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NORSOK STANDARD

SYSTEM REQUIREMENTS WELL INTERVENTION EQUIPMENT

D-002 Rev. 1, October 2000

This NORSOK standard is developed by NTS with broad industry participation. Please note that whilst every effort has been made to ensure the accuracy of this standard, neither OLF nor TBL or any of their members will assume liability for any use thereof. NTS is responsible for the administration and publication of this standard. Norwegian Technology Center Oscarsgt. 20, Postbox 7072 Majorstua N-0306 Oslo, NORWAY Telephone: + 47 22 59 01 00 Fax: + 47 22 59 01 29 Email: [email protected] Website: http://www.nts.no/norsok Copyrights reserved

System requirements well intervention equipment

D-002 Rev. 1, October 2000

CONTENTS

FOREWORD INTRODUCTION 1 SCOPE 2 NORMATIVE REFERENCES 3 TERMS, DEFINITIONS AND ABBREVIATIONS 3.1 Definitions 3.2 Abbreviations 4 GENERAL REQUIREMENTS 4.1 General 4.2 Design principles 4.3 Design principles references and standards 4.4 Verification, testing and marking 4.5 LCC and regularity 4.6 Process and ambient conditions 4.7 Layout and working environment requirements 4.8 Special requirements for skid base structures 4.9 Utility interfaces 4.10 Operational requirement 5 WELL INTERVENTION WELL CONTROL SYSTEM 5.1 Equipment configuration 5.2 Equipment requirements 5.3 Control system 6 SNUBBING EQUIPMENT 6.1 General 6.2 Snubbing equipment requirements 6.3 Data acquisition system 6.4 Power package 6.5 Circulating system 6.6 Well control system 6.7 Workstring and BHA 7 COILED TUBING EQUIPMENT 7.1 General 7.2 Coiled tubing equipment requirements 7.3 Power package 7.4 Coiled tubing workstring (steel coiled tubing) 7.5 Coiled tubing reel 7.6 Control cabin 7.7 Data acquisition system 7.8 Well control system 7.9 BHA 8 WIRELINE EQUIPMENT 8.1 General 8.2 Wireline equipment requirements NORSOK standard 2 2 5 5 7 7 7 8 8 8 8 13 15 15 15 16 16 17 18 18 21 30 35 35 36 39 40 40 40 41 42 42 42 46 46 47 48 49 49 50 51 51 51 Page 1 of 68

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D-002 Rev. 1, October 2000 52 52 53 53 54 54 54 54 54 54 55 55 56 56 58 60 60 60 63 63 65 65 65 66 66 66 67

8.3 8.4 8.5 8.6 8.7 8.8 8.9 8.10 8.11 8.12 8.13 8.14

Control cabin Data acquisition Clamps/sheaves and hay pulleys Power package Pressure test pump Wellhead pump Well control system Logging container (for logging and well tractor) Wireline mast (crane) Transport and storage racks for wireline equipment Slick, braided and electrical line requirements Down hole tools requirements

9 DOCUMENTATION 9.1 General 9.2 Specific well intervention requirements ANNEX A (informative) DATA SHEET SNUBBING EQUIPMENT ANNEX B (informative) ANNEX C (informative) SNUBBING AND COILED TUBING WELL CONTROL SYSTEM RIG UP ANNEX D (informative) WIRELINE WELL CONTROL SYSTEM RIG UP BIBLIOGRAPHY

SAFETY HEAD REQUIREMENTS, COILED TUBING AND SNUBBING OPERATIONS 63

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FOREWORD

NORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative to add value, reduce cost and lead time and eliminate unnecessary activities in offshore field developments and operations. The NORSOK standards are developed by the Norwegian petroleum industry as a part of the NORSOK initiative and supported by OLF (The Norwegian Oil Industry Association) and TBL (Federation of Norwegian Manufacturing Industries). NORSOK standards are administered and issued by NTS (Norwegian Technology Center). The purpose of NORSOK standards is to contribute to meet the NORSOK goals, e.g. to develop standards that ensure adequate safety, value adding and cost effectiveness and thus are used in existing and future petroleum industry developments. The NORSOK standards make extensive references to international standards. Where relevant, the contents of a NORSOK standard will be used to provide input to the international standardisation process. Subject to implementation into international standards, the NORSOK standard will be withdrawn. Annexes A, B, C and D are for information only.

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INTRODUCTION

The main objective of this NORSOK standard is to contribute to optimise the design of well service and intervention facilities, their systems and equipment with respect to utilisation, operational efficiency, life cycle cost and to stipulate acceptable safety levels. NORSOK standard D-002 is an overall improvement and expansions of the former standards for coiled tubing, snubbing and wire line equipment, and replace the following NORSOK standards: · · · D-SR-005 D-SR-006 D-SR-008 Coiled tubing equipment, revision 1 ­ January 1996 Snubbing equipment, revision 1 ­ January 1996 Wireline equipment, revision 1 ­ October 1996

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1

SCOPE

This standard describes the design, installation and commissioning principles and requirements for the well intervention equipment and their systems and equipment.

2

NORMATIVE REFERENCES

The following standards include provisions which, through reference in this text, constitute provisions of this NORSOK standard. Latest issue of the references shall be used unless otherwise agreed. Other recognized standards may be used provided it can be shown that they meet or exceed the requirements of the standards referenced below. NPD Regulations NORSOK D-001, Drilling facilities. NORSOK E-001 Electrical systems, NORSOK E-002 Adjustable speed motor drives. NORSOK H-001 HVAC Heating, ventilation and air conditioning NORSOK N-001, Structural design. NORSOK N-003, Actions and action effects. NORSOK S-001, Technical Safety. NORSOK S-002, Working Environment. NORSOK S-003, Environmental Care. NORSOK Z-010 Installation of Electrical, Instrument & Telecommunication NORSOK Z-015, Temporary Equipment. ISO 10423 ISO 10424 ISO 13533 ISO 13535 ISO 13626 ISO 14693 API Spec 4F API Spec 5CT API Spec 6A API Spec 7 API Spec 7K Petroleum and Natural Gas Industries ­ Drilling and Production Equipment ­ Specification for Valves, Wellhead and Christmas Tree Equipment Petroleum and Natural Gas Industries ­ Drilling and production equipment ­ Rotary drilling equipment Petroleum and Natural Gas Industries ­ Drilling and production equipment ­ Specification for drill through equipment Petroleum and Natural Gas Industries ­ Drilling and production equipment ­ Hoisting equipment Petroleum and Natural Gas Industries ­ Drilling and production equipment ­ Drilling and well servicing structures ­ Specification Petroleum and Natural Gas Industries ­ Drilling and production equipment ­ Drilling equipment Drilling and well servicing structures Specification for Casing and Tubing (U.S. Customary Units) Specification for Wellhead and Christmas Tree Equipment Specification for Rotary Drill Stem Elements (replace with ISO 10424 when issued) Specification for Drilling Equipment

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API Spec 8C API Spec 9A API Spec 16A API Spec 16C API Spec 16D

Specification for Drilling and Production Hoisting Equipment (PSL 1 and PSL 2), (replace with ISO 13535 when issued) Specification for Wire Rope Specification for Drill Through Equipment, (replace with ISO 13533 when issued) Choke and kill system Specification for Control Systems for Drilling Well Control Equipment.

BS 308: Parts 1, 2 & 3 Recommendations for geometrical tolerancing. BS 449 Specification for the use of structural steel in building. Metric units. BS 4656: Part 1 Accuracy of machine tools and methods of test. Specification for lathes, general purpose type BS 4656: Part 2 Accuracy of machine tools and methods of test. Specification for copying lathes and copying attachments BS 4656: Part 3 Specification for the accuracy of machine tools and methods of tests. Milling machines, knee and column type, horizontal or vertical spindle plain BS 4656: Part 4 Specification for the accuracy of machine tools and methods of test. Milling machines, bed type, horizontal or vertical spindle BS-7072 Code of practice for inspection and repair of offshore containers NACE-MR-0175, NACE-TM-0177 ASME VIII NS 3472 NS 5820, DNV DNV Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment. Labory Testing of Metals Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S Environment. Item no 21213 Div. 1 and Div. 2, Pressure vessel code Steel structures ­ Design rules Suppliers documentation of equipment. Offshore standard OS-E101 Drilling Plant Lifting Appliance

ANSI/ASME B31.3 Process Piping ANSI/AWS D1.1 ASTM-E466-82 ASTM-E468-90 ASTM-E739-91 ASTM-A450 IEC 60068 FEA-M Structural Welding Code - Steel Standard Practice for Conduction Force Controlled Constant Amplitude Axial Fatigue Tests of Metallic Materials Standard Practice for Presentation of Constant Amplitude Fatigue Test Results for Metallic Materials Standard Practice for Statistical Analysis of Linear or Linearized Stress-Life (S-N) and Strain-Life (e-N) Fatigue Data Standard Specification for General Requirements for Carbon, Ferritic Alloy, and Austenitic Alloy Steel Tubes Environmental testing Forskrifer for elektriske anlegg. Maritime installasjoner. Norsk Vassdrags og Energiverk (NVE). Page 6 of 68

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3

3.1

TERMS, DEFINITIONS AND ABBREVIATIONS

Definitions

For the purpose of this NORSOK standard, the following terms, definitions and abbreviations apply.

3.1.1 barrier envelope of one or several dependent barrier elements preventing fluids or gases from flowing unintentionally from the formation, into another formation or to surface Shall: Should: Verbal form used to indicate requirements to be followed in order to conform to the standard. Verbal form used to indicate that among several possibilities one is recommended as particularly suitable, without mentioning or excluding others, or that a certain course of action is preferred but not necessarily required. Verbal form used to indicate that among several possibilities, one is suitable, without mentioning or excluding others, but not necessarily required.

May:

3.1.2 qualified special proof for being fit for the intended purpose

NOTE To be documented by design, calculation and function testing and verified by 3 rd party or independent surveyor.

3.1.3 maximum expected wellhead pressure maximum shut in wellhead pressure plus additional pressure from well intervention activities 3.2 Abbreviations BHA bottom hole assembly BOP blow out preventer BPV back pressure valve CE European Conformity Assessment Mark EEA European Economic Area ESD emergency shut down FAT factory acceptance test HVAC heating ventilation and air conditioning LCC life cycle cost MTBF mean time between failure MTTR mean time to repair NPD Norwegian Petroleum Directorate UPS un-interruptable electrical power supply ANSI American National Standards Institute NORSOK standard Page 7 of 68

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ASME ASTM BS DNV NACE NS FEA-M

American Society of Mechanical Engineers American Society for Testing and Materials British Standards Det Norske Veritas National Association of Corrosion Engineers Norsk Standard Forskrifer for elektriske anlegg. Maritime installasjoner. Norsk Vassdrags og Energiverk (NVE).

4

GENERAL REQUIREMENTS

4.1 General The well intervention equipment shall be designed, built and equipped in compliance with applicable regulations and this NORSOK standard. 4.2 Design principles An overall objective for well activities shall be the requirement that no single failure shall entail a life-threatening situation for the involved personnel, or significant damage to material and the environment. This applies both to operational errors and to failure in connection with equipment used directly in operations, as well as equipment with auxiliary functions. The objectives shall constitute the basis for definition and revision of the acceptance criteria for risk in connection with well activities, and for the choice of risk reducing measures. System and equipment are to be protected against excessive loads and pressure. System and equipment are to provide two independent levels of protection to prevent or minimise the effects of a single malfunction or fault in the process equipment and piping system, including their controls. Different types of safety devices to reduce the probability for common cause failures should provide two levels of protection. All equipment shall be located to ensure safe operation and, if located in hazardous areas, shall be suitably protected for installation in such areas. Reference is made to NORSOK standard Z-015 regarding relevant discipline requirement for design and installation of service containers, such as fire and gas, electrical, HVAC, etc. for temporary equipment. The facilities shall be designed to minimise risks of personnel injuries, environmental hazards and economic loss. Reference is made to NORSOK standard S-001, NORSOK standard S-002, NORSOK standard S-003 and NPD Regulations. 4.3 Design principles references and standards NORSOK, ISO and API standards constitute a good starting point as regards reference documentation when designing well intervention equipment.

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Planning, design, fabrication, operation and maintenance of well intervention equipment shall be according to documents listed in Table 1, Table 2, Table 3, Table 4 and Table 5. Table 1 Snubbing Note: ( ) means standards under preparation Equipment Norsok ISO API Substructures / N-001 (13626) 4F masts / gin pole

Pipe handling system; Jack/pulling unit; Rotary / power swivel Work window Slip bowls / carriers Make up / brake out tongs Winch package / hoisting equipment Circulating swivel Kelly valves Workstring BHA

(13535) 8C (13535) 8C N-001 (13626) 4F (13535) 8 C (14693) 7K (14693) 7K 9A (10423) 6A (15156) (13535) (10424) (15156) (10424) (11960) 9001: Chapter 4.5 4.7 & 4.16 8C 7 7 5CT

Other NS-3472 Steel structures ­ Design rules BS-7072 Code of practice for inspection and repair of offshore containers DNV Lifting Appliance DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant NS-3472 DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant

BS 308: Parts 1, 2, & 3. BS 4656: Parts 1, 2, 3, & 4.

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Table 2

Coiled Tubing Norsok N-001 ISO API Other NS-3472 BS449 BS7072 DNV Lifting Appliance DNV Offshore standard OS-E101 Drilling Plant NS-3472 BS-449 BS7072 ANSI B31.3 AWS D1.1 DNV Lifting Appliance DNV Offshore standard OS-E101 Drilling Plant (11960) 5CT, 5C7 (15156) 9001 NACE-TM-0177 NACE- MR- 0175 ASTM-E466-82 ASTM-E468-90 ASTM-E739-91 ASTM-A450 ASME- sec. VIII Div.1&2 NS-3472 BS449 BS7072 DNV Lifting Appliance DNV Offshore standard OS-E101 Drilling Plant BS 308: Parts 1, 2, & 3. BS 4656: Parts 1, 2, 3, & 4.

Substructures

Injector head w/ Tubing guide arch (gooseneck), Injector support frame(s) & Injector lifting frame

N-001

Coiled tubing workstring (steel coiled tubing)

Coiled tubing reel

Z-015

BHA

9001:, Chapter 4.5 4.7 4.16

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Table 3

Wireline Norsok N-001 Z-015 ISO API Other DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant DNV Offshore standard OS-E101 Drilling Plant

Substructures Wireline unit Clamps/sheaves and hay pulley; Pressure test pump Wellhead pump Wireline mast (crane) Slick, braided and electrical line down hole tools Table 4

Z-015 Z-015 (13626) 4F

BS 308: Parts 1, 2, & 3. BS 4656: Parts 1, 2, 3, & 4.

Snubbing Coiled Tubing and Wireline ­ General Norsok H-001 Z-015 Z-015 Z-010 (10423) 6A (15156) (10423) 6A (15156) NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 ANSI B.31.3 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 ANSI B.31.3 DNV Offshore standard OS-E101 Drilling Plant ISO 9241 API Other IEC60068

Equipment Operator cabin w/ Control system & Data acquisition system Hydraulic power pack Circulating system

Chiksan / stand pipe

Circulation hoses

(15156)

Lifting requirements Containers

Z-015 Z-015

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D-002 Rev. 1, October 2000 FEA-M (1990)

Electrical equipment design and installation Table 5

Z-010 Z-015 E-001 E-002

Well Control Equipment Norsok ISO API (13533) 16A (15156) Other NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant

BOP's for snubbing, coiled tubing and wireline ; stripper rams, blind/shear ram, pipe rams ( fixed or variable ), slip rams , shear seal rams & safety head wireline ram Annular preventer

(13533) 16A (15156) (13533) 16A (15156) (13533) 16A (15156) (10423) 6A (15156) (10423) 6A (15156) (10423) 6A (15156) (10423) 6A (15156) 16C (15156)

NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant NACE-MR-0175 NACE-MR-0175 NACE-MR-0175 NACE-MR-0175 DNV Offshore standard OS-E101 Drilling Plant

Snubbing stripper bowl or active stripper. CT dual stripper

Gate & plug valves, check valves and loops Stuffing box for solid wireline - Slickline Grease injection head with relevant sized flowtubes Braided cable Hydraulic line wiper and stuffing box, Open hole operations Choke & kill systems

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D-002 Rev. 1, October 2000 16D 16E DNV Offshore standard OS-E101 Drilling Plant FEA-M (1990)

BOP accumulator unit system w/ BOP control hoses

Z-015 Z-010 E-001 E-002

4.4

Verification, testing and marking

4.4.1 Verification Verification of design, fabrication and testing shall be carried out and implemented according to an overall and clearly defined verification programme and verification basis There shall be independence between those who carry out the work, and those who are responsible for the verification. The verification may thus comprise control of calculations, drawings and fabrication by going through what have been done or carrying out independent or own calculations. The verification may also include trials or testing of equipment and systems. By independence means that the verification shall be carried out by someone other than the one who has performed the work which is to be verified, or the one who has prepared the verification basis, and also that there shall be organisational independence regarding reporting in the chain of command. An important condition is that the verifying unit has the necessary competence and resources to carry out the verification. Verifications shall be carried out in accordance the requirements in this NORSOK standard. Consideration of complexity shall be included in the evaluation, as well as the probability for or the consequences of failure or faults, which may occur. The verification shall be documented and should comply with issuance of e.g. design verification report and product certificate. 4.4.2 Testing requirements for new equipment The various vendors shall present a test procedure, including acceptance criteria, prior to the FAT. The procedure shall describe all tests to be carried out during the FAT and procedures for commissioning and the start-up phase for the equipment as a stand-alone unit. At FAT the well intervention equipment shall, to the extent possible, be tested as a complete system, with all subsystems integrated. Loads and signals shall be simulated and recorded. During commissioning and start-up, the various systems and their drilling instrumentation package shall be utilised to verify the sensor data.

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4.4.3 Marking Equipment shall be clearly marked as follows with identification and operational limitations, relating the equipment to certificates and fabrication documentation: Equipment identification: · manufacturer's name or mark; · equipment type no.; · equipment serial no. Operational limitations such as: · working load limit; · working pressure; · maximum voltage; · maximum temperature. There shall be consistency between units used for marking and units displayed on instruments. CE marking applies to machines and simple pressure vessels on fixed installations. Machinery placed on the market after 8 April 1995 shall be designed, manufactured and documented in accordance with the requirements of the Machinery Directive 98/37/EC/Forskrift om maskiner Best. nr. 522. The requirement entails that the individual contractor, sub-contractor etc. shall ensure that machinery taken into use has received CE marking and that it is accompanied by a declaration of conformity. By marketing («place on the market») is meant the first time a product, against payment or free of charge, is placed at disposal with a view to distribution or use within the EEA. The NPD has in cooperation with other authorities, defined the following criteria for when a product is considered placed on the market: · · · · when the right to utilize of the product passes over from a manufacture within the EEA area to the next link in the chain of distribution; when the equipment is imported from a country outside the EEA area, and the right to utilize of the product passes over from importer to the next link in the chain of distribution; when the equipment was offered and is available for direct sale from the manufacture or from an importer and the purpose was to direct sale to users; when a manufacturer or an importer takes into use equipment imported by him.

The requirement contained in this section applies only to machinery comprised by the Machinery Regulations. This entails that the requirement applies only to machinery used on fixed installations. The reason for this is that Machinery Regulations are not applicable to ships and mobile offshore units.

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4.5 LCC and regularity Regularity requirements shall be defined prior to detailed design, based on stability (MTBF/MTTR) and service intervals. The service intervals shall reflect the MTBF. LCC shall be defined for all vital parts in the well intervention equipment. 4.6 Process and ambient conditions The well intervention equipment shall be selected and designed to operate under ambient conditions prevalent in the intended area of operation, and shall be resistant to well intervention and formation fluids. 4.6.1 Design basis The equipment shall be designed as required for the following conditions: · · · · ambient temperature, structures: -20 °C to + 40 °C; ambient temperature, machinery: -10 °C to + 40 °C; humidity: 100%; for conditions where H2S service is required, NACE MR-0175 applies.

The design basis shall be defined for the following load combinations: · · · · · · operational load; snow and ice loads; earthquake conditions (optional); impact from transportation; wind conditions; the structure shall as a minimum be designed for continuos operation with regards to hook load, rotary load for wind speeds up to 30 m/s, 10 min. mean values, considering a reference height of 50 m above lowest astronomical tide, unless otherwise specified. Layout and working environment requirements

4.7

4.7.1 General All work areas in connection with well intervention equipment shall be arranged to ensure the safety of personnel and operations, working environment and pollution control, in accordance with NORSOK standard S-001, NORSOK standard S-002 and NORSOK standard S-003 and project safety goals. The layout of the well intervention equipment shall give due consideration to areas that may be critical to dropped objects, especially in connection with materials and equipment handling. The layout shall ensure that maintenance and service can be carried out in a safe and ergonomically efficient way.

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4.7.2 Noise protection requirements. Special attention hall be made to requirements defined in the NORSOK standard S-002 for design of cabins, power generation packages, fluid and N2 pumping units and accumulator packages. The control cabins for snubbing, coiled tubing, wireline equipment and pumping units shall be designed to withstand a total outdoor area noise level impact of 90 dB (A) and be designed according to values defined in NORSOK standard S-002, annex A, for driller cabins. The total noise level shall not exceed 65 dB (A) inside the cabin. The power packages, fluid and N2 pumping units and accumulator packages for snubbing, coiled tubing and wireline operations shall be designed according to values defined in NORSOK standard S-002. The equipment shall be designed in such a manner that the total noise level from the equipment shall not exceed 82 dB (A) and the equipment shall not contribute to exceed a max area noise level as defined in NORSOK standard S-001, i.e. 85 dB (A) on pipe deck area. 4.7.3 Material handling The layout and design of the well intervention equipment shall ensure safe and efficient transport and handling of equipment and materials. A material handling study should be performed to secure safe and efficient operation. 4.8 Special requirements for skid base structures The skidable part of the well intervention rig up frames and structures should be installed on the platforms integrated skid beams, extending to at least one platform edge to facilitate on/off loading of modules. The frames and structures shall be designed to suit all relevant load conditions, see NORSOK standard N-001 and NORSOK standard N-003. The remaining parts of the well intervention equipment shall be located adjacent to the skidable structure. Contaminated fluids shall be collected and routed to a dedicated slop tank system. All other fluids from the well intervention equipment, rigged up on top of the skid base substructure, shall be discharged to the installations drain points. 4.9 Utility interfaces The well intervention equipment should be supplied with dedicated interface termination points. Mechanic, electric, hydraulic and pneumatic interface connections shall be compatible with rig or platform connections. The following utilities should typically be supplied by the platform facilities to support the well intervention equipment: · · · · · · electrical power supply; emergency power supply; fire and gas control interface; emergency shutdown interface; sea, fresh water, steam and hot water; drains; Page 16 of 68

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· · · · · · · · · · ·

drains/vents for hydrocarbones; UPS; instrument and plant air; diesel; telecommunications interface; main data bus interface; closed circuit television interface bulk brine; HVAC; methanol; glycol (monoethylene glycol/ diethylene glycol/ triethylene glycol). Operational requirement

4.10

4.10.1 Maintenance requirements All equipment shall be subject to systematic maintenance. This is to ensure that it is in good condition if the need should arise for the use of preserved equipment. The extent of maintenance, which is overdue, should be limited. Prior to start-up of demanding phases of the activities there should not be any maintenance on critical equipment overdue. In order to maintain an acceptable safety level, it is important that adequate safety routines are established in connection with maintenance, e.g. in connection with pressure relief, fire protection, alerting personnel, fencing off areas etc. The purpose of systematic maintenance is to ensure that: · · · · test conditions for components and equipment are specified; repairs and modifications are carried out in such way that an adequate level of safety is maintained; experience data are systematically collected and recorded for improvement of equipment and operations; experience data are reported back to the manufacturer/supplier.

4.10.2 Testing requirements Function testing of all components including all accessory equipment shall be performed prior to each job. Function testing of the positive and negative weight indicator system shall be performed prior to each job. Function testing of all interfaces to permanently installed equipment and systems. Documentation and verification to be submitted to verify acceptable rig up versus forces and bending momentum's, downhole tools, well control system, frames, main equipment and pumps expected work conditions inside set safety limits.

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5

WELL INTERVENTION WELL CONTROL SYSTEM

This clause describes the mechanical well control system with associated equipment. The well control system shall comprise equipment as described below: 5.1 Equipment configuration The BOP system shall as a minimum consist of: Primary well control system is defined as follows: Equipment External well control Snubbing X Stripper bowl or active stripper. X Two stripper rams X Equalising loop system If used One annular preventer Workstring Two back pressure valves in the BHA Coiled tubing · · · · · Dual stripper. Coiled tubing body (string) End connector One dual check valve in the BHA Alternatively ­ plugged end of coiled tubing. X X X X X

Internal well control

· · · · · ·

X X

Wireline Slickline operations Stuffing box for solid wireline. Braided cable Grease injection head with relevant sized flowtubes. Open hole operations Hydraulic line wiper and stuffing box, if applicable. Primary well control system for wireline operations is dependant on type and size of line and is located above the secondary well control system.

X X X

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· · · · · ·

· ·

Secondary well control system is defined as follows: Equipment External well control Snubbing X One combined blind/shear ram X Two pipe rams ( fixed or variable ) X One annular preventer X Minimum one choke line outlet X Minimum one kill line inlet X Minimum one manual gate and/or plug valve on each choke and kill line and minimum one remote hydraulic operated gate and/or plug valve. Alternatively the remote valve on the kill line can be replaced with one manual valve and a check valve. One nipple profile in the BHA One stabbing valve

Internal well control

X X

· · · · ·

Coiled tubing One combined shear/seal ram One pipe ram One slip ram Minimum one kill line inlet Minimum one manual gate valve and/or plug valve on the kill line and minimum one remote hydraulic operated gate and/or plug valve. Alternatively remote valve can be replaced with one manual valve and a check valve.

X X X X X

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Wireline · · · · One wireline ram One wireline ram (inverted ) A double valved kill inlet connection shall be included in the rig up during a live well intervention One combined shear/ seal ram

Slick line

Braided or electric line

X X X

X X X X

Tertiary well control system is defined as follows: Equipment External Internal well control well control General The safety head BOP shall be mounted as close as possible to the wellhead. Snubbing One safety head BOP X X Coiled tubing One safety head BOP X X Wireline One shear/seal ram (safety head BOP) X X The need for separate shear/seal ram (safety head BOP ) should on the individual facility be considered if the height distance between the valves is short or if remote control valve on the x-mas tree is documented as a shear/seal valve.

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5.2 5.2.1

Equipment requirements General Equipment

Snubbing Coiled tubing Wireline

The internal diameter of the BOP components and riser shall be specified to suit the intended purpose and capacity of the completion diameter as stated in the work program In cases where appropriate, the BOP can have an internal diameter less than the x-mas tree bore. The pressure rating of BOPs, stripper system/bowl, riser, valves, flanges, kill/choke systems of following systems shall as a minimum comply with the maximum expected wellhead pressure. Consideration shall be given to H2S protection of the complete system. The BOPs shall be fitted with qualified connections as follows. If alternative connections are used, they shall be qualified and certified to withstand the required forces and pressure. · 1) Flanged connections w/metal to metal seals. · 2) Quick union type. All side connections shall have metal to metal seal and have at least have 50,8 mm (2 in) nominal size. Kill line connections shall have metal to metal seal. Well control hoses and connections from BOP to safe area for secondary and tertiary well control purpose shall be fire resistant, capable of withstanding 1100ºC for minimum 3 min. Fire testing shall be in accordance with API 16D. The position of the kill and choke outlets should be arranged so that circulation for well control can be carried out with the workstring suspended in the BOP and the shear/blind ram closed.

X

X

X

X X

X X

X X

X 1)

X 1)

X 2)

X

X X X

X

X

X

X

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5.2.2

Pump down plugs, stabbing valves, back pressure and check valves Equipment Snubbing Coiled tubing

Back pressure valves A minimum of two BPV installed in workstring. A minimum of four BPVs shall be on work location. The BPVs shall allow balls and darts to pass through.

X X X

Check valves A minimum of dual check valves installed in workstring. A minimum of dual check valves shall be on work location. The check valves shall allow balls to pass through.

X X X

Pump down plugs and stabbing valves A minimum of one pump down plug for each nipple size specified in workover program shall be on work location. A minimum of two stabbing valves and necessary x-overs shall be on work location.

X X

5.2.3

Hydraulic operated stripper and stripper bowl system Equipment Snubbing Coiled tubing X X X X X Page 22 of 68

Hydraulic operated stripper The stripper system shall be a dual system that can be individually and hydraulically controlled from the control cabin. The upper stripper shall be located at shortest possible distance from the injector drive chains to minimise buckling potential when snubbing. Pressure rating in accordance with the needs for the operation. The stripper sealing elements shall fit the proper temperature and well pressure range. The sealing elements and extrusion rings shall be replaceable with NORSOK standard

System requirements well intervention equipment

D-002 Rev. 1, October 2000

coiled tubing inside to enable replacement of the sealing elements in case of a leak The wear bushings should be replaceable with coiled tubing located inside to enable removal of coiled tubing with increased and/or oval outer diameter and/or other changes in the tubing shape through the stripper by removing the bushings and elements The stripper control system shall be hydraulic operated and incorporate a regulating system to avoid over-pressurisation and collapse of the workstring. The hydraulic stripper pressure shall be maintained regardless of prime mover operation. A backup system incorporating a hand pump or air pump system shall be used. An injection port shall be incorporated between the upper and lower stripper to enable injection of inhibitors and/or lubricants. This port can also be utilised for flushing prior to leak testing and/or monitoring of wellhead pressure if required. The connection between the upper and lower stripper can be of a quick hand union design, providing the connection has been qualified. A hydraulic quick latch type connection should be utilised between the lower stripper and the coiled tubing BOP. Such a quick latch shall on the bottom have a nominal bore minimum equal to the nominal bore of the coiled tubing BOP. A work window may be utilised between the lower stripper and the coiled tubing BOP. The window minimum nominal bore should be equal to the nominal bore of the coiled tubing BOP. Connections on both ends of the window can be of a quick hand union type, providing the connections has been qualified. The active stripper system for snubbing shall be hydraulically controlled from the workbasket/control cabin. Stripper bowl Gauge and bleed off port on stripper bowl housing for trapped pressure. Stripper bowl shall be prepared to allow for installation of a wireline adapter

X

X

X X X

X X

X

X

X

NORSOK standard

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5.2.4

Stuffing box, grease injection head, hydraulic line wiper and Equipment Wireline X

Stuffing box The hydraulic actuated packing nut to be operated from the hydraulic control panel. Stuffing box shall be equipped with a qualified device preventing hydrocarbon leaks in case of wireline breakage Grease injection head A line wiper and stuffing box to be included in the grease injection head assembly. The grease injection inlet manifold to include a check valve. Integral check valve system to be included and two ports for grease injection. Grease injection head stuffing box shall be equipped with a qualified device preventing hydrocarbon leaks in case of wireline breakage Hydraulic line wiper Hydraulic actuated rubber element operated from hydraulic control unit.

X

X

5.2.5 Pipe, stripper, slip, tubing, wireline shear blind, shear / seal, safety head rams and annular preventer requirements Equipment General The BOPs shall have a mechanical locking system to enable locking of the rams in closed position. Indicator "pins" for open and close status of the BOP should be included. If remote mechanical locking of BOP is used, indicator "pins" can be voided. The rams shall be dimensioned to suit the actual "workstring" and be able to close/open against full wellbore working pressure. The rams shall be able to close/open against maximum working pressure. The rams shall be capable of centralising without damaging relevant "workstring" against side loads. Snubbing Coiled tubing X X X X X X1 Wireline

X X X X X X1

X X X X X X2

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Pipe, stripper, slip, tubing and wireline rams The rams shall be able to close around the "workstring" and seal off the annular space in the BOP bore. Pipe and slip ram hang off capacity compatible with the workstring weight. Front packer on stripper rams shall be wear resistant for stripping. The slip ram shall be capable of holding the workstring and prevent up and down movement. X The slip ram shall be of a design that minimises or avoids stress marking of the tubing. X The top and bottom ram for braided and electric line to hold pressure from top and below, a grease injection/test port between the rams shall be included. X X1 X X X X X1 X X2

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Annular preventer The annular preventer shall be able to close and seal off at max. shut in / max. expected operating pressure rating on open hole. The annular preventer shall operate (close) on both stationary and running objects. Stripping through the annular with the specified workstring shall be possible without damaging the tubular. The annular preventer shall be furnished with accumulator(s) as a surge dampener for emergency stripping of pipe and tubular. Accumulator system can be voided if there are no external upsets on workstring Shear/blind ram or seal ram The shear/blind ram shall be capable of shearing the highestgrade of workstring, as well as sealing off the wellbore with lateral and face seals. The shear/seal ram shall be capable of shearing the highestgrade of as follows, as well as sealing off the wellbore with lateral and face seals. The ram design needs to clear sheared workstring from the seal area as a part of the shearing and closing operation, to enable circulation rate through the workstring left in the well. The shear blades shall be designed to prevent small pipe or cable to be caught between the ram blocks and the wellbore side. X X If used

If used X

X

X1

X2

X

X

X

X

1 2

Workstring Wire

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Safety head The safety head shall be a combined shearing and sealing ram capable of shearing the workstring and sealing the bore with the maximum working pressure. There shall be documentary evidence that the safety head will shear the intended size and wall thickness of workstring (coiled tubing and snubbing), including any wire, cable or capillary lines and provide sealing effect after shearing, see annex B. For wireline the safety head shall be able to cut and seal the wire only. The shear blades shall be designed to prevent small pipe or cable to be caught between the ram blocks and the wellbore side. Minimum nominal bore shall be equal to or greater than xmas tree bore. X Shear and seal capability shall be available when the "workstring" is unloaded, in tension, or in compression X X X X

X

X

X

X X

X X

X X

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5.2.6

Riser, lubricator, tool catcher and chemical injection sub

Snubbing Coiled tubing Wireline

Equipment Riser The riser shall as a minimum have the following specifications: · · pressure rating in accordance with the needs for the operation; arrangements to enable bleed off and verify no trapped pressure to be included.

X

X X X X

X X

The riser shall have a minimum number of connections and no inlets or outlets between the safety head and the x-mas tree. If alternative connections are used, such as on floater operations, the connections shall be qualified to withstand the required forces and pressures. Lubricator The lower section of the lubricator shall have a minimum nominal bore equal to or greater than BOP internal diameter. Arrangements to enable bleed off and verify no trapped pressure to be included. Tool catcher The tool catcher shall be of failsafe type spring catch/hydraulic release design. Chemical injection sub The chemical injection sub injection inlet manifold shall include a check valve. The liquid chamber shall be made of soft material (brass or equivalent).

X

X

X

X

X

NORSOK standard

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5.2.7

Piping and hook-up valves to well control system Equipment

Snubbing Coiled tubing Wireline

Piping and hook-up valves All piping and hook-up valves to the well control system shall have a pressure rating in accordance with the needs for the operation. The piping and valves to treating and flowing lines should be minimum 50,8 mm (2 " in) nominal size. Kill line for wireline should be minimum 50,8 mm (2 in) nom size. All outlets and inlets on the BOP system shall have metal to metal seals. The outlets and inlets shall be fitted with at least two valves. 1) All outlets and inlets. 2) All outlets and inlets below shear/seal ram. · · · The valves shall be bi-directional and the inner valve, closest to the wellbore, should be flanged and have metal to metal sealing in the bore (gate valve type). Threaded connections are permissible only downstream the first valve away from the well and riser bore. One of the two valves on outlets and inlets for treatment or flow lines shall be remotely operated. On the kill line, a manual operated valve and a check valve can replace the remotely operated valve. The inner valve shall not be used as a working valve.

X

X

X 1) 2) 2)

X X X

X X X

X X

·

X X X

X X X

X X

Check valves, if used, shall be of a flapper or cone design. Ports for pressure monitoring, injection, etc in and below secondary well control, shall have connections with metal to metal seals, and be double valved with metal to metal seals in the bore. Valves and connections may be of a threaded design. Any redundant outlets may be blocked with blind flanges or plugs with metal to metal seals instead of two valves. Circulating, standpipe, equaliser and bleed off lines Equalising loop on stripper rams assembly to incorporate a hydraulic pressure de-booster with remote measuring of well pressure. Workbasket and/or cabin gauge to monitor pressure between stripper rams.

X

X

X

X

NORSOK standard

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5.2.8 Choke manifold The choke manifold shall, both for snubbing and coiled tubing as a minimum include two chokes, manual or remote controlled. In the case of manually operated chokes, the circulating pressure and the choke manifold pressure shall be displayed on or close to the manifold. All pressure indicators gauges should be through hydraulic pressure deboosters with remote output. The manifold should also be fitted with a connection facility for an optional pressure gauge with low increment readings. Lines and hoses between the BOP stack and the choke manifold system shall, together with their connections and valves on the high pressure side of the choke manifold, as a minimum have the same working pressure rating as the BOP stack. All valves should be gate valves. 5.3 Control system The operation of the primary well control system can be from one control panel. The operation of the secondary well control system shall be from minimum two control panels, one control panel located at the operator's workstation, and one control panel located in a safe area. The operation of the tertiary well control system shall as a minimum be operated from a safe area. The accumulator unit(s) to operate the secondary and tertiary well control system shall be located in a safe area in order to avoid exposure in the event of an uncontrolled well control situation, i.e. away from the well area and close to an escape way. The rig-floor is normally not considered as a safe area. The control panel(s) for operating the secondary and tertiary well control systems may be integrated into the BOP accumulator unit(s).

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5.3.1 General The control system shall consist of the following for Snubbing, Coiled tubing and Wireline: · Control panels which clearly indicates (e.g. Indicator with status of the functions shall be included by means of lights or selector valve) information for the panels whether the functions are in open or closed position · The control panels with motion selector valves and switch buttons shall be equipped with a securing device against unintentional operation of essential functions (e.g. shear ram). Accidental operation shall not occur. · The BOP control system and panels shall be equipped with alarms for low accumulator pressure, loss of power and low level of control fluid. · Regulators in the system shall remain unaffected in the event of loss of power. · BOP ram operating pressure shall as a minimum be regulated from the BOP accumulator unit. · Maximum response time when the BOP is located on a surface installation, 30 seconds. Response time refers to the time it takes from the closing function is activated from the panel, until the BOP function is in closed position. · Stripper ram maximum response time for snubbing: 5 seconds · Equaliser, bleed off, kill line and choke line valves maximum response time for snubbing: 1 second The accumulator capacity for operating a BOP stack with associated systems shall as a minimum have sufficient volumetric capacity to close, open and close all the installed BOP functions plus 25 % of the volume for one closing operation for each one of the said BOP rams. The following BOPs operated from the well control system shall be used as basis when calculating the accumulator capacity: Snubbing Coiled tubing Wireline · Annular preventer · Shear/seal ram · Wireline ram · Upper pipe ram · Pipe ram · Wireline ram · Shear/blind ram · Slip ram · Shear/seal ram · Lower pipe ram · Equaliser loop valve · Bleed off valve · Kill line valve · Choke line valve There shall be documentary evidence that the pressure capacity of the accumulators is capable of operating the rams according to the design requirements.

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As a minimum for dimensioning total accumulator volumes and capacities (isotherm, adiabatic slow charge and fast operation) shall be included. Coiled tubing Workstring Coiled tubing string Annular preventer Pipe ram N/A Pipe ram Snubbing Wireline Wire/cable

Accumulators shall have sufficient pressure capacity to enable cutting of the relevant workstring. There shall be sufficient remaining accumulator pressure to enable cutting, after having used a volume corresponding to as follows: Closing and opening of one Closing, opening and closing of one

N/A Wireline ram

Alternatively a dedicated shear ram auxiliary pressure system (shear boost system) may be installed to meet the minimum requirements to cut the workstring if the remaining accumulator pressure is not sufficient to enable cutting after having performed operations as described above. The accumulator system shall be separate from all other hydraulic circuits, i.e., only the well control system can take fluid from the storage accumulators. The accumulator system shall be designed such that the loss of an individual accumulator and/or bank will not result in more than 25 % loss of the required total accumulator system capacity. The control panels shall have an ergonomic layout and be designed according to NPD Regulations and NORSOK standard S-002

NORSOK standard

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5.3.2 Function requirements for accumulator unit and panels for primary and secondary well control functions Panel located on the BOP accumulator unit and panel (located in the operator cabin/ workbasket) to be equipped with functions for as follows: Snubbing Coiled tubing Wireline Acc. unit Work Acc. unit Wireline Acc. unit Coiled Regulators for as follows:

basket cabin tubing cabin cabin

BOP ram activation pressure-manifold pressure. Annular preventer regulator. Active stripper regulator. Upper stripper regulator. Lower stripper regulator. Alarms for as follows: Low accumulator pressure. Loss of power supply. Low level of control fluid. Pressure monitoring: Accumulator pressure BOP ram activation/ manifold pressure. Annular preventer pressure. Active stripper pressure. Upper stripper pressure. Lower stripper pressure. Basic BOP ram/valve open and close functions: Annular preventer. Stripper ram 1. Stripper ram 2. Upper pipe ram. Shear/blind ram. Lower pipe ram. Equaliser loop valve. Bleed off valve. Kill line valve. Choke line valve. Shear/seal ram. Pipe ram. Slip ram. Wireline ram. Wireline ram (inverted).

X X If used

If used X If used

X If used

If used If used X X

If used

If used

X X X X X X If used

X X X X X X If used

X X X X X If used

If used If used If used X X If used X X

X X X X X

If used If used If used X X

X X X X X X X X X X

X X X X X X X X X X

If used

If used

X X X X X X X X X

X X

X X

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Flow monitoring: BOP fluid monitoring. Optional BOP ram/valve open and close functions: Active stripper. Deployment functions Seal/slip ram. Blind ram. Locking holding ram. Disconnect ram. Auxiliary valve. BOP accumulator bypass: BOP accumulator unit shall be equipped with a bypass function for allowing accumulator pressure to bypass the regulated manifold pressure. Additional control functions: Grease injection to BOP.

X

X

X

X

X

X

X X X X X X X

X If used If used If used If used X X X X

If used

X

X

5.3.3 Grease injection skid/hydraulic control skid for wireline The grease injection skid shall as minimum include two pumps and grease tanks. The capacity shall as minimum be 0,25 l/min per pump at maximum pump pressure. 5.3.4 Tertiary BOP control system (for safety head) for snubbing, coiled tubing and wireline The basis for design of the BOP accumulator unit for operating the safety head (defined as the tertiary well control system) is the same as for the BOP accumulator system to operate the secondary well control functions. This includes accumulator capacity design, BOP hoses design, shear boost (if used) system, regulators and monitoring of pressure internal on the unit, alarms, volume monitoring (flow) and indicator status on open and close functions. 5.3.5 Choke control system for snubbing, coiled tubing and wireline Operation of a remote controlled choke, if installed, shall take place from a suitable panel. The panel shall at least indicat · · · · · circulating pressure (workstring / coiled tubing internal pressure); choke manifold pressure; choke position indicators; volume pumped; well fluid pump rate.

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6

SNUBBING EQUIPMENT

6.1 General The snubbing equipment with associated systems shall be capable of handling the workstring, well conditions and other work parameters specified by the work program. This clause describes the minimum functional requirements for snubbing equipment. The snubbing well intervention system will normally consist of the following main items: · · · · · · · · · · · · · · · snubbing units/snubbing units with derrick/mast type structures pipe handling system; jack/pulling unit; work window; slips; tong post/tongs; winch package; gin pole; workbasket and operator cabin; circulating system; control system; data acquisition system; hydraulic power pack; well control system; workstring and BHA.

The system shall be designed to and be capable of handling tubular such as, but not limited to, in an efficient way: · · · · drill and workstrings; casing and tubing strings; high pressure risers and associated equipment (optional); BOP stacks and x-mas trees (optional).

Requirement for modularization shall be specified. The system design shall allow for performing Wireline work and electric logging operations within the workbasket/snubbing unit working platform area, considering space, height, equipment handling, access to the equipment and weather protection. The equipment should be equipped with a four point lifting arrangement for both horizontal and vertical handling of modules where applicable.

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6.2

Snubbing equipment requirements

6.2.1 Snubbing units / snubbing units with derrick/mast type structures The derrick, mast or hoisting structure shall be designed to withstand the loads and forces imposed by the relevant operational and environmental loads. In addition, the structure can be used for support of pipehandling equipment, and support for racked tubular on setback areas if applicable. see NORSOK standard N-001. Access in connection with operation and maintenance of equipment shall be catered for by suitable and safe access from deck or installed work platforms. From current practice it follows that the various work platforms in structures (including platform for installation of casings) shall be adequately equipped with safety devices, lifts, stairs or ladders for safe access, see NORSOK D-001 standard. Lubrication points with difficult access in the workover area, such as sheaves, shall be routed to a readily accessible area. Sufficient number of hang off points of required capacity for travelling assembly, manual rig tongs and work winches shall be installed. All hang off points and/or padeyes shall be properly marked with safe working load, and the design shall ensure that safe working load does not exceed 20 % of the breaking load. The snubbing unit working platform area shall in relevant areas be designed for dropped object protection, i.e. to withstand the impact from the heaviest expected tubular falling from a height of 1,5 m. All permanently manned working areas shall be weather protected. The primary work area shall be covered with a non-skid material. The substructure shall be designed to form an adequate foundation for the structure/mast or hoisting structure and the snubbing unit working platform area, and provide required elevations and handling space for BOPs and optional x-mas trees etc. The substructure shall be designed to withstand all combined loads from, mast or hoisting structure and snubbing unit working platform area with full loading, BOP handling loads, if applicable, as well as equipment installed in the substructure itself. The complete design shall be considered for lubrication (space out) of applicable BHA such as running and pulling perforating and gravelpack assemblies when rigged up on a live well. 6.2.2 Pipe handling system The snubbing unit shall be equipped with a remote pipehandling system to include · · · vertical pipehandling system; horizontal pipehandling system; horizontal to vertical pipehandling system.

The workbasket/snubbing unit work platform area shall be unmanned and equipment remotely operated in normal "drilling" and tripping operations. The horizontal transportation system and the horizontal to vertical transportation system shall be remote operated with the possibility for

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· ·

stowage, make up, break out and suspension of workstring, collars, casings and tubing in the rotary table; transport of workstring, casing, collars etc. to and from storage location in front of " V- door " to the snubbing unit working platform area. The complete string of tubular shall be stored on a location where it require no platform crane handling between the storage location to the snubbing unit workbasket/working platform area (drillfloor).

An anti collision system should be installed to prevent collision between the main hoisting equipment, the pipehandling equipment and structures. 6.2.3 Jack/pulling unit The snubbing unit shall have a pulling and pushing (snub) capacity to the maximum expected and anticipated load for the operation. Rotary head or top drive shall be protected. The hydraulic hoses to the unit shall have sufficient lengths to position the hydraulic support system at the required distance from the well area. All hoses in suspension from a connection shall be equipped with quick disconnect complete with locking feature including dust plug and cap. The unit shall be equipped with an anti buckling guide tube system to support the workstring and the inside diameter to suit actual workstring 6.2.4 Work window The unit shall contain a work window assembly and the height shall be according to the requirements in the work program. Window shall be designed with load rating equivalent to the jack and/or pulling unit with feature for hanging off the workstring. There shall be a work platform at the work window level. 6.2.5 Slips The slips design rating shall be equivalent to at least the maximum thrust of the jack/pulling unit system and shall be remote operated. Unit shall be equipped with dual redundant stationary snub slips. The slips shall be equipped with a cross port relief valve system to prevent hydraulic and mechanical damage in the event of forced opening of equivalent function. 6.2.6 Tong post/tongs Tongs shall be remote operated. If an old system with conventional tongs are used the following applies:

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·

the height from the tong post arm to the workbasket handrail shall be adequate to accommodate the power tong and with a suspension and trolley arrangement to allow swinging of tong away from the centre line; tong suspension arrangement to allow the introduction of a spring to prevent overload of tong arm during make-up of tubular joints; to incorporate tong backup attachment eye, rated at the maximum horizontal force resulting from the maximum tong torque capacity.

· ·

One set of tubing tong with slide heads for both tong and back-up to fit the tube and upset connection of the workstring. 6.2.7 Winch package The dual type counterbalance winch package shall if used be skid mounted with drip pan. The winch package to contain an automatic fail-safe brake in the event of hydraulic failure and the safe working load on the winch shall be determined by the work program. Winch package can be voided if design of unit do not require such system. 6.2.8 Gin pole Where a gin pole system is required, it shall be able to extend to such a height that the distance from the bottom of the gin pole sheaves to the workbasket (handrail) is sufficient to accommodate the pipe length (Range II or III) plus safety valve, circulation swivel, swivel with tackle including a reserve air gap of minimum 1,0 m (3 ft). The system shall contain a hydraulic arrangement for raising and lowering of the gin pole. 6.2.9 Workbasket and operator cabin If the jack and pulling unit is designed with a workbasket, the travelling head area shall be equipped with removable internal handrail to guard against the rotating workstring. Personnel safety and working environment shall be given due consideration. The workbasket shall have two independent escape exits and be equipped with wind walls for weather protection, and a workstring mark board in the workbasket area for operator quick reference of workstring depth. The layout of the operator cabin shall ensure full operational control and view from the operator's position to the various parts of the work floor area. The control cabin shall have an ergonomic layout and be designed according to NPD Regulations and NORSOK standard S-002. The control cabin shall facilitate all necessary controls and monitoring equipment to operate the complete snubbing unit and well control equipment as defined in clause 5. Control cabins shall satisfy the following requirements:

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· · · · · ·

the operator cabin shall have an ergonomic layout and shall be equipped with laminated glass, oil resistant wiper or cleaner and a suitable mechanical ventilation system; the roof and windows shall have adequate strengthening or protection against falling objects. due consideration to be given to visibility on control system visual display unit screens; jack "snub" and "heavy" force limitation shall be pre-set at power pack manifold local adjustments in workbasket and cabin shall not override the pre-set value; there shall be individual hydraulic circuits for jack, pipe-handling system, BOP and auxiliary system. Each circuit shall have an adjustable pressure safety relief and pressure indicator; interlock shall be provided to prevent inadvertent opening of the stationary and the travelling heavy slips simultaneously. It shall be possible to manually over ride this interlock.

The controls and monitoring equipment shall as a minimum include the following: · · · · · · · · · · · · · torque control for rotary or top drive; rotary/top drive speed adjustment; rotary/top drive direction control; power package speed control; power package shut down; power package ESD, selector for operating jack by two of four cylinders (option); jack direction control lever; slip bowl control levers; slip pressure regulator; weight indicator (heavy and snub force); wellhead pressure; circulating pressure.

6.3 Data acquisition system The snubbing unit shall be equipped with a data acquisition system to display and record operational parameters. The data-sampling rate shall be sufficient to record relevant variations in the displayed and recorded parameters. A system for analyzing the recorded data shall be available at the location. The snubbing unit shall be equipped with a data acquisition system to monitor and record the following parameters: · · · · · · · · · · · time and date; workstring weight, positive and negative (heavy and snub); jack hydraulic system pressure; wellhead pressure; workstring pressure; workstring depth; rig and slip hydraulic pressure; rotary torque and rpm. workstring connection torque; optional: volume control; optional: pump speed.

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In addition, there shall be a back-up system, which records · · · workstring weight (positive and negative); wellhead pressure; workstring pressure.

6.4 Power package Two independent power packages are required at the work site. Minimum one unit shall be diesel driven and capable of supplying sufficient power to operate all operating systems of the snubbing unit on a continuos basis and at peak demand. The power package shall be designed and sound proofed in accordance with NPD Regulations. Provisions shall be made for a manual ESD system that is operated locally and remotely from the workbasket/control cabin. The power package shall be certified for operating in Zone II areas and in accordance with NORSOK standard Z-015. Provisions shall be available for remote and local control. Individual adjustment and pre setting of the operating limits for maximum pull and push forces to the snubbing unit shall be possible. These shall be protected from adjustment during normal operating conditions. If the power package is used for charging the accumulator system for the well control equipment, the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic circuits. Only the well control system shall be able to take hydraulic pressure from the dedicated accumulators. 6.5 Circulating system The circulating swivel and circulating hose working pressure to comply with operational requirement. The integral 90° gooseneck with lift eye shall if used be compatible with counterbalance winch. Pin connection on swivel shall be compatible with the safety valve requirements. Minimum circulating hose length shall be equal to one single joint and end connection equipped with safety clamps and chain. 6.6 Well control system Well control system to be according to clause 5.

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6.7

Workstring and BHA

6.7.1 General The workstring shall meet the operational requirements with respect to maximum anticipated pressure, temperature, torque, tension and compression. The workstring shall be inspected and a verification report shall be issued stating approved and found suitable for operation as a minimum. The tubing shall have documented tracability. A pipe tracking system may provide documented tracability. During operations the workstring limitation for over pull shall be set to 80% of manufacture's tensional yield/torsional yield of the workstring. For live well interventions, the type of connection for use in the workstring above the BPVs (check valves) to meet the requirement of minimum two independent gas tight metal- to - metal seals. The seals to withstand internal and external pressure. Drifts (2 each size), stabbing guides (2 each size), necessary x-overs and overshots for fishing the workstring components shall be included. 6.7.2 Back pressure valve (BPV) The BPVs prevents well fluids from entering into the workstring. The BPV is a barrier element and shall have a working pressure rating equal to the expected wellbore pressure. The BPVs shall be provided with seals in the bore towards the BHA and provide internal and external seal. Provisions shall be made for pumping balls through the BPVs. 6.7.3 Others All other equipment or tools in the BHA shall be qualified and designed to withstand all expected down hole forces and conditions.

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7

COILED TUBING EQUIPMENT

7.1 General A coiled tubing unit with associated systems shall be capable of handling the workstring, well conditions and other work parameters specified by the work program. This clause describes the minimum functional requirements for a coiled tubing unit with associated equipment. The well Intervention system for coiled tubing will normally consists of the following main items: · · · · · · · · · · · 7.2 7.2.1 injector head; tubing guide arch (gooseneck); injector support frame(s); injector lifting frame; power package; coiled tubing workstring (steel coiled tubing); coiled tubing reel; control cabin; data acquisition system; well control system; BHA. Coiled tubing equipment requirements Injector head

7.2.1.1 General The injector head shall have a pulling capacity of 140 % of the maximum expected load for the operation and pushing (snub) capacity of 120 % of the maximum anticipated load for the operation. 7.2.1.2 Base structure and outer frame The injector head base structure shall be designed to withstand the maximum rated pull and push loads from the injector. The base structure shall also be equipped with drip trays and drains for draining spill. The outer frame structure shall provide a base for the tubing guide arch and injector lifting sling. The outer frame structure shall be designed for lifting the total weight of the injector head including the stripper assembly, BOPs, BHA and lubricator/riser system as required for the operation. Provisions shall be made for anchoring at minimum four anchor points or alternative system with equal strength according to design criteria for the system to be used.

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7.2.1.3 Drive chain system The drive chain system shall be capable of handling the maximum weight of the workstring with minimum damage. The drive chain shall be easily replaceable in the field or be equipped with replaceable gripper blocks. 7.2.1.4 Traction system The traction system shall provide variable gripping force designed to minimise tubing damage and prevent tubing slippage. The traction force shall be adjustable from the control cabin and be capable of generating sufficient friction to push or pull the workstring at maximum rated loads without slippage or damage to the workstring. The traction system shall have a fail-safe device preventing loss of traction pressure in case of a broken hose. The traction system shall be provided with an accumulator system for each traction circuit at the injector head. Provisions shall be available to provide traction in the event of power supply failure. 7.2.1.5 Tension system The chain tension system should be adjustable from the control cabin and be capable of tensioning the injector chain sufficiently to avoid damage to bearings and the coiled tubing workstring. The tension system should be provided with an accumulator system at the injector head. 7.2.1.6 Hydraulic drive system The hydraulic drive system shall provide accurate fine movement control of the tubing in and out of hole during maximum load conditions. Provisions shall be available at the injector head, control cabin or power unit, for individual adjustment and pre-set of the operating limits for maximum pull and push forces to the injector head. These shall be protected from adjustment during normal operating conditions. The hydraulic drive system shall be capable of pushing or pulling the maximum rated load at a speed of 10 m/min. The hydraulic system shall be fail safe and stop the chains from moving if hydraulic power is lost. Charts for hydraulic pressure with corresponding load and available hydraulic pressure shall be provided. Provisions shall be made for hydraulic drive lockout when the reel brake is engaged.

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7.2.1.7 Brake system The brake system shall be capable of holding the maximum rated loads and be fail safe so that the brakes will stop the chains from moving and hold the load in case hydraulic power is lost. 7.2.1.8 Weight indicator The weight indicator system shall be capable of measuring all tensile and compressive forces (positive and negative weights) in the workstring above the stripper. Provisions shall be made for adjusting zero to compensate for the weight of the injector and BHA when required. The weight indicator system shall not be affected by conditions such as temperature changes or radio signals, etc. The injector head weight indicator system shall be equipped with a fail-safe transport-locking device, i.e. the transport locking device shall either be fully locked or fully open. Provisions shall be made for easy replacement of the weight indicator in the field and a back-up weight indicator system shall be provided. 7.2.1.9 Depth counter system At least two independent depth counters (one at the injector and one at the reel) shall be provided. The injector head should be equipped with a system for monitoring tubing and chain slippage. Provisions shall be made for installing a 3rd party depth counter system for logging services. 7.2.2 Tubing guide arch (gooseneck)

7.2.2.1 Mounting and support system Provisions shall be made for easy installation and removal of the tubing guide arch on top of the injector head. The tubing guide arch and support base shall be designed to withstand the forces imposed by the back-tension from the reel. On floating vessels the vessel movement will generate additional forces that has to be accounted for. A weak point may be built in to the tubing guide arch system for operations on floating installations. The strength of the tubing guide arch must be documented. Provisions shall be made for safe access of all the top rollers of the tubing guide arch. 7.2.2.2 Guide arch size (radius) The minimum bending radius should as a guideline be 48 times the workstring diameter. Other sizes tubing guide arch radiuses may be used if the fatigue life of the workstring is rated accordingly. Reference is made to recommendations provided in API RP 5C7 [27].

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7.2.2.3 Guiding system The tubing guide arch shall be provided with shaped rollers or a similar system for guiding the workstring into the injector. A system to prevent the workstring from sliding off sideways shall also be included. Provisions shall be made for allowing the workstring to enter or exit the tubing guide arch tangent to the curve of the tubing guide arch. Provisions shall be made for allowing the workstring to enter or exit the tubing guide arch from the angle made by spooling the workstring across the width of the reel. The tubing guide arch shall support the side loads. 7.2.3 Injector support frame The injector support frame system will normally be utilised for non-derrick operations. The injector support frame system should be designed to withstand the expected dynamic, static and bending forces it will be subjected to during normal operations. The operational limits for the system shall be clearly identified to enable operation within the design criteria. When the injector support frames are designed to transmit the load from the coiled tubing to the deck during operations, the maximum pull- and snub force capacity of the injector head shall be included in the design. Provisions should be made for moving the injector 3 ways (up and down and sideways in northsouth and east-west directions). Work platform(s) to access relevant working areas shall be provided. Provisions should be made for handling and make/brake of BHA. Provisions shall be made for anchoring at minimum four anchor points or alternative system with equal strength according to design criteria for the system to be used. Provisions shall be made for anchoring personnel safety harness at suitable areas. 7.2.4 Injector lifting frame The injector-lifting frame will normally be utilised for floating vessels and semi-submersible operations. The lifting frame shall withstand the maximum anticipated loads for the operation. It shall contain a work window in which the injector head, stripper and BOP can operate isolated from the motion of a floating vessel. The lifting frame should have an integrated hydraulic or electric winch/system for independent handling of the injector, well control equipment and other hook-up equipment. Air operated winch systems for lifting the injector head should be avoided. The winch/system shall be remotely operable from the work platform in the lifting frame and/or from the rig floor. It shall be capable of lifting the injector head with a speed that is higher than the vertical motion of the rig. The load capacity shall minimum be 30 % above the weight of the injector head assembly above the quick NORSOK standard Page 45 of 68

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connector plus the weight of the heaviest anticipated BHA and the forces required to open/unlatch the quick connector. The lifting frame should have an integrated hydraulic man rider winch that is remotely operable from the work platforms in the lifting frame and/or from the rig floor. Work platform(s) to access relevant working areas shall be provided. The lifting frame shall have a system to guide and prevent horizontal movement of the injector during operations. Provisions should be made for handling and make/brake of BHA in the lifting frame. Provisions shall be made for anchoring personnel safety harness at suitable areas. 7.3 Power package The power package shall be capable of supplying sufficient power to operate all operating systems of the coiled tubing unit on a continuous basis and at peak demand. The power package shall be designed and sound proofed in accordance with NPD Regulations and NORSOK standard S-002. Provisions shall be made for a manual ESD system that is operated locally and remotely from the control cabin. The power package shall be certified for operating in Zone II areas and in accordance with NORSOK standard Z-015. Provisions shall be available at the injector head, control cabin or power unit, for individual adjustment and pre-set of the operating limits for maximum pull and push forces to the injector head. These shall be protected from adjustment during normal operating conditions. If the power package is used for charging the accumulator system for the well control equipment, the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic circuits. Only the well control system shall be able to take hydraulic pressure from the dedicated accumulators. 7.4 Coiled tubing workstring (steel coiled tubing) The workstring shall have documented tractability, see API RP 5C7 [27] for guidance. The workstring shall have documentation of fatigue cycle history, weld location, tapers, length, property de-rating and inspection record. The workstring shall meet the operational requirements with relation to maximum calculated pressure, temperature, hydraulics, tension and compression. A tubing force calculation shall be performed for each operation. The workstring shall be leak tested and drifted prior to each mobilisation. Workstring with e-line installed may be drifted if applicable. NORSOK standard Page 46 of 68

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The workstring shall be quality checked (continuously inspected) and a verification report shall be issued stating the status and suitability for the upcoming operation(s) prior to each mobilisation. The tubing quality check shall as a minimum include wall thickness, surface condition, outside diameter, corrosion, ovality and ballooning. The workstring should be inspected continuously during the operation to maintain a real time string condition record. The inspection prior to mobilisation may be omitted if the workstring is continuously inspected during the operation. The workstring shall never exceed more than 80 % of manufacturer's specified yield strength as new. Any de-rating shall be according to recognised standards, e.g. API RP 5 C7 [27] A system for maintenance and preservation (internal and external) of the workstring shall be in place. 7.5 Coiled tubing reel The coiled tubing reel shall be equipped with drip tray(s) and drains. Access and work platforms shall be provided at suitable areas for normal operations. The drive system shall be capable of driving the reel faster than the maximum (operating) speed of the injector head. It shall provide the required tension necessary to bend the workstring over the guide arch and onto the reel and provide sufficient torque to accelerate the reel drum from stationary to maximum (operating) speed with the reel drum fully loaded of workstring filled with fluid. The reel drive system shall be variable, adjusted and controlled from the control cabin. The coiled tubing reel core diameter shall, as a minimum be 48 times the coiled tubing diameter. A smaller core diameter can be utilised providing the fatigue life of the workstring is de-rated accordingly. The level wind system shall be designed to withstand the bending and side load forces from the workstring. A guiding system with an override function shall be provided for proper spooling of the workstring on and off the reel drum. The level wind system should be equipped with a remotely operated tubing clamp. The coiled tubing reel shall have a reel brake system that automatically engages with loss of hydraulic power. This system must have provisions for manual override when operating on floating vessels/semi-submersibles. The coiled tubing reel shall have a brake system that is designed to prevent operation of the injector head when the coiled tubing reel brake system is engaged. An additional brake system should be installed and to be activated in the event of drive gear or chain failure. This could either be a capillary brake system or an additional drive motor with internal brake.

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The coiled tubing reel shall be equipped with a depth counter. The coiled tubing reel shall have a pig and ball launcher system by-pass and an isolation valve between the launcher and workstring end termination. The launcher system shall have an internal diameter equal to or greater than the internal diameter of the workstring. The workstring reel end termination shall be a qualified connection. The coiled tubing reel shall be provided with additional piping as follows: Inlet and isolation valves, swivel joint, pressure sensing device and connection point for pressure relief valve. 7.6 Control cabin The control cabin shall have an ergonomic layout and be designed according to NPD Regulations and NORSOK standard S-002. The control cabin shall facilitate all necessary controls and monitoring equipment to operate the complete coiled tubing unit. The controls and monitoring equipment shall as a minimum include the following: a) injector head; · in hole- and out of hole control; · traction control; · tension control; · high/low gear or displacement control (when applicable); · emergency traction control; · injector drive pressure supply pressure; · in hole- and out of hole pressure; · traction pressures; · tension pressure; · depth counter; · weight indicator (positive and negative weight); · wellhead pressure. b) coiled tubing reel; · reel forward and reverse control; · reel back tension control; · level wind override (right and left) control; · level wind rise and lower control; · reel brake control; · circulating pressure; · reel back tension pressure; · reel brake pressure. c) power package; · normal stop control; · ESD control; NORSOK standard Page 48 of 68

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· ·

engine throttle control; priority supply pressure.

d) stripper; · upper and lower stripper control; · upper and lower stripper pressure. e) BOP. · shear and seal ram control; · pipe ram control; · slip ram control; · BOP accumulator pressure supply; · BOP control pressure; · BOP fluid volume control (flow meter) (see also well control system clause 5). Provisions shall be available at the injector head, control cabin or power unit, for individual adjustment and pre-set of the operating limits for maximum pull and push forces to the injector head. These shall be protected from adjustment during normal operating conditions. 7.7 Data acquisition system The coiled tubing unit shall be equipped with a data acquisition system to display and record operational parameters. The data-sampling rate shall be sufficient to record relevant variations in the displayed and recorded parameters. A system for analyzing the recorded data shall be available at the location. The following parameters shall as a minimum be displayed in the control cabin: · · · · · · injector load (positive and negative); injector hydraulic system pressure; wellhead pressure; circulating pressure; depth; running and pulling speed.

The following parameters shall, as a minimum, be recorded: · · · · · · · · · time and date; injector load (positive and negative); injector hydraulic system pressure; wellhead pressure; circulating pressure; depth; running and pulling speed; pump rate (unless recorded at the pump unit); required data for updating the workstring fatigue model.

7.8 Well control system Well control system shall be in accordance with clause 5. NORSOK standard Page 49 of 68

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7.9

BHA

7.9.1 General The BHA shall be designed to withstand all expected downhole forces and conditions. The BHA shall as a minimum consist of the following from top: · · end-connector; dual check valve (BPV).

NOTE The dual check valve can be replaced with a tested plug.

7.9.2 End connector The end-connector provides the interface between the workstring and the rest of the BHA. It is a barrier element and shall have a working pressure rating equal to the maximum operating pressure. The end connector shall be provided with dual seals on both sides and provide an internal and external seal. The end-connector shall be qualified to withstand all forces (tension, compression and torsion) that it may be subjected to from the BHA or the workstring. 7.9.3 Dual check valve (BPV) The dual check valve prevents well fluids from entering into the workstring. It is a barrier element and shall have a working pressure rating equal to the maximum operating pressure. The dual check valve shall be provided with dual seals in the bore and towards the end-connector and provide internal and external seal. Provisions shall be made for pumping balls through the dual check valve. 7.9.4 Others All other equipment or tools in the BHA shall be qualified and designed to withstand all expected down hole forces and conditions.

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8

WIRELINE EQUIPMENT

8.1 General The wireline unit with associated systems shall be capable of handling the tool string, well conditions and other work parameters specified by the work program. This section clause describes the minimum functional requirements for a wireline unit with associated equipment. The well intervention system for wireline will normally consists of the following main items: · · · · · · · · · · · · 8.2 wireline unit; control cabin; data acquisitions; clamps/sheaves and hay pulley; power package; pressure test pump; wellhead pump; well control system; logging container (for logging and well tractor); wireline mast (crane); transport and storage racks for wireline equipment; slick, braided and electrical line down hole tools. Wireline equipment requirements

8.2.1 Wireline winch unit requirements The wireline winch unit shall have a minimum recommended drum capacity of 1,5 times expected operational depth or minimum 5 000 m (16 400 ft) and a minimum pulling capacity at top of drum flange as follows: · · · Slickline: Braided/electric cable: Braided/electric cable: 2,7 mm (0,108 in); 3,2 mm (0,125 in) 80 % of breaking strength 4,8 mm (0,188 in); 5,6 mm (0,219 in) 80 % of breaking strength 7,9 mm (0,313 in); 11,9 mm (0,469 in); 12,7 mm (0,500 in) 47,1 kN (10 580 lbsf)

The brake system shall have a minimum capacity equal to drum pulling capacities. The drive system shall be capable of holding the load sufficient in neutral position until brake is activated. The unit shall be equipped with a spooling device or back-up drum for slickline. 8.2.2 Jarring requirements · Slickline drum with 1,96 kN (440 lbsf) tension: Cable speed after 4 m (13,1 ft) acceleration: 3 m/s (9,8 ft/s) · Braided line drum with 9,81 kN (2 200 lbsf) tension: Cable speed after 4 m (13,1 ft) acceleration: 1 m/s (3,3 ft/s)

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8.2.3

Speed range requirements

8.2.3.1 Slick line · Low speed: 500 m/h (1 600 ft/h) constant speed at outer diameter of drum. · High speed: 10 000 m/hr (33 000 ft/h) constant speed at outer diameter of drum. Logging speed range requirements - all size logging cables: · Low speed: 90 m/hr (300 ft/h) constant speed at outer diameter of drum. · High speed: 3 000 m/h (10 000 ft/h) constant speed at outer diameter of drum. 8.2.3.2 Fishing/braided line · Low speed: 300 m/h (1 000 ft/h) constant speed at outer diameter of drum. · High speed: 5 000 m/h (16 500 ft/h) constant speed at outer diameter of drum. 8.3 Control cabin The control cabin shall have an ergonomic layout and be designed according to NPD Regulations. The cabin shall have protection over windows facing upwards and equipped with splint safe windows. There shall be minimum one extra seat The control cabin shall facilitate all necessary controls and monitoring equipment to operate the complete wireline unit. The controls and monitoring equipment shall as a minimum include and be located such that operator at all times can read the following: a) controls; · depth counter; · weight indicator; · level wind control; · reel brake; · reel forward /reverse; · cable speed when required for the operation. b) BOP. · shear seal ram; · wireline rams; · BOP control pressure; · flow monitoring; · BOP accumulator pressure. 8.4 Data acquisition A data acquisition system should monitor and record the following parameters: · · · · depth; tension; cable speed; tubing pressure.

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Depth indicator system: Weight indicator system:

Calibration range of +/-1,5 m for a depth of 5 000 m (+/- 4,9 ft for depth of 16 400 ft) Calibration accuracy of 0,5 % on gauge.

Additional for logging unit: Prepared for slip ring collector. Automatic overpull shut-down system. 8.5 Clamps/sheaves and hay pulleys

8.5.1 Sheaves and hay pulleys Pulleys are for wireline operations only, and shall be marked accordingly. To be tested to 2 x maximum line pull, and documented on a load test formulary. Load limit requirement for sheaves and hay pulley: maximum line pull x 2 x safety factor. Maximum line pull not to exceed 80% of the wire breaking strength and minimum safety factor: 2. All locking devices shall have a double safety feature. The recommended minimum sheave diameter shall be as follows: · · · · · · Slickline, 2,7 mm (0,108 in) Slickline, 3,2 mm (0,125 in) Braided/electric cable, 4,8 mm (3/16 in), 5,6 mm (7/32 in) Braided/electric cable, 7,9 mm (5/16 in) Electric cable, 11,9 mm (15/32 in) Electric cable, 12,7 mm (1/2 in) 0,30 m to 0,36 m (12 in to14 in) 0,30 m to 0,36 m (12 in to14 in) 0,30 m to 0,36 m (12 in to14 in) 0,41 m to 0,49 m (16 in to19 in) 0,51 m to 0,61 m (20 in to 24 in) 0,56 m to 0,66 m (22 in to 26 in)

8.5.2 Clamps for wireline Wireline clamps for securing and pulling during normal wireline operations. This is considered to be a hand tool, not certified for lifting. Fishing clamps for securing and pulling the wireline during fishing operations. The clamps shall be tested to line breaking strength, and documented on a load test formulary. The following requirements apply: · · · Load limit requirement: Line breaking strength x safety factor; minimum safety factor: 2; all locking devices shall have a double safety feature.

8.6 Power package The power package shall be capable of supplying sufficient power to operate all operating systems of the wireline unit on a continuous basis and at peak demand. Provisions shall be made for a manual ESD system that is operated locally and remotely from the control cabin.

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The power package shall be certified for operating in Zone II areas and in accordance with NORSOK standard Z-015. If the power package is used for charging the accumulator system for the well control equipment, the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic circuits and only the well control system shall be able to take hydraulic pressure from the dedicated accumulators. 8.7 Pressure test pump The test pump shall have a pressure recorder included on the pump and equipped with a liquid tank. The pump shall be rated to following working pressures as required for the operation: Pump pressure 34,5 MPa 69,0 MPa (5 000 psi) (10 000 psi) 3 l/min 1,0 l/min

6,9 MPa (1 000 psi) Pump rate 30 l/min

103,4 MPa (15 000 psi) 0,5 l/min

8.8 Wellhead pump The wellhead pump shall have minimum two separate pumps included in the skid. Check valve shall be included to prevent well fluid to enter pump reservoir. The pump shall be rated to the following working pressures as required for the operation: 34,4 MPa (5 000 psi)/ 69,0 MPa (10 000 psi)/ 103,4 MPa (15 000 psi) 8.9 Well control system Well control system to be according to clause 5. 8.10 Logging container (for logging and well tractor) Special container for control of tools and data acquisition. Inventory and requirements as specific for the actual operation. 8.11 Wireline mast (crane) Special lifting arrangement for lifting and securing the wireline lubricator stack during wireline operations should be included. The design shall be according to platform and specific operational requirements, and as per regulations. Man rider winch should be included in the design. 8.12 Transport and storage racks for wireline equipment Special inventory for securing the equipment inside during transportation and storage shall be supplied. The racks shall have suitable protection at bottom for preventing loose objects falling out. The racks shall be designed for easy and safe loading and unloading, with required securing devices.

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8.13 Slick, braided and electrical line requirements The slick line, braided line and electric line shall have a periodic wire inspection, preventive maintenance program and be well conditions compatible. Wire loaded to yield strength shall be replaced immediately Wire log with relevant data shall be kept. 8.14 Down hole tools requirements The following requirements apply: a) wireline tool string components; · · · · fishing neck on all components; well condition compatible; there shall be fishing tools available on the location; Rockwell HRC 30-36 on low alloyed steel.

b) running and pulling tool components; · · · fishing neck on all components; well condition compatible; Rockwell HRC 30-36 on low alloyed steel.

c) fishing tool components; · · · · fishing neck on all components; well condition compatible; rated for the exposed loads; Rockwell HRC 30-36 on low alloyed steel.

d) explosive tool components; · · · · well condition compatible; fishing tools shall be available on location; pressure relief port for bleeding off trapped pressure; firing system independent of radio silence.

e) logging tools components. · · well conditions compatible; fishing tools shall be available on location.

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9

DOCUMENTATION

9.1 General The following equipment is considered to be comprised by this category and shall be presented according to NS 5820: · snubbing equipment; · coiled tubing equipment; · wireline equipment. Requirements relating to technical documentation the provision stipulate that documentation necessary to ensure safe operations shall be available. This requirement shall be applicable to planning, engineering, construction, installation, operation and maintenance of well service equipment and facilities. Further elaboration is provided with this provision by requiring that it shall be possible for equipment considered to be of major significance to the safety of personnel, well integrity and installations to be separately documented. The following equipment is comprised by this category: a) b) c) d) e) f) g) h) i) j) k) l) m) n) o) p) q) r) s) substructures; masts with bolts and shackles; hoisting machinery with complete associated equipment; running tools and workstring (tubular) and BHA; BOP with choke manifold; wellhead arrangement; hydraulic and flange and clamp connection unit to wellhead; lifting equipment/cranes; deadline anchor for the wire rope of the draw-work; wire rope of the draw-work; testing equipment with piping arrangement; high pressure piping systems and pressure vessels; wire line masts and units; coiled tubing equipment; snubbing equipment; pipehandling equipment; pumping equipment; power generation packages; BOP control systems.

9.1.1 Verification and certification The provision entails that the need for documentation shall be assessed during the various phases of the activity concerned. The provision does not specify who is required to prepare or to keep on file the necessary documentation. The documentation system of the operator may make use of documentation and documentation systems already established with contractors, sub-contractors or suppliers. In accordance with current practice the documentation applicable to the above shall as a minimum include

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a) b) c) d) e) f) g) h) i) j) k) l)

name of equipment; production number; name of manufacturer and supplier; description of design and manufacture, indicating safety factors; verification of design and strength control; material certificates and confirmation as to where materials have been used; welding procedure specifications and qualification; confirmations with that manufacture, inspection and final control have been subjected to independent verification; report from testing including testing conditions, and information on how testing has been carried out; independent verification of design assumptions with regard to strength; supplier's operation and maintenance specifications, with indication of operational criteria and limitations; marking of equipment.

Updating of items in the case of modification of equipment with regard to verification of equipment, which is lacking in documentation, adequate deviation procedure will include, but not be limited to a) b) c) d) analysis of elements (chemical composition); hardness measurements; non-destructive examination (magnetic particle inspection, replica etc.); confirmation from manufacturer that the equipment is produced in accordance with recognized standards; e) equipment history. 9.1.2 Technical requirements Examples of parameters considered to be relevant in order to verify that the equipment is of required suitability may be a) b) c) d) e) f) g) h) i) j) k) capacity (e.g.lifting capacity); pressure; volume; temperature; exposure time; environmental loads; tensile loads; corrosion; erosion; thickness measurements; transportation loads and requirements.

As stipulated by this provision, equipment shall be designed, manufactured, installed, operated and maintained in a way that ensures its ability to resist the most extreme loads that it may become subjected to during drilling and well operations. In connection with operations in cold climatic conditions, the requirements to design temperature must be considered in relation to the possibility of maintaining a controlled operation temperature at all times.

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9.2 9.2.1

Specific well intervention requirements Downhole tools and strings for snubbing, coiled tubing and wireline

The manufacture's quality control certificate and documentation shall include a) b) c) d) e) name of equipment; production number; name of manufacturer and supplier; description of design and manufacture, indicating safety factor used; verification of design assumptions with regard to strength, carried out by an independent survey institution;

NOTE Depending on organisational independence, this function may be taken care of by the manufacturer.

f) material certificates and confirmation as to where materials have been used; g) statement of manufacture and inspection signed by manufacturer and surveyor/surveying firm or body. Additional documentation for snubbing, coiled tubing and wireline should include a) b) c) d) e) f) g) h) i) j) receiving - quality control of the tool; marking of equipment; updating of items in the case of modification of equipment; quality audit of the maker's manufacturing process; inspection report; drawings showing internal parts and functions, overall length, maximum outside diameter, minimum internal diameter and weight; tool description, function, maximum and minimum parameters; strength calculations indicating safety margins; operational manual/operating procedures; function and operational testing;

NOTE This does not replace acceptance test offshore before a job.

k) complete BHA drawings showing: total length, maximum outside diameter, minimum internal diameter, weight, and position of tools and threads; l) fishing data. 9.2.2 Coiled tubing string The manufacture's quality control certificate and documentation shall include a) b) c) d) name of equipment; production number; name of manufacturer and supplier; description of design and manufacture, including safety factors used. Verification of design assumptions with regard to strength, carried out by an independent survey institution. Depending on organisational independence, this function may be taken care of by the manufacturer; e) supplier's operation and maintenance specifications, with indication of operational criteria and limitations; f) material certificates, including chemical analysis, mechanical strengths (hardness, tensile and yield) and physical dimensions;

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g) inspection report, including non-destructive inspection of coiled tubing body and welds, locations of all imperfections and details of drift ball test; h) report from testing including testing conditions, and information on how testing has been carried out. Minimum required is hydrostatic test report; i) repair record; j) statement of manufacture and inspection signed by manufacturer and surveyor/surveying firm and body; k) weld procedure qualifications for welds, including x-rays; l) weld log, including bias weld and butt weld locations; m) welding procedure specifications and inspection/verification specifications; n) drying procedure used. Additional documentation should include a) log of tubing repairs, including: location of manufacturer's welds, location of section welds, tubing cut off, added and re-used and reason for repair; b) log of outside diameter, ovality and wall thickness testing; c) estimated cumulative damage and remaining life time, including evaluation and location of butt and field welds; d) operational limits for outside diameter and wall thickness; e) history log of all previous jobs, including parameters influencing life time; f) documentation on receiving-quality control of the coiled tubing; g) marking of equipment; h) updating of items in the case of modification of equipment; i) quality audit of the manufacturing process; j) pre-job inspection and testing documentation; k) insulation (merging) test record for coiled tubing with e-line installed. 9.2.3 Wire and cable The manufacture's quality control certificate and documentation shall include a) b) c) d) e) f) name of equipment; production number; name of manufacturer and supplier; description of design and manufacture, indicating safety factor used; material certificates including chemical analysis and mechanical strengths; report from testing including testing conditions, and information on how testing has been carried out; g) quality audit of the maker's manufacturing process; h) inspection reports; i) physical dimensions.

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ANNEX A (informative) DATA SHEET SNUBBING EQUIPMENT

Operator: Project: Document no: Date and revision: System/equipment NORSOK classification selected General snubbing Module size maximum LxWxH Module weight maximum MT (Megatonnes) Derrick/mast /hoisting structure/hoisting equipment minimum static capacity: Rotary table loading NORSOK I3 NORSOK II1 D-002 Rev. 1 Sep. 2000

Your choice

1510 kN (340 klbf) 1510 kN (340 klbf)

2930 kN (658 klbf) 2930 kN (658 klbf)

Structures snubbing Derrick/mast /hoisting structure and hoisting equipment minimum capacity Rotary table load rating BOP handling equipment ­ maximum load rating Pad eyes / hang off points for travelling assemblies, minimum safe working load capacity Pad eyes/hang off points for rig tongs, work winches etc., minimum safe working load capacity Hoisting and rotary systems Minimum lifting capacity Lifting speed ­ minimum Topdrive ­ minimum load rating Topdrive maximum at max continuous torque 3

1510 kN (340 klbf) 1510 kN (340 klbf) kN (klb) 49 kN (11,0 klbf) 24 kN (5,4 klbf)

2930 kN (658 klbf) 2930 kN (658 klbf) kN (klb) 49 kN (11,0 klbf) 24 kN (5,4 klbf)

1510 kN (340 klbf) 1 m/s (ft/s) 1510 kN (340 klbf) 160 rpm

2930 kN (658 klbf) 1 m/s (ft/s) 2930 kN (658 klbf) 160 rpm

-Ref: D-001 chapter 4.4

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

minimum Topdrive maximum continuos torque ­ minimum Topdrive breakout torque - minimum Topdrive makeup torque ­ minimum Topdrive/rotary speed at maximum continuous torque Topdrive/rotary minimum speed at maximum torque Topdrive/swivel maximum speed Topdrive/swivel minimum pressure rating Rotary table ­ minimum internal diameter Rotary table ­ minimum load rating Rotary table - minimum Rotary table - torque, minimum Lifting height ­ to be defined. System/equipment

9 kNm (6,6 klb·ft) kNm (klb·ft) 80 kNm (59,0 klb·ft) 120 rpm 10 rpm 160 rpm 34,5 MPa (5 000 psi) 0,345 m (1,13 ft) 1510 kN (340 klbf) 160 rpm 9 Nm (6,6 lbf·ft) m (ft) NORSOK I

29 kNm (21,4 klb·ft) kNm (klb·ft) 80 kNm (59,0 klb·ft) 160 rpm 10 rpm 220 rpm 51,7 MPa (7 500 psi) 0,345 m (1,13 ft) 2930 kN (658 klbf) 220 rpm 29 Nm (21,4 lbf·ft) m (ft) NORSOK II

Your choice

Pipehandling systems Vertical pipehandling system (s): Lifting capacity - minimum Minimum average drillpipe tripping speed Horisontal pipehandling system(s) Tubular range ­ handling capacity 3 kN (674 lbf) 45 joints/h 73,0 mm to 177,8 mm 2,875 in to 7 in 10 kN (2,2 klbf) 25 35 45 100 kNm (73,8 klbf·ft) 3 kN (674 lbf) 45 joints/h 73,0 mm to 330,3 mm 2,875 in to ­ 13,375 in 30 kN (6,7 klbf) 25 35 45 100 kNm (73,8 klbf·ft)

Lifting capacity - minimum Handling capacity ­ tubular per, minimum: 330,3 mm (13 3/8 in) 244,5 mm (9 5/8 in) 177,8 mm (7 in) or smaller Iron roughneck ­ break-out torque - minimum Tubing tongs ­ break ­ out torque - minimum NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

Associated equipment Minimum capacities unless otherwise specified: Work winches Manrider winches

30 kN (6,7 klbf) 1,5 kN (337 lbf)

30 kN (6,7 klbf) 1,5 kN (337 lbf)

High pressure circulation system (s) Maximum operating pressure

34,5 MPa to 69,0 MPa (5 000 psi to 10 000 psi)

34,5 MPa to 69,0 MPa (5 000 psi to 10 000 psi)

Well control systems Well control equipment pressure rating minimum BOP internal diameter - optional No. of rams - minimum Ram sizes - optional No. of annular preventer(s) - minimum Annular preventer(s) internal diameter - as for BOP Annular preventer pressure rating - minimum No. of choke/kill outlets - minimum Choke/kill valves pressure rating - minimum

69,0 MPa (10 000 psi) 179,4 mm (7 7,063 in) 5 1 179,4 mm (7 7,063 in) 69,0 MPa (10 000 psi) 2 69,0 MPa (10 000 psi)

69,0 MPa (10 000 psi) 179,4 mm (7 7,063 in) 5 1 179,4 mm (7 7,063 in) 69,0 MPa (10 000 psi) 2 69,0 MPa (10 000 psi)

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

ANNEX B (informative) SAFETY HEAD REQUIREMENTS, COILED TUBING AND SNUBBING OPERATIONS

The requirements for the safety head are to cut the actual work string in use including any wire, tube and cable inside, and provide sealing in the bore after shearing with maximum working pressure inside the safety head body. Additional equipment that the safety head should be capable to cut and provide sealing effect after shearing, are listed below: Item 1 2 3 4 5 6 Description 2,7 mm (0,108 in) slick line without tension 2,7 mm (0,108 in) slick line 11,1 mm (0,438 in) el. cable w/ 2,2 kN (500 lbf) tension 11,1 mm (0,438 in), 5 cores el. cable without tension 31,8 mm (1,25 in), 2,8 mm (0,109 in) wall thickness coiled tubing Heavy wall 4,8 mm (0,188 in), wall thickness 38,1 mm (1,5 in), 44,5 mm (1,75 in) and 50,8 mm (2,00 in) CT coiled tubing with 11,1 mm (7/16 in) cable inside. Heavy wall 4,8 mm (0,188 in) wall thickness 60,3 mm (2 3/8 in) and 73,0 mm (2 7/8 in) coiled tubing with 11,1 mm (7/16 in) cable inside. 50,8 mm (2 in) sinker bar, ANSI 4230 steel quality 88,9 mm (3,5 in) Drillpipe S-135, 226,2 N/m (15,5 lbf/ft) 101,6 mm (4 in) tubing 13 chrome L-80 Each 1 ea. strand 10 ea. strands 1 ea. strand 10 strands 10-12 ea. parallel strings 3 parallel strings Your choice

7

2ea. parallel strings

8 9 10

1 ea. 1 ea. 1 ea.

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000 1 ea. 1 ea. 1 ea.

11 12 13

114,3 mm (4,5 in) perforating gun 114,3 mm (4,5 in) 184,0 N/m (12,6 lbf/ft) tubing 117,5 mm (4 5/8 in) gravel pack screen w/ 60,3 mm (2 3/8 in) washpipe inside

NOTE Ref. item 6 and 7, the requirements should be performed with the coiled tubing in compression, neutral and in tension equal to 20,7 MPa (3000 psi) wellbore pressure.

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

ANNEX C (informative) SNUBBING AND COILED TUBING WELL CONTROL SYSTEM RIG UP

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

ANNEX D (informative) WIRELINE WELL CONTROL SYSTEM RIG UP

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

BIBLIOGRAPHY

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [12] [13] [14] [15] [15] [17] [18] [19] [20] [21] [22] [24] [25] [26] [27] [28] [29] [30] [31] [39] [40] [41] [42] [43] [44] [44] NORSOK C-001, Living quarters area. NORSOK C-002, Architectural components and requirements. NORSOK D-010, Drilling & Well operations. NORSOK D-CR-003, Surface Christmas Tree. NORSOK D-SR-007, Well testing system. NORSOK E-001, Electrical systems. NORSOK E-002, Adjustable speed motor drives. NORSOK I-001, Field Instrumentation, 1. NORSOK I-002, Safety and automation systems (SAS). NORSOK I-SR-001, Wellhead Control and Hydraulic Power. NORSOK L-001, Piping and valves. NORSOK M-001, Material Selection. NORSOK M-702, Drill string components. NORSOK S-005, Machinery ­ working environment analysis and documentation. NORSOK Z-008, Criticality Classification Method. NORSOK Z-016, Management and Regularity Technology. ISO 1000, SI units and recommendations for the use of their multiples of certain other units. ISO 9000, Quality management and quality assurance standards. ISO 10400, Formulae and calculation for casing, tubing, drill pipe and line pipe properties. ISO 10407, Petroleum and Natural Gas Industries ­ Drilling and Production Equipment ­ Drill Stem Design and Operating Limits . ISO 10417, Petroleum and Natural Gas Industