Installation, Repair and Operation of Subsurface Safety Valve Systems

Definitions Absolute Open Flow (AOF): In general terms, the rate of flow that would be produced by a well if the only back-pressure at the surface is atmospheric pressure. Choke: An adjustable pressure control valve that is used to control backpressure on the well. Controlling the backpressure adjusts the production rate of the well.

Page 3 of 32



Drilling Island: A wellsite for drilling one or more wells, normally used in populated areas to minimize land usage. A drilling island is an exclusive land use area. Drilling Pad: A compacted area of marl located at the wellsite. The drilling pad is required to be level for use by drilling and workover rigs. Gas-Oil Ratio (GOR): The ratio of volume of gas produced from a well in a barrel of crude oil at standard conditions (14.7 psia, 15°C). GOSP: A gas-oil separation plant (GOSP) is a plant area where water and gas are separated from the produced crude oil so that the oil is of suitable quality for shipping through a pipeline to an oil terminal or to a refinery. The gas is sent to gas plants for further processing. High-Population Building: Any building, such as a office building, mosque, cafeteria, or training building, that can be expected to contain 25 or more people at any time. H2S: Hydrogen Sulfide, a colorless toxic gas that is sometimes produced with natural water, crude oil, and natural gas. High Pressure Well: Wells where the shut-in wellhead pressure is expected to exceed 20,700 kPa (3000 psig). Kick: A unplanned flow of reservoir gas, oil or water from the formation into the wellbore during drilling operations. Low Pressure Well: Wells where the shut-in wellhead pressure is not expected to exceed 20,700 kPa (3000 psig). LFL: Lower flammable limit of a fuel vapor in air mixture. If a vapor/air mixture is above the LFL, a fire is likely in the presence of an ignition source. Major Facility: The outer-most security fence, property line, or other demarcation of land-use claim of refineries, gas treatment, NGL plants, gas-oil separating or processing facilities, and the property line of any third party manufacturing facilities (Refer to Table 1 below for examples).

Page 4 of 32



Table 1 – Examples of Major Facilities Refineries

Gas Treating

NGL

Jeddah

Berri

Juaymah

Rabigh

Uthmaniyah

Yanbu

Oil Process Abqaiq Plants Complex Safaniya Onshore GOSP Tanajib Onshore GOSP; Khursaniya

Ras Tanura

Shedgum

Riyadh

Hawiyah

Shaybah CPF

Haradh

Khurais

Terminals

Non-Aramco

Juaymah

SCEC Power Generation (formerly SCECO)

Jeddah

SWCC Treatment

Ras Tanura (North & South)

Commercial International Airports

Yanbu

Jubail or Yanbu Industrial Complexes

Non-Associated Gas Fields: Areas that are developed for the primary purpose of producing natural gas. The produced gas is not a by-product of crude oil production. Population: Any concentration or grouping of people. Population is normally indicated by the existence of buildings, but may also be a camp site, a site where construction or maintenance crews are working. Separation spacing from a well shall be measured from the nearest fence or other landmark that indicates the boundary. For the purposes of this standard, a road or highway is not considered population. Populated Area: For the purposes of this standard, a well is in a “populated area” if the population exceeds 20 persons residing, working, or otherwise located inside the 30 ppm rupture exposure radius (RER). For the purpose of this Standard, the number of persons considered does not include personnel residing at the rig camp, on-site workers in support of the drilling or workover rig, or the occupants of vehicles traveling on roads or highways. Rupture Exposure Radius (RER): 1)

For toxic effects, the rupture exposure radius refers to the horizontal distance from a leak source to a specified level of hydrogen sulfide (H2S) concentration in parts per million (ppm).

2)

For a flammable gas hazard, the rupture exposure radius refers to the horizontal distance from a leak source to the ½ Lower Flammable Limit (LFL).

Surface Safety Valve (SSV): An automated spring-assisted fail-safe valve installed on a wellhead to automatically shut in flow during an abnormal condition such as high or low pressure of the flowline. This can be the upper master valve, a wing valve (upstream of choke), or a production valve (downstream of the choke). Page 5 of 32



Suspension Procedure: Wireline or workover rig procedures for securing a standing well from production on a long-term basis. Subsurface Safety Valve (SSSV): An automated valve installed below ground level in the tubing string of an oil or gas well. The SSSV is used to shut in flow during an abnormal condition. SSSVs, when required, shall be installed 60 m or more below ground level per API RP 14B. Wellhead: The valve manifold directly at the top of the well bore. The wellhead consists of several specialized valves including the following: a)

Crown Valve: Topmost valve of the wellhead. This valve is used for wireline and coil tubing access to the well.

b)

Lower Master Valve: The first valve on a wellhead. This is not a surface safety valve (SSV).

c)

Upper Master Valve: A second isolation gate valve just above the Lower Master Valve on a wellhead. If this is automated, it is considered a surface safety valve (SSV).

d)

Wing Valve: The valve on the side branch of the wellhead, normally located immediately upstream of the choke.

Page 6 of 32



7-1/16" 3M PSI Onshore Production Tree

7" 3M QUICK UNION TREE CAP 14-7/8"

24-1/8" 7" 3M GATE VALVE

7" 3M FLANGE 16"

7" 3M TEE 24-1/8"

7" 3M HYDRAULIC ACTUATED SSV

24-1/8"

7" 3M GATE VALVE

32-1/4"

Saudi Aramco 3M PSI WP WOG 6M PSI TP

Figure 1 – Example of Wellhead (from 45-SAMSS-005, Figure 6) Wellsite: A wellsite consists of wellhead(s), associated drilling pad, a well flare/burn pit area or areas, and flare/burn pit buffer zone(s). The entire wellsite constitutes an exclusive land use area. No other uses are permitted in this area, except as allowed by this Standard. Size of the wellsite and distances between wellheads shall be specified by Drilling and Workover Engineering, Drilling Operations, Production and Facilities Development (P&FDD), and the Proponent Operating Department, on a case-by-case basis. Well Status: Wells that are not flowing oil or gas may be described by the following terms: a)

Abandoned Well: A well that is permanently plugged with cement. This well Page 7 of 32



cannot be produced again.

5

b)

Observation Well: A well drilled to monitor reservoir conditions such as bottomhole pressure in the reservoir.

c)

Suspended Well: A well that has been shut-in on a long term basis with all productive zones isolated and production shut-off on a long-term basis.

d)

Standing Well: A well that is shut-in awaiting action, such as flowline tie-in or well perforation, before it can be returned to production.

Determination of Rupture Exposure Radius (RER) 5.1

Three concentric circles representing the three rupture exposure radii - 30 ppm, 100 ppm hydrogen sulfide (H2S) and ½ lower flammable limit (LFL) shall be plotted from the well's proposed surface location as shown in Figure 2 below. Refer to Appendix 1 for procedures to determine the RERs.

5.2

For fields, reservoirs, or service not listed in Appendix 1, the rupture exposure radius shall be obtained from the Saudi Aramco Loss Prevention Department's Technical Services Unit. In order to calculate the RER, the following information should be provided with the request: Well composition of produced fluid (mole %), temperature (Flowing Wellhead Temperature, FWHT), and AOF for gas wells or maximum flow rate and GOR for oil wells.

Figure 2 – RERs A well is considered to be in a “populated area” if the population is above 20 persons living, working, or otherwise located inside the 30 ppm H2S RER (see 6.3). In populated areas, requirements in sections 6.5, 7.3, and 7.7, and 8 apply.

Page 8 of 32


6


Wellsite Location 6.1

Wells that are drilled through a hydrocarbon bearing formation shall be located so that no person(s) unrelated to the drilling activity, no portion of an occupied building or manned facility is within the well's 100 ppm H2S or ½ LFL RER. The RER for a well is normally provided by Production and Facilities Development Department (P&FDD). Minimum spacing shall not be less than that stated in Table 2. The RER to be used for well spacing shall be based on the worst case of all hydrocarbon zones that are penetrated during drilling. Where evacuation is strategically not feasible e.g. electrical power plants, military defense installations, hospitals, schools, or major facilities, wells shall be located so that such no portion of these types of establishments or facilities are within the well’s 30 ppm H2S RER. Exception: Mobile rig camps at the rig location and unoccupied lands, such as those used primarily for agriculture, are not required to meet this spacing requirement. Emergency response coordination with any on-site workers is required to meet Section 6.9 below.

6.2

Manifolds, significant aboveground appurtenances for cross-country transportation pipelines such as junctions containing a several scraper launcher/receiver facilities, Khuff and Jouf gas distribution facilities, and their associated utilities, roads, highways, and expressways, are allowed to be within the 100 ppm H2S circle but not within the ½ LFL RER nor closer than the minimum spacing stated in Table 2. Table 2 – Spacing from Oil and Gas Wells (4, 5) Minimum Spacing from the Wellhead

Facility (1, 2)

Pipelines Overhead powerlines for site-related CP, etc. (<69 kV); site related rectifiers Main overhead powerlines

100 m 200 m

Saudi Aramco or Government roadways Divided Limited-Access Expressways

60 m

(3)

(3)

(3)

100 m 150 m

Railroads Major electrical distribution centers (use only if 100 ppm H2S RER is <450 m) Occupied buildings, major facilities (use only if 100 ppm H2S RER is < 450 m)

150 m

Non-well flares and burn pits Hospitals and schools (use only if 100 ppm H2S RER is < 1000 m)

450 m 1000 m

450 m 450 m

Page 9 of 32



1)

The existing elevated marl pad around wellhead(s) on a wellsite shall not be crossed by a pipeline. Rig access shall not be obstructed by installation of a pipeline. In addition, the minimum spacing does not apply to flowlines that are associated with a multi-well wellsite.

2)

New wells may require additional spacing from existing flowlines for wellsite construction and drilling operations. Spacing shall be increased as needed at the request of the Drilling Services or Drilling Operations Departments.

3)

Spacing from the well to the closest edge of right-of-way, such as a fence.

4)

Minimum spacing applies to wells drilled after March 30, 2001.

5)

Wells are to be spaced a minimum of 60 m from the closest edge of a burn pit for an oil well or LP gas well and 150 m from a flare for a HP gas well. See Table 3 for more details on flare burn pits.

6.3

Water gravity injector, power injector and supply wells that penetrate hydrocarbon formations shall be spaced the same as hydrocarbon producing wells. Injector and supply wells that do not penetrate hydrocarbon bearing formations shall have a basic 60 m minimum spacing requirement from plant equipment, buildings, etc. Gas injection wells shall use the same location criteria as producing gas wells.

6.4

A well is in a “populated area” if the population exceeds 20 persons (unrelated to drilling activities) residing, working, or otherwise located within the 30 ppm H2S rupture exposure radius of that well (see Figure 2). Commentary Notes: For purposes of this Standard, roads do not generate populated areas. Where wells are located near areas of potential concern, such as roads, parking areas, or camp sites, the Proponent Operating/Engineering Department shall determine whether additional precautionary measures, such as subsurface safety valves, fencing, etc., are required.

6.5

Wells to be drilled or wells subject to workover in a populated area shall implement the following additional precautionary measures in addition to the normal drilling safety program during drilling of hydrocarbon zones. Other drilling precautionary measures may be added at the request of the Manager, Loss Prevention or the General Manager of Drilling and Workover. Precautionary measures during drilling and workover in a populated area: 1.

Rig-site H2S monitoring systems with 24-hour coverage by a competent and qualified safety professional.

2.

Placement of remote H2S monitors in the vicinity of populations and nearby facilities to monitor H2S levels at those locations in an emergency.

Page 10 of 32



3.

An additional one-hole volume of kill-weight mud available at the drillsite for immediate use.

4.

Capability of cutting the drill pipe with shear rams.

5.

On-site coverage 24 hours a day by on-site foremen (minimum 2-man coverage on 12-hour shifts) with authority for immediate ignition of the well without prior approval in the event of loss of well control.

6.

Capability of burning gas in a controlled release using a properly designed separation system and an elevated flare with pilot (Only for wells to protect population within the 30 ppm H2S RER; the use of this equipment is not required for drilling near GOSPs, process plants or facilities). The design, location, and elevation of flare shall take into account the potential dispersion of flammable or toxic materials from the flare during a flameout condition, the toxic products of combustion, such as sulfur dioxide, during flare operation, and other design considerations as specified in SAES-F-007. Alternative designs for gas handling shall follow a management of change (MOC) engineering process. The design shall be approved by the Manager, Drilling Operations and Manager, Drilling Technical Department. Commentary Note: The intent of the MOC process is to assure compliance with standards, material specifications, and Codes that apply for gas handling facilities. The engineering review provides a check on the engineering soundness, concepts, and calculations used in the design. The dispersion analysis is required in order to identify alternative design or procedures needed to protect life safety should the flare extinguish during operation.

7.

A wellsite emergency response plan that meets the Saudi Aramco Safety Management Guide for Emergency Preparedness.

8.

Other applicable safeguards as needed.

6.6

Under no circumstances shall population be exposed to over 30 ppm H2S gas concentration for more than 1 hour.

6.7

Well burn pits shall be subject to the same spacing from population and major facilities as well spacing. The exceptions to 6.1 shall also apply to burn pits. Minimum spacing shall meet Table 3. 6.7.1

Oil wells and low-pressure gas wells shall have at least one flare while being drilled.

6.7.2

High-pressure gas well shall have two flares while being drilled.

Page 11 of 32



6.7.3

Burn pits shall be at predominantly downwind and crosswind locations, at least 60 meters from the well (300 m for high-pressure gas wells) ranging from 60 to 270 arc degrees from true North. Burn pits shall be placed to point away from populations and facilities as much as possible.

6.7.4

If there are two flares, they should be a minimum of 90 degrees and a maximum of 180 degrees from each other and pointing away from populations and facilities as much as possible. Table 3 – Spacing from Well Burn Pits (3) Minimum Spacing from Oil & Gas Well Burn Pits 60 m (Oil & LP Gas) 300 m (HP Gas Well) 60 m (Oil & LP Gas) 150 m (HP Gas Well)

Facility Well and Well Burn Pits

(1)

Existing Wellheads Pipelines (Above Ground) Pipelines (Buried)

60 m

(2)

30 m

Main Overhead Powerlines Overhead Powerlines for Site-Related CP, etc., (<69 kV); Site Related Rectifiers Powerlines (Buried)

(2)

Railroads

(3)

100 m 30 m

Saudi Aramco or Government Roadways Divided Limited-Access Expressways

200 m

(3)

(3)

100 m (Oil Wells and LP Gas) 200 m (HP Gas Wells)

450 m (Oil and Gas Wells) 200 m

Population (use only if RER <450 m)

450 m

Non-well Flares and Burn Pits Hospitals and Schools (use only if RER < 1000 m)

450 m 1000 m

1)

Spacing of any well related burn pit from a well being drilled shall be a minimum distance of 60 m for an oil well and 300 m minimum for a high-pressure gas well. Wells are to be spaced a minimum of 60 m from the closest edge of a burn pit for an oil well or LP gas well and 150 m from a flare for a HP gas well. A minimum of 60 m buffer zone shall be maintained around the outside of each burn pit (not on the wellsite side). The edges of the burn pits shall have a 2 m high berm (minimum elevation above flare outlet center).

2)

Buried CP powerlines, flowlines, and trunklines related to a wellsite shall have no other spacing restrictions provided the powerlines do not interfere with rig access or future production flare operations.

3)

Spacing from the closest edge of the burn pit to the edge of the right-of-way.

Page 12 of 32



6.8

For existing wells in populated areas, the special precautions in 6.5 shall be used for workovers. Precautions appropriate for stimulation and wireline work on existing wells shall be as requested by the Proponent Operating Department, Drilling and Workover Services, and Loss Prevention as needed.

6.9

Pre-incident Emergency Response Planning 6.9.1

In areas where drilling will take place, an emergency response plan that meets the Saudi Aramco Safety Management Guide for Emergency Preparedness shall be created and used by drilling operations, facility proponents, responding personnel, Saudi Aramco communities, and other entities to manage emergency response to a drilling, workover, or producing related incident. Commentary Note: Refer to the Emergency Management Guide (http://lp.aramco.com.sa) for information on how to develop, implement, and maintain a viable emergency management program.

7

6.9.2

The plan shall indicate locations where people may be located within the 30 ppm RER or 5 km of the wellsite, whichever is greater. Such locations include, but are not limited to, occupied buildings, employee housing compounds, shopping complexes, office buildings, manned facilities, factories, camp grounds, schools, hospitals, project construction sites, and other similar situations. The plan shall include an effective notification protocol for all locations where people may be impacted by a drilling, workover, or producing related incident.

6.9.3

Participants in the plan shall receive training to help communicate the plan’s expectations, especially those entities that do not normally work together.

6.9.4

A system for using the plan shall be in place so that the plan itself or a summary of key elements can be accessed by the responders while in transit to and at the site of the incident.

6.9.5

Facilities that are potentially impacted shall modify their own emergency response plans to help provide guidance on how to respond to a nearby wellsite related incident.

Well Safety Valves and Wellsite Hardware 7.1

Hydrocarbon Producing and/or Hydrocarbon Injection Wells - General Requirements

Page 13 of 32


7.1.1


All well installations shall be in accordance with the specifications prepared by Saudi Aramco Drilling and Workover Engineering. Refer to 34-SAMSS-624 and 45-SAMSS-005 for the minimum requirements for Saudi Aramco oil and gas production trees, wellheads, valves and miscellaneous equipment relating to the wellhead. Naturally flowing hydrocarbon wells shall be completed in a manner that permits flow only through a tubing string equipped with a downhole packer or polished bore receptacle.

7.1.2 Requirements for wellhead piping, flowlines, trunklines, and testlines are covered in SAES-L-410.

7.2

7.1.3

All wells shall have a manual lower master valve.

7.1.4

At the discretion of the Proponent Operating Department, oil wells may be equipped with manual remote operators attached to the master valve and/or wing valve. If manual remote operators are installed on oil wells, they shall be in accordance with Standard Drawing AA-036454.

7.1.5

Any lockout device used to temporarily hold a surface safety valve (SSV) in the open position by restricting movement of the valve stem shall be constructed of fusible materials with a melting point 30°C above the higher of the flowing wellhead or maximum design ambient temperature.

Safety Valves for HP Gas Producing Wells 7.2.1

All high-pressure gas production wells shall have at least two springassisted failsafe surface safety valves (SSVs).

7.2.2

The two SSVs shall be triggered when an abnormally high or low pressure is sensed in the piping to the well. Fusible devices, with a set point 30°C above either the flowing wellhead or the maximum design ambient temperature, whichever is highest, shall be installed on the wellhead to close the safety valves.

7.2.3 At the discretion of the Proponent Operating Department, addition of other automated valves, such as subsurface safety valves, shall be installed as requested. 7.3

Safety Valves on Oil Wells and Low Pressure Gas Wells 7.3.1

Where an oil well or low pressure gas well is in a populated area or where the associated flowline has Location Class 3 or 4 populations (as specified in Tables 1 and 2 of SAES-B-064), the well shall be provided with an SSV and SSSV. Page 14 of 32



7.3.2

For all existing oil wells and low pressure gas wells in populated areas or where areas become populated due to growth of communities, those wells shall remain active, but shall require installation of a SSV and SSSV. The upgrade shall be done only when other needs justify the use of a rig on the well.

7.3.3

The upper wellhead master valve shall be a spring-assisted fail-safe surface safety valve (SSV), triggered when an abnormally high or low pressure is sensed.

7.3.4

A subsurface safety valve (SSSV), per API RP 14B specification, shall be installed more than 60 m below ground level in oil wells. The SSSV shall be triggered when an abnormally high or low pressure is sensed.

7.3.5

A fusible device with a melting point 30°C above the higher of the flowing wellhead temperature or maximum design ambient temperature shall be installed on the wellhead to trigger the SSV and SSSV systems. Commentary Note: Values for pipeline associated RERs are found in SAES-B-064, Tables 1 and 2. Location Class 3 is where the pipeline RER includes areas with a population greater than 30. Location Class 4 is where the pipeline RER includes 4-story or greater buildings, schools, hospitals, hotels, prisons, shopping malls or similar retail complexes.

Table 4 – Well Safety Valves Additional Drilling Precautions Oil/LP Gas Well – (a) Unpopulated Area Oil/LP Gas Well – Populated Area HP Gas Well PWI Well – Unpopulated Area PWI Well – Populated Area

No

Automated SSV No

(a)

Automated SSSV No

(a)

Yes

Yes

Yes

No

Yes, 2 SSVs

(b)

No

No

No

Yes

No

No

Note a

Even if the well is in an unpopulated area, if the flowline passes through a populated area per 8.3, an SSV and SSSV shall be required.

Note b

HP gas production wells shall have at least two spring-assisted failsafe SSVs. Addition of other automated valves, such as subsurface safety valves, shall be installed where required by the Proponent Operating Department per Section 8.2.

Page 15 of 32


7.4


Hydrocarbon Injection Wells Hydrocarbon injection well flowlines shall each be provided with a check valve in the wellhead piping.

7.5

Observation Wells Wells shall be equipped with the relevant safety devices equivalent in function to those that would be required for a producing well unless suspended with a subsurface plug or other acceptable method.

7.6

Suspended Wells Wells shall be suspended in accordance with Producing Engineering requirements. Suspension procedures for wells shall be documented by Producing Operations and shall be available for review.

7.7

7.8

8

Vehicular Crash Protection and Fencing 7.7.1

All wellheads shall be protected with a guard barrier per Saudi Aramco Standard Drawing AB-036685.

7.7.2

Wellsites and associated burn pits in populated areas shall be enclosed by a fence meeting the specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant locked at all times. Keys shall be kept with the Proponent Operating Department. Two gates shall be a minimum of 18 m wide rig-access gates. The locations of these rig-access gates shall permit access to all wells on the wellsite from either gate.

A wind sock pole and a wind sock (e.g., SAP Material Number 1000132744) are to be permanently installed at each hydrocarbon production or injection wellsite in populated areas.

Abandoned Wells The following requirements apply to a wellsite only if all its wells have been permanently plugged and if it is located in a populated area: 8.1

The perimeter of the drilling pad shall be provided with a fence (SAES-M-006, Type III) if there is no fence at the perimeter of the buffer zone.

8.2

The fence shall have one lockable vehicle gate 10 m wide.

8.3

One access route 10 m wide shall be maintained to the wellsite gate.

Page 16 of 32


9


Drilling Rig Access Routes Two land based access routes shall be available to each wellsite. These shall meet the following requirements: 9.1

Each access route shall be 18 m wide, terminating at a rig access gate.

9.2

Vertical clearance over the access routes shall be 14 m minimum.

9.3

An access route shall not include grades or transverse slopes of more than 5%.

9.4

No obstruction is allowed on an access route.

9.5

The minimum radius of curvature of access routes shall be 70 m. The center point of all access route curves shall be outside the wellsite served.

9.6

One of the access routes required by paragraph 10.1 above shall have within it a prepared roadway consisting of a compacted marl surface 0.3 m thick and 9.0 m wide with 2.5 m wide shoulders, giving a total clear road width of 14 m.

9.7

The two access roads shall have a separation of from 90 to 270 arc degrees from each other through the 100 ppm RER.

9.8

In situations where a second land-based route per 9.7 is not feasible (e.g. the wellsite is near a body of water, in wetlands, located on a peninsula, or on a causeway-connected drilling island), an alternative second method of emergency egress shall be planned for all personnel that are at the site, including all drilling personnel, non-drilling personnel, and visitors. Pre-incident planning shall also include alternative means for accessing the rig site for search and rescue, firefighting, well control, and other anticipated emergency response needs. The alternatives shall be approved by the Manager, Drilling Operations.

31 March 2009 23 July 2009

Revision Summary Major Revision. Editorial revision in Section 9.8 to removed approval by Manager, DTD.

Page 17 of 32



Appendix 1 – Procedure for Determining RER of Oil and Gas Wells Introduction To allow for more cost-effective well spacing, while at the same time maintaining a safe distance between wells and exposed populations, SAES-B-062 provides variable rupture exposure radii (RER) that are based on field and well conditions (i.e., the well fluid composition and maximum potential release rate). This appendix is based on a comprehensive analysis of RERs for Saudi Aramco oil and gas wells. Production and Facilities Development Department (PRED/1-099-99) provided the data used for the RER calculations. Tables A7 and A8, at the end of this Appendix, summarize the data provide. The RER calculations were made in accordance with LPD Guidelines for Determining the Consequences of Well Blowouts. Note that the information in Tables A7 and A8 are based on the latest LPD gas dispersion model PHAST (Version 6.0). The RERs may change in future updates of SAES-B-062 as a result of changes in well data or refinements in the models. If the information for the well or production zone needed is not in Appendix 1, contact the Supervisor, Technical Services Unit, Loss Prevention Department. The following sections illustrate the use of the correlations for predicting RERs for oil and gas wells. The correlations are of the form RER = aQb, where a and b are fieldspecific constants and Q is based on the release rate of gas from the well. Correlations are provided for the following oil and gas fields: Non-Associated Gas Fields North Ghawar Areas-Ain Dar and Shedgum Central Ghawar Areas-Uthmaniyah South Ghawar Area-Hawiyah

South Ghawar Area-Haradh Qatif Berri

Oil Fields Abqaiq (Abqaiq Cap Gas) Abu Hadriyah Abu Jiffan Ain Dar Berri Onshore Dammam Fadhili Fazran

Haradh Harmaliyah Hawiyah Khurais Khursaniyah Mazalij Qatif Shedgum Uthmaniyah

The following sections explain and demonstrate the process of RER calculations. Worksheets for calculating RERs are provided at the end of this Appendix.

Page 18 of 32



Procedure for Determining RER of Gas Wells Sour gas wells are considered in this Standard to have three Rupture Exposure Radii (RER): a 100 ppm H2S RER (RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL RER (RER½ LFL). Sweet gas wells would only have a RER½ LFL. These radii are used in SAES-B-062 to determine spacing requirements. Follow these steps when determining the RER for a gas well. 1.

Identify the gas field and reservoir for the well of interest (Contact the General Supervisor, Northern Area or Southern Area Facilities Div., Production and Facilities Development Department (P&FDD) and obtain the Absolute Open Flow (AOF) and mole fraction of hydrogen sulfide (H2S) in the gas stream. Note that the correlations included in this appendix are based upon the expected upper and lower range of AOFs and H2S content in the gas stream.

2.

Determine release rate of H2S (QH2S) from the following: QH2S = (QAOF)(xH2S) Where xH2S = mole fraction of H2S in gas stream QAOF = Absolute Open Flowrate of gas from the well, MMscfd QH2S = maximum release rate of H2S, MMscfd

3.

Use the constants in Table A6 to calculate RER100 ppm, RER30 ppm and RER½ LFL from the following RER100 ppm = e(QH2Sf); RER30ppm = g(QH2Sh); RER½ LFL = l(QAOF)m The AOF or H2S concentration of a gas mixture must fall within the limits presented in Table A6. If an AOF or the H2S concentration is outside the limits, then LPD/TSU will calculate RER values specifically for the well of interest (users need to supply LPD/TSU with well name, AOF, gas composition (mole%), and flowing wellhead temperature).

Example of RER for Gas Well As an example, consider a high-pressure gas well in the South Ghawar Area, Hawiyah. Information available indicates that the anticipated Absolute Open Flow of the well is 100 MMscfd and the H2S concentration is expected to be 3 mole%.

Page 19 of 32



The following steps are necessary to determine the RER: 1.

Data Requirements The AOF and the H2S concentration are within the ranges specified in Table A6. Table A6 indicates that the appropriate constants for this field are as follows: Table A1 – RER Constants for South Ghawar Area, Hawiyah Field (from Table A6) RER100 ppm

2.

RER30 ppm

RER½ LFL

e

f

g

h

l

m

245

0.79

700

0.77

11.7

0.54

Calculate maximum H2S release rate The maximum H2S release rate is given by the following: QH2S = (QAOF)(xH2S) = (100 MMscfd)( 3 / 100 ) =3 MMscfd of H2S

3.

Calculate RERs RER100 ppm = 245[(3).79] = 583 m RER30 ppm = 700[(3).77] = 1,631 m RER½LFL = 11.7[(100).54] = 141 m The RER for this example well are in Table A2. Table A2 – RER for Example Well Rupture Exposure Radii

Distance, m

RER100 ppm

583

RER30 ppm

1,631

RER½LFL

141

Procedure for Determining RER of Oil Wells Gas is flashed during a large release of crude and is then dispersed downwind. As with gas wells, oil wells have three Rupture Exposure Radii (RER): a 100 ppm H2S RER Page 20 of 32



(RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL RER (RER½LFL). Sweet oil wells only have a RER½ LFL. These radii are used in SAES-B-062 to determine spacing requirements and to assist in determining emergency response planning and notification. Follow these steps when determining the RER for an oil well: 1.

Identify the oil field and reservoir for the well of interest (Contact the General Supervisor, Northern Area or Southern Area Facilities Div. /P&FDD, and obtain the maximum oil flow rate, Gas-Oil Ratio (GOR) and mole fraction of hydrogen sulfide (H2S) in the oil. The correlations included in this appendix are based upon the expected upper and lower range of maximum flow rates, gas-oil ratios, and H2S content in the oil.

2.

Use the following equation to calculate the rate of gas flashed from the crude released at the maximum flow rate: Qgas = (Qoil)(GOR) /1,000 Where: Qgas = Release rate of flashed gas, MMscfd Qoil = Maximum oil release rate, Mbpd GOR = Gas-Oil Ratio, scf/stb

3.

Calculate the concentration of H2S in the flashed gas from the following equations: [xH2S]gas = [xH2S]oil where:  = a(GOR)b (Note: a, b are obtained from Table A7) Determine release rate of H2S (QH2S) QH2S = (Qgas) ([xH2S]gas) [MMscfd of H2S]

4.

Calculate RER100 ppm RER100 ppm = e(QH2S)f (Note: e, f are obtained from Table A7)

5.

Calculate RER30 ppm RER30 ppm = g(QH2S)h (Note: g, h obtained from Table A7).

Page 21 of 32


6.


Calculate RER½ LFL RER½ LFL = l(Qgas)m (Note: l, m obtained from Table A7)

If the AOF or H2S concentration do not fall within limits of Table A7, then LPD/TSU will calculate RER values specifically for the well of interest (users need to supply LPD/TSU with well name, maximum oil flow rate, oil composition (mole%), gas-oil ratio, and flowing wellhead temperature). Example of Oil Well RER Determination As an example, consider an oil well that is producing Arab-D in the Khurais field. Available information indicates the well will have a maximum flow rate of 30,000 bpd, the oil will have an H2S concentration of 2.9 mole %, and the GOR is 277. What are the RER values for this well? 1.

Available information The available information is summarized below. The maximum flow rate and the H2S concentration are within the limits specified in Table A7. Maximum Flow Rate, Mbpd

30

GOR, scf/stb

277

Mole percent of H2S in Oil

2.9%

Constants for evaluating this well are summarized in Table A3. Table A3 – RER Constants for Khurais Field (From Table A7) H2S in Flashed Gas

2.

RER100 ppm

RER30 ppm

½ LFL

a

b

e

f

g

h

l

m

2.2

0

1,285

0.69

2,656

0.64

47.3

0.63

Calculate flashed gas release rate The flow rate of released gas may be estimated by the following: Qgas = (30 Mbpd) x (277 scf/stb) = 8.31 MMscfd

3.

Calculate the H2S concentration in flashed gas  = a(GOR)b = (2.2) x (277)0 = 2.2 [xH2S]gas = [xH2S]oil = (2.2) x (2.9 %) = 6.4%

Page 22 of 32


4.


Calculate H2S release rate QH2S = (8.31 MMscfd) x (.064) = 0.53 MMscfd H2S

5.

Calculate RERs RER100 ppm = e(QH2S)f RER100 ppm = (1285)(0.53)0.69 = 829 m RER30 ppm = g(QH2S)h RER30 ppm = (2656)(0.53)0.64 = 1,769 m RER½LFL = l(Qgas)m RER½LFL = (47.3)(8.3)0.63 = 180 m Table A4 – RER for Example Oil Well Rupture Exposure Radii

Distance, m

RER100 ppm

829

RER30 ppm

1,769

RER½LFL

180

Method of Using RER Results Saudi Aramco uses the maximum of the 30 ppm RER (100 ppm RER with additional drilling precautions) or the ½ LFL RER to establish the minimum distance between wells and population or major facilities (note that spacing can never be less than the minimums stated in Table 2 of the Standard – see Section 6 for more details). The purpose for this RER method of spacing is to minimize the possibility of exposing people to either potentially lethal or flammable vapor clouds. Table A5 summarizes the effects of hydrogen sulfide exposure to people. Once the RER100 ppm, RER30 ppm, and RER½LFL are known, draw the RERs as circles with the well at the center (see Figure A1). For sour gas wells, the ½ LFL RER will not dominate, but it should still be drawn on the map showing RERs.

Page 23 of 32



Figure A1 – RER Circles Superimposed Over Wellsite Map Table A5 – Effects of Hydrogen Sulfide on People H2S Concentration (ppm) 0.10

Effect on People ERPG-1*: The maximum airborne concentration below which it is believed that nearly all adult males could be exposed for up to 1 hour without experiencing other than mild transient adverse health effects or perceiving a clearly defined objectionable odor.

4

Moderate odor, easily detected.

10

Time Weighted Average (TWA) exposure limitation, beginning of eye irritation. Setting for Warning low level H2S alarm for control rooms and other indoor areas protected by air intake sensors. Saudi Aramco work permit procedures require use of SCBA for work in areas with 10 ppm or greater H 2S.

15

Short Term Exposure Limit (STEL) for 15 minutes.

20

Warning High H2S Level alarm setting at Saudi Aramco plants per SAES-J-505.

30

50 70 – 150

ERPG-2*: The maximum airborne concentration below which it is believed that nearly all adult males could be exposed for up to 1 hour without experiencing or developing irreversible or other serious health effects or symptoms that could impair their abilities to take protective action. Inhalation limit for 60 minutes, threshold limit of possible eye injury. Setting for Warning High-high Level H2S alarm at Saudi Aramco plants per SAES-J-505. Headaches, dizziness, sore throat and increasing stress.

100

ERPG-3*: The maximum airborne concentration below which it is believed that nearly all adult males could be exposed for up to 1 hour without experiencing or developing life-threatening health effects.

150

Loss of sense of smell.

Page 24 of 32

Document Responsibility: Loss Prevention Standards Committee Issue Date: 23 July 2009 Next Planned Update: 31 March 2014 H2S Concentration (ppm) 150 – 300


Effect on People Severe irritation of eyes and lungs. Immediately Dangerous to Life and Health Concentration: The maximum airborne concentration to which a healthy male worker can be exposed for as long as 30 min and still be able to escape without loss of life or irreversible organ system damage. Loss of sense of reasoning and balance, loss of consciousness and possible death in 30 – 60 minutes.

300

500 1,000

Immediate loss of consciousness and death within a few minutes.

* Emergency Response Planning Guideline (ERPG), American Industrial Hygiene Association.

Table A6 – Gas Field Constants for RER Calculations Properties H2S (mole%) Field

Constants

AOF or Qgas (MMSCFD)

100 ppm

30 ppm

½ LFL

min

max

min

max

e

f

g

h

l

m

Abqaiq Cap Gas

1.0

5.0

50

150

268

0.73

729

0.73

14.8

0.49

Berri

20

20

50

120

789

0.63

1894

0.64

11.7

0.49

North Ghawar (Ain Dar and Shedgum)

0.72

6.0

50

150

273

0.75

689

0.81

14.0

0.48

South Ghawar (Haradh)

0.50

2.0

50

125

242

0.71

654

0.67

14.6

0.49

South Ghawar (Hawiyah)

0.5

4.5

50

150

245

0.79

700

0.77

11.7

0.54

Qatif

7.23

11.2

50

120

376

0.74

1032

0.72

11.1

0.50

Uthmaniyah

2.28

9.27

50

175

295

0.80

855

0.76

16.1

0.46

Equations for Oil and Gas Wells: RER100 ppm = e(QH2S)f RER30 ppm = g(QH2S)h RER½LFL = l(QAOF)m Equations for Oil Wells Only: [xH2S]gas

H2S]oil b

Note:

All RER distances are in meters. QH2S = release rate of H2S, MMSCFD. Qgas = release rate of gas, MMSCFD

Page 25 of 32



Table A7 – Oil Fields Constants for RER Calculations Properties

Constants

H2S (mole%) in Oil

Qoil (MBD)

min

max

min

max

a

b

e

f

g

h

l

m

Abqaiq

0.93

3.19

2.9

85

11.7

-0.29

815

0.58

1,895

0.58

49.4

0.59

Abu Hadriyah

0.21

2.23

1.9

88

2.2

0

1,024

0.57

2,249

0.55

63.8

0.57

Abu Jiffan

2.58

3.61

10

50

2.5

0

1,182

0.56

2,470

0.55

51.2

0.58

Ain Dar

0.25

2.7

6.9

37

1.7

0

897

0.76

2,251

0.84

45.5

0.42

Berri

1.06

8.92

15

143

33.5

-0.48

1,152

0.53

2,474

0.52

59.1

0.59

Dammam

1.04

2.18

8

52

2.8

0

432

0.48

725

0.49

24.1

0.47

Fadhili

4.13

11.1

5

31

1.5

0

878

0.77

1,949

0.71

51.7

0.54

Fazran

0.66

2.15

4.5

27

1.8

0

273

0.25

911

0.37

38.4

0.29

Haradh

0.02

0.79

5

32

2

0

2,741

0.77

3,825

0.37

50.4

0.52

Harmaliyah

1.69

5.3

6

32

1.6

0

856

0.61

1,980

0.59

45.3

0.44

Hawiyah

0.21

1.05

5

30

2

0

1,173

0.73

2,617

0.71

48.8

0.56

Khurais

0.58

2.94

9

36

2.2

0

1,285

0.69

2,656

0.64

47.3

0.63

Khursaniyah

1.96

4.77

7

43

2

0

1,079

0.59

2,346

0.58

47.9

0.53

Mazalij

1.9

5.47

6.3

37.8

2.2

0

1,232

0.71

2,565

0.67

50.6

0.65

Qatif

3.72

11.95

4

90

1.9

0

1,708

0.34

3,488

0.32

64.6

0.55

Shedgum

0.75

1.57

9

46

1.8

0

630

0.51

1,511

0.49

50.0

0.38

Uthmaniyah

0.23

1.55

9

29

1.8

0

1,438

0.83

3,279

0.83

36.5

0.70

Field

Flash

100 ppm

30 ppm

½ LFL

Page 26 of 32



Table A8 – Oil Field Data from Exploration and Producing Components (mole %) Well Name Abqaiq Abqaiq Abqaiq Abu Hadriyah Abu Hadriyah Abu Hadriyah Abu Jiffan Abu Jiffan Abu Jiffan Ain Dar Ain Dar Ain Dar Berri Berri Berri Dammam Dammam Dammam Fadhili Fadhili Fadhili Fazran Fazran Fazran Haradh Haradh Haradh Harmaliyah Harmaliyah Harmaliyah Hawiyah Hawiyah Hawiyah Khurais Khurais Khurais

Reservoir Range Arab-D Min. Arab-D Wt. Avg. Arab-C Max. Arab-A&B Min. Wt. Avg. Arab-C Max. Arab-D Min. Arab-D Wt. Avg. Arab-D Max. L. Fadhili Min. Arab-D Wt. Avg. Arab-D Max. Arab-B Min. Wt. Avg. Hanifa Max. Arab-D Min. Wt. Avg. Arab-D Max. Arab-D Min. Wt. Avg. Arab-D Max. L. Fadhili Min. Wt. Avg. L. Fadhili Max. Arab-D Min. Arab-D Wt. Avg. Arab-D Max. Arab-D Min. Arab-D Wt. Avg. Arab-D Max. Arab-D Min. Arab-D Wt. Avg. Arab-D Max. Arab-D Min. Arab-D Wt. Avg. Arab-D Max.

N2 0.3 0.1 0.6 0.2 0.4 0.3 0.2 0.2 0.3 0.1 0.1 0.2 0.1 0.1 0.1 0.2 1.4 1.5 0.0 0.1 0.1 0.3 0.2 0.1 0.3 0.2 0.2 0.1 0.1 0.1 2.1 1.0 0.4 0.3 0.5 0.8

CO2 4.9 4.6 5.1 1.0 1.2 1.3 1.7 1.9 2.1 3.9 5.9 6.3 1.2 1.5 6.6 2.8 4.8 5.5 2.9 2.3 9.8 3.8 4.5 2.1 1.4 3.8 4.8 4.8 5.1 5.3 4.8 4.8 4.1 1.4 1.9 4.5

H2S 0.9 1.8 3.2 0.2 1.4 2.2 2.6 3.1 3.6 0.3 1.7 2.7 1.1 2.1 8.9 1.0 1.7 2.2 4.1 5.5 11.1 0.6 1.5 2.2 0.0 0.4 0.8 1.7 4.1 5.3 0.2 0.8 1.1 0.0 0.6 2.9

C1 27.4 29.6 6.1 3.5 14.5 17.2 9.6 9.2 8.9 34.3 25.1 24.0 4.3 4.6 24.9 21.9 22.6 22.4 33.4 31.8 25.8 21.0 21.5 34.0 19.5 22.2 27.4 25.5 27.7 24.9 29.4 22.8 15.9 13.8 13.7 12.8

C2 C3 10.7 4.4 10.3 6.6 4.7 7.4 2.9 6.7 8.1 8.1 8.4 7.8 9.6 9.3 8.9 8.8 8.3 8.3 13.8 8.5 10.4 7.7 10.2 7.0 6.7 9.7 6.4 9.2 10.2 7.2 2.0 1.5 2.1 1.6 1.6 1.1 11.1 6.8 12.8 8.3 9.3 7.1 11.3 9.3 11.3 8.5 11.7 6.8 10.5 10.0 9.5 8.5 10.7 8.2 11.8 8.3 11.4 7.8 10.6 7.6 6.9 5.8 9.1 7.9 8.3 7.6 9.2 8.9 9.3 9.2 6.1 8.9

i-C4 1.6 0.6 1.2 1.4 1.1 1.1 1.2 1.2 1.2 1.0 1.0 0.9 1.7 1.5 0.9 0.3 0.4 0.2 0.5 0.9 0.9 1.2 1.0 0.8 1.2 1.1 1.0 0.9 0.9 0.9 0.8 1.0 1.0 1.3 1.2 1.4

n-C4 3.7 4.3 5.1 5.4 4.9 4.6 4.9 4.7 4.6 4.0 3.8 3.5 6.1 5.7 3.5 1.3 1.4 0.8 3.9 3.8 3.5 5.2 4.1 3.7 5.1 4.5 3.9 3.8 3.7 3.8 3.5 4.1 4.3 4.8 4.9 4.9

i-C5 2.6 1.0 2.1 2.2 1.8 1.6 1.7 1.7 1.8 1.1 1.2 1.2 2.3 2.2 1.2 0.4 0.8 0.4 0.8 1.0 1.2 1.8 1.3 1.3 1.6 1.6 1.3 1.2 1.3 1.2 1.2 1.4 1.7 1.7 1.7 1.9

n-C5 1.8 3.0 3.5 3.9 3.2 3.1 3.0 3.1 3.1 2.1 2.2 2.1 3.6 3.6 2.1 0.9 1.3 0.9 2.5 2.0 2.0 3.4 2.5 2.2 2.8 2.8 2.3 2.3 2.4 2.3 2.2 2.6 3.4 3.1 3.0 3.0

C6 4.2 3.1 4.6 4.3 3.4 2.8 3.9 4.4 5.0 1.6 3.0 3.2 3.5 3.7 2.8 4.7 3.6 3.4 3.2 1.4 1.8 3.7 4.0 2.1 2.8 3.9 2.0 3.1 3.0 3.2 3.0 3.5 6.0 4.0 3.8 3.9

C7+ GOR 37.4 860 35.1 860 56.6 135 68.3 57 52.0 260 49.6 57 52.4 253 52.7 253 53.0 253 29.3 730 37.8 550 38.7 550 59.8 139 59.3 145 31.6 659 63.1 353 58.4 360 60.0 353 30.7 955 30.3 962 27.4 955 38.5 1100 39.5 565 33.0 1100 44.7 470 41.4 470 37.6 470 36.6 772 32.7 772 34.8 772 40.2 485 40.9 485 46.1 485 51.4 277 50.1 277 48.7 277

Page 27 of 32



Table A8 – Oil Field Data from Exploration and Producing (Cont'd) Components (mole %) Well Name Reservoir Range Khursaniyah Arab-D Min. Khursaniyah Wt. Avg. Khursaniyah Arab-B Max. Mazalij Arab-D Min. Mazalij Arab-D Wt. Avg. Mazalij Arab-D Max. Qatif Fadhili Min. Qatif Wt. Avg. Qatif Arab-D Max. Shedgum Arab-D Min. Shedgum Wt. Avg. Shedgum Arab-D Max. Uthmaniyah Arab-D Min. Uthmaniyah Arab-D Wt. Avg. Uthmaniyah Arab-D Max.

N2 0.1 0.2 0.1 0.1 0.3 0.3 0.2 0.9 0.3 0.3 0.2 0.2 0.1 0.2 0.1

CO2 2.5 3.1 4.7 3.4 2.6 1.6 3.5 6.6 6.7 5.4 5.3 5.4 3.8 4.5 5.2

H2S 2.0 2.4 4.8 1.9 3.2 5.5 3.7 7.9 11.9 0.8 1.1 1.6 0.2 0.8 1.6

C1 C2 19.4 9.8 21.5 9.8 15.8 7.2 28.7 5.8 19.2 8.0 5.3 8.7 38.2 12.3 14.4 7.0 20.8 9.0 25.0 10.0 24.4 9.9 24.3 9.8 26.1 9.7 24.6 10.0 23.9 9.2

C3 8.6 8.5 6.9 6.4 7.5 8.3 7.4 7.2 7.1 7.7 7.8 7.6 7.7 8.1 7.7

i-C4 1.1 1.1 1.0 1.0 1.1 1.2 0.9 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.1

n-C4 4.5 4.2 3.8 3.7 4.3 5.0 3.6 4.1 3.6 3.9 4.0 3.9 4.2 4.1 4.4

i-C5 1.7 1.5 1.5 1.4 1.7 2.1 1.2 1.6 1.4 1.3 1.4 1.3 1.6 1.4 1.5

n-C5 3.1 2.6 2.7 2.2 2.7 3.4 2.2 2.7 2.2 2.4 2.4 2.4 3.0 2.5 2.7

C6 3.2 2.8 2.9 3.2 4.0 5.6 3.0 3.8 3.6 3.3 3.2 3.3 3.4 3.3 4.1

C7+ GOR 44.0 350 42.3 380 48.7 350 42.1 398 45.4 398 53.0 398 23.8 1266 43.0 330 32.5 870 38.9 540 36.2 540 39.3 540 39.4 515 39.3 515 38.7 515

Page 28 of 32



Table A9 – Gas Field Data from Exploration and Producing Mol Wt. Range

Well Name Reservoir

Component (mole %) N2

CO2

H2S

C1

C2

C3

i-C4

nC4

iC5

nC5

C6

C7

C8

C9

C10+

North Ghawar (Ain Dar and Shedgum) ANDR-277

Khuff-B

23.1

Min.

14.7

3.8

0.7

70.4

4.9

1.8

0.4

0.6

0.2

0.2

0.2

0.3

0.4

0.3

1.1

SDGM-226

Khuff-C

23.7

Med. 11.8

3.7

3.6

69.4

5.1

2.0

0.5

0.8

0.3

0.3

0.4

0.4

0.4

0.3

1.1

SDGM-212

Khuff-C

24.6

Max. 11.5

3.9

6.0

66.6

5.0

2.1

0.5

0.8

0.4

0.3

0.5

0.6

0.6

0.4

1.0

Central Ghawar Area (Uthmaniyah) UTMN-622

Khuff-B

25.5

Min.

10.5

1.7

2.3

68.4

6.7

3.0

0.6

1.2

0.5

0.5

0.7

0.8

0.8

0.6

1.8

UTMN-616

Khuff-C

24.9

Med. 11.5

3.3

5.2

66.0

5.8

2.5

0.5

1.0

0.4

0.4

0.6

0.6

0.6

0.5

1.3

UTMN-2000 Khuff-C

26.4

Max. 10.2

3.1

9.3

62.0

6.2

2.7

0.5

1.0

0.3

0.3

0.6

0.9

0.8

0.6

1.5

South Ghawar Area (Hawiyah) Avg.

9.6

2.2

2.5

68

6.7

2.9

0.5

1.1

0.4

0.4

0.7

1.0

1.0

0.7

2.2

26.6

Min.

9.8

2.3

0.5

69.4

6.8

3.0

0.5

1.1

0.4

0.4

0.7

1.0

1.0

0.7

2.2

27.1

Med.

9.6

2.2

3.0

67.7

6.6

2.9

0.5

1.0

0.4

0.4

0.7

1.0

1.0

0.7

2.2

27.2

Max.

9.4

2.2

4.5

66.6

6.5

2.8

0.5

1.1

0.4

0.4

0.7

1.0

1.0

0.7

2.1

Avg.

9.0

1.5

0.6

71.1

7.4

3.3

0.6

1.4

0.5

0.5

0.6

0.8

0.8

0.6

1.2

Khuff-C

27

Khuff-C Khuff-C Khuff-C

South Ghawar Area (Haradh) Khuff-C

25

Khuff-C

25

Min.

9.0

1.5

0.5

71.2

7.4

3.3

0.6

1.4

0.5

0.5

0.6

0.8

0.8

0.6

1.2

Khuff-C

25

Med.

9

1.5

1.0

70.9

7.4

3.3

0.6

1.4

0.5

0.5

0.6

0.8

0.8

0.6

1.2

Khuff-C

25

Max.

9

1.5

2.0

70.1

7.3

3.3

0.6

1.4

0.5

0.5

0.6

0.8

0.8

0.6

1.2

Qatif QTIF-51

Khuff-A

20.9

Min.

6.5

9.1

7.2

75.8

1.2

0.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

QTIF-152

Khuff-B

24.7

Max.

42.2

2.0

11.2

42.2

0.9

0.2

0.0

0.2

0.0

0.0

0.1

0.8

0.0

0.0

0.0

Abqaiq Abq Cap Gas Berri

Abqaiq

0.7

8.6

2.3

64.5 14.1

6.1

2.2

0.9

0.3

0.1

0.1

0.1

0.0

0.0

0.0

Berri Khuff

Berri

10.0

8.2

19.8

61.4

0.2

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

23.2

0.3

The table below shows examples of the maximum RERs for some fields. The RER values shown are based on the calculation information above and the maximum open flow and highest sour gas concentration typically expected the fields listed. The values below are for example only. RER100ppm (meters)

RER30ppm (meters)

RER½LFL (meters)

Abqaiq Gas Cap

1170

3170

170

North Ghawar (Ain Dar and Shedgum)

1420

4090

160

South Ghawar (Haradh)

460

1210

160

South Ghawar (Hawiyah)

1110

3050

180

Uthmaniyah

2740

7110

170

Gas Fields

Page 29 of 32



RER100ppm (meters)

RER30ppm (meters)

RER½LFL (meters)

Abqaiq

1780

4140

620

Abu Jiffan

1270

2660

220

Ain Dar

850

2130

160

Dammam

460

770

100

Fazran

280

960

100

Haradh

910

2250

210

Harmaliyah

1340

3060

190

Hawiyah

490

1130

220

Khurais

950

2010

200

Khursaniyah

1340

2890

200

Mazalij

1880

3820

300

Shedgum

530

1270

170

Uthmaniyah

700

1590

240

Oil Fields

Page 30 of 32



Gas Field RER Work Sheet Information

Value

Well Name Field Absolute Open Flow, Qgas MMSCFD Mole % of H2S in Gas, [xH2S]gas DATA from Table A6 Minimum AOF, MMSCFD, per Table A6 Maximum AOF, MMSCFD, per Table A6 Is AOF for well greater than minimum and less than maximum AOF for field? Minimum mole percent (%) of H2S per Table A6 Maximum mole percent (%) of H2S per Table A6 Is H2S mole % for well greater than minimum and less than maximum flow rate for field?

( ) Yes (continue) ( ) No (stop: Contact LPD/TSU)


Constants from Table A6 e f g h l m Calculate H2S Release Rate QH2S = (QAOF)(xH2S) [MMscfd of H2S] Calculate RERs f RER100 ppm = e(QH2S) : h RER30 ppm = g(QH2S) m RER½ LFL = l(QAOF) Results RER100 ppm RER30 ppm RER½ LFL

Page 31 of 32



Oil Field RER Work Sheet Information

Value

Well Name Field Maximum Flow Rate, Qoil Mbpd GOR, scf/stb Mole % of H2S in Oil, [xH2S]oil DATA from Table A7 Minimum Flow Rate, Mbpd, per Table A7 or Qoil Maximum Flow Rate, Mbpd, per Table A7 or Qoil Is flow rate for well greater than minimum and less than maximum flow rate for field? Minimum mole percent (%) of H2S per Table A7


Maximum mole percent (%) of H2S per Table A7 Is H2S mole % for well greater than minimum and less than maximum flow rate for field?


Constants from Table A7 a

b

e

f

g

h

l

m

Calculate flashed gas release rate Qgas = (Qoil)(GOR)/1,000 [MMscfd] Calculate the H2S concentration in flashed gas b

[xH2S]gas

H2S]oil

QH2S = (([xH2S]gas)/100)Qgas [MMscfd of H2S] Calculate RERs f

RER100 ppm = e(QH2S) h RER30 ppm = g(QH2S) m RER½ LFL = l(Qgas) Results RER100 ppm RER30 ppm RER½ LFL

Page 32 of 32

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

1852.01

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

10/29/2011 APPROVAL

AAR

Approved

REPLACES

01/31/2010 PAGE NUMBER

1

OF

2

CONTENT: This General Instruction contains policy for equipping a rig with a Flare Gun and standard Communication Equipment. 1. OBJECTIVE 2. BACKGROUND 3. FLARE GUN 4. COMMUNICATION EQUIPMENT

1.0

OBJECTIVE ** The purpose of this policy is to ensure that every rig is fully equipped with a Flare Gun and Communication Equipment in case of an uncontrolled surface well flow (blowout) or other emergency. All rigs must have functional and dedicated flare gun on location, prior to commencing and during Drilling and Workover Operations.

2.0

3.0

BACKGROUND 2.1

During Drilling and Workover operations, with a rig on the well, an uncontrolled surface flow (blowout) may occur, requiring immediate ignition of the well effluent to protect human life and company assets. In such a case, a Flare Gun is fired to ignite the effluent before spreading.

2.2

During the blowout emergency, it becomes imperative to have reliable means of communication at the rig site and with headquarters, especially when all power is turned off at the well site to avoid uncontrolled ignition. The use of mobile radios and portable communication devices (such as Walkie-Talkies) become essential in effective transmittal of instructions and expedient control of the well.

FLARE GUN * Drilling & Workover will have a Flare Gun on each rig site, as well as a minimum of 20 cartridges with long shelf life. The Flare Gun and cartridges will be locked up in a clearly marked wooden box in the Foreman's office, and the location of the key will be known only to the Foreman and the Contract rig Supervisor. The Foreman and Contract rig Supervisor should be proficient in operation of the Flare Gun. Note: Foremen should ensure that the cartridge is compatible with the length of the gun barrel.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

4.0

1852.001

10/29/2011 APPROVAL

AAR

Approved

REPLACES

01/31/2010 PAGE NUMBER

2

OF

2

COMMUNICATION EQUIPMENT Drilling & Workover, Area Information and Communications Operations Departments will work together to forecast, acquire and install the following communication equipment: 4.1 One (1) Trunk mobile radio (for on-shore rigs only) in rig Foreman’s vehicle to provide the capability to communicate with management, etc. in case of an emergency. The radio will only be used when at a safe distance from the well site in case of an un-ignited hydrocarbon accumulation since the vehicle and radios are both source of ignition. 4.2 One (1) Trunk desktop radio (all rigs) in every rig Foreman’s office to enable communication with management, etc. if incase V-Sat communication is non functional or an emergency situation exists at the rig. 4.3 One (1) Trunk portable radio (hand held) for all rigs. 4.4 Six (6) VHF portable radios. The radios are needed on every rig site during an emergency or critical operation. The portable radios will be locked up in a clearly marked wooden box in the Foreman’s office, and the location of the key will be known only to the Foreman and the Contractor Rig Supervisor. The foreman is responsible for the proper operation and charging of the radios. The radios must be rated for use in Class I, Div. I electrically classified areas (i. e. Explosion proof). 4.5 One (1) Base Station VHF System (Aviation Radio) for Offshore Rigs only to communicate with helicopter. 4.6 One (1) V-Sat unit at every rig to enable use of telephone / data (internet) communication at rig during normal non-emergency operations. 4.7 One (1) satellite phone at every rig as back-up communication to provide the capability to communicate with management, etc. if incase V-Sat communication goes down.

Prepared by : __________________ Iqbal Ahmed Sr. Consultant D&W/O Approved by:

__________________ _______ ABDULHAMEED A. AL-RUSHAID

General Manager (A), Drilling.

* CHANGE

** ADDITION

____ SULAIMAN H. ARJAH

Manager, Area Info. Tech. Dept.

NEW INSTRUCTION

___________________________ ABDULRAHMAN E.ALMUAGLE

Manager, Comm. Oprs. Dept.

COMPLETE REVISION

G. I. Number

SAUDI ARABIAN OIL COMPANY (Saudi Aramco)

APPROVED

1853.001

GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT

ISOLATION BARRIERS FOR WELLS DURING DRILLING & WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

02/05/2014 APPROVAL DMD

REPLACES

05/30/2012 PAGE NO.

1 OF 7

CONTENT: This document contains Instructions for providing adequate isolation barriers (or shut-offs) when removing surface control equipment while drilling or working over wells. These instructions are also applicable for well repair work, performed by the Drilling & Workover organization with and without a rig on location. 1. OBJECTIVE 2. BACKGROUND 3. MINIMUM REQUIREMENT 4. TYPES OF ISOLATION BARRIERS 5. RELIABILITY OF ISOLATION BARRIER 6. WAIVER

1.0

OBJECTIVE: The purpose of this GI is to ensure safe operations during drilling and well repair work by strict compliance to the guidelines. Deviation from these guidelines will not be permitted unless a waiver is obtained from the Vice President, Drilling and Workover or designated representatives.

2.0

BACKGROUND: When drilling or working over wells, with or without a rig, situations arise where surface equipment such as Blow Out Preventers (BOPs), wellheads, master valves and trees have to be removed for various reasons. In these situations, surface well control is temporarily removed and is substituted with down-hole isolation barriers so that the reservoir pressure is isolated and work can continue around the wellhead safely. More than one isolation barrier or shut-off is normally required in certain wells in case of unexpected failure of the primary barrier. Adequate back-up barriers reduce the chances of uncontrolled surface flow (blowout) and costly repair work.

3.0 MINIMUM REQUIREMENT: The following guidelines will apply at all times unless a waiver has been obtained from Management (as described in paragraph 6.2). The mandatory number of barriers or shut-offs in each case is the minimum; any additional barriers are optional, dictated by the well condition and down-hole completion equipment. CHANGE

ADDITION *

NEW INSTRUCTION

COMPLETE REVISION

G. I. Number


APPROVED

1853.001


ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT


02/05/2014 APPROVAL DMD

REPLACES

05/30/2012 PAGE NO.

2 OF 7

3.1) Oil Wells (GOR less than 850scf/bbl) 2 shut-offs, at least one of which is mechanical. (See notes below)

3.2) Oil Wells (GOR more than 850 scf/bbl) 3 shut-offs, at least two of which are mechanical. (See notes below) 3.3) Oil Wells (Dead Wells – 0 psi when the ESP is not running) 1(one) shut-off for tubing - While continuously pumping kill fluid down the Tubing/Casing Annulus. Notes: a)

For completing wells with tubing and down-hole packer, the shut-off guideline is applicable to tubing only. A minimum of 2 shut-offs is required for the Tubing/Casing Annulus (tubing hanger and packer seals).

b)

For de-completing well with down-hole packer, the shut-off guideline is applicable to the Tubing. The shut-offs for the tubing/casing annulus (TCA) are: 

Packer.



Tubing Hanger.



Positive pressure test of Casing.

If any one of the shut-offs is deemed to be ineffective or questionable, then additionally a Cement Plug or a Thru-Tubing Drillable Bridge-Plug (TTBP) must be placed above the producing / injecting zone, capped with cement. The Top of Cement (TOC) must be tagged.

CHANGE

c)

For de-completing wells with up-hole packer completions it is mandatory that full circulation is established with kill fluid. If full circulation is not achieved a Cement Plug or a TTBP capped with cement is required. The TOC must be tagged.

d)

For Wells equipped with ESP (without ‘Y’- assembly) and positive Wellhead Pressures, the shut-off guideline is applicable to the Tubing. The shut-offs for the tubing/casing annulus (TCA) are: 

Tubing Hanger



TCA standing full with kill-weights fluids or continuously pumping kill-weight fluids down the TCA.

ADDITION *

NEW INSTRUCTION

COMPLETE REVISION

G. I. Number



ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT


e)

3.3

APPROVED

1853.001 02/05/2014 APPROVAL DMD

REPLACES

05/30/2012 PAGE NO.

3 OF 7

When changing the tree above the master valve on wells that have a pressure tested master valve, only one barrier in addition to the master valve is required. This additional barrier should be mechanical. Water Injection Wells  If positive WH pressure, 2 shut-offs are required, one of which is mechanical.  If no WH pressure, 1 shut-off is required.

Notes: a) Water Injection Wells encountering Loss Circulation (LC) after pumping kill fluid. It is acceptable to Nipple-Up (NU) or Nipple-Down (DN) the BOPE on top of the injection tree by closing the Master Valve and continuously pumping kill fluid down the well-bore. No additional shut-offs are required as long as the tree was never removed and has been pressure tested prior to NU/ND the BOPE. b) Injection Wells with guide string extended into the Open Hole. It is acceptable to NU/ND the BOPE with tubing full of kill fluid. MV closed & a mechanical plug (tested) in place, tubing hanger seals (tested) while continuously pumping kill fluid down the Tubing/Casing Annulus. 3.4

Gas Wells 3 shut-offs, at least two of which are mechanical.

Notes:

CHANGE

a.

For completion, the 3 shut-off guideline is applicable to the tubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus (tubing hanger and packer seals).

b.

For de-completion positive pressure test of Tbg. & TCA with kill fluid in both sides is mandatory.

c.

When changing the tree above the master valve on wells that have a pressure tested master valve, barriers in addition to the master valve (barrier) are required.

ADDITION *

NEW INSTRUCTION

COMPLETE REVISION

G. I. Number



ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT


3.5

APPROVED

1853.001 02/05/2014 APPROVAL DMD

REPLACES

05/30/2012 PAGE NO.

4 OF 7

Water Supply Wells (with or without submersible pump) - If well flows to surface, 1 mechanical shut-off is required with kill weight fluid in the well-bore - If well does not flow to surface, no shut-off is required.

4.0

TYPES OF ISOLATION BARRIERS: 4.1

A number of acceptable isolation barriers or shut-off alternatives are available and can be used under different operating conditions. These barriers can be separated into two main groups: Mechanical and Non-Mechanical.

4.2

The following are examples of Mechanical and Non-Mechanical isolation barriers. The type of barrier to be utilize will depend on the well condition and down-hole completion equipment. These barriers include, but are not limited to: Mechanical: - Drillable or Retrievable Bridge Plug - Retrievable Tubing Plug - Back Pressure Valve - Valve Back-Seat - Surface Valve - Un-perforated Casing Non-Mechanical: - Kill Fluid - Cement GLASS AND CERAMIC DISKS: Both types can be considered a barrier when completing a well under the following conditions: a. The disks must be rated to hold the formation pressure from below. The working pressure must be a minimum of 20% higher than the anticipated formation pressure. b. They are only used during BOP nipple down and tree nipple up operations. c. A negative test must be successfully performed on the disks. d. After the negative test, the integrity of the disks may not be compromised by any subsequent operation (e.g.: wire-line, CT work, dropped objects, etc.) e. They must be used in conjunction with a BPV.

CHANGE

ADDITION *

NEW INSTRUCTION

COMPLETE REVISION

G. I. Number



ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT


5.0

APPROVED

1853.001 02/05/2014 APPROVAL DMD

REPLACES

05/30/2012 PAGE NO.

5 OF 7

RELIABILITY OF ISOLATION BARRIERS: 5.1

Equipment Testing

5.1.1 Vendor Testing: Prior to delivery of a new mechanical pressure isolation device, the vendor must conduct the required and appropriate hydrostatic pressure tests per Saudi Aramco Materials System Specification (SAMSS) to insure that the device meets design specifications. 5.1.2 Field-Testing: Whenever a mechanical isolation barrier is installed in a well, every effort should be made to field test and insure the barrier is holding. Since plugs are designed to hold pressure from above, below or from both directions, the field test should be designed according to the plug functionality.

5.1.3 While drilling or working over a well, if BOPE repairs are required, the mechanical isolation barriers must be installed and positive tested. 5.2

Kill Fluid 5.2.1 A kill fluid can be used as one of the isolation barriers as mentioned in section 4.2 above. In order for the kill fluid to be effective as an isolation barrier, two conditions must be met: a) The hydrostatic pressure of the kill fluid column must exceed the reservoir pressure. b) The wellbore kill fluid must remain static at surface for a period of time (as per item 5.2.2 below) to insure the presence of a competent barrier.

5.2.2

The following are the minimum mandatory observation times for a kill fluid to be declared static: Oil Well (GOR less than 850 scf/bbl): *Well (GOR more than 850 scf/bbl): *Gas Well Water Injector Water Supply Well

1 hour Oil 2 hour 3 hours 1 hour 30 minutes

*The depth and permeability of the producing formation should be taken into consideration. Deeper or less permeable producing formations may need longer observation period..

CHANGE

ADDITION *

NEW INSTRUCTION

COMPLETE REVISION

Appendix I

GI 1853.001 Page 7 of 7

WAIVER REQUEST FOR ISOLATION BARRIER Date Requested Well Name & Number

Plant#

Waiver Request#

Facility Connected to

Include number, Paragraph, and Issue date of this affected GI Waiver request

After-the-fact

WAIVER ORIGINATOR

Justification (include discussion of impact assessment)

Y Impact Assessment

Y

N

Y

N

Financial Impact

Safety Impact

Discuss under justification Alternative to waiving requirements

Originating organization

(Originator’s name)

(Signature)

Date

(Signature)

Date

Phone: Originator’s Supervisor

REMARKS

APPROVAL

N

Well Control Committee Chairperson

Signature

Date

Signature

Date

Name: Vice President or Designated Representative Name:

SAUDI ARAMCO DRILLING & WORKOVER ROOM 221A, BLDG 3193 DHAHRAN 31311, SAUDI ARABIA TEL. 862-8000, FAX. 862-8011 October 18, 1999

D&WO/GM-160

Clarification of GI 1853.001

Managers Drilling & Workover The new GI 1853.001 entitled “Isolation Barriers for Wells during Drilling & Workover Operations (with and without Rig)” was approved in November 1998 and distributed for implementation. The interpretation of the GI with respect to changing rams or installing casing rams has been questioned. The following clarifies the shut-off requirements for these operations as per the subject GI. Section 3.0, Paragraphs 3.2 (Oil Wells with GOR more than 850 scf/bbl) and 3.4 (Gas Wells) Three mandatory shut-offs are required; two of which should be mechanical. Clarification: i) For BOP stack removal or tree removal, the mandatory shut-off requirements are applicable. ii)

For changing rams or installing casing rams, the mandatory shut-offs do not apply. Two barriers are adequate; one of which should be mechanical. Shutting the blind rams with kill fluid in the hole will provide proper isolation since the 1) BOP preventers below the open ram cavity are effective and reliable (recently pressure tested), 2) time involved in changing rams is much less than removing the entire BOP stack or tree. When changing the lowermost set of rams, a down-hole mechanical shut-off (either cased hole or packer) with kill fluid is required.

Signed 10/18/99 __________________________________ F. A. Al-Moosa, General Manager Drilling & Workover dgn/ cc: Drilling Superintendents, Deep Drilling and Onshore Workover Dept. Drilling Superintendents, Dev. Drilling and Offshore Workover Dept. General Supervisors, Drilling and W/O Engrg. Dept. Originator Letterbook

Drilling & Work Over Manual-2014

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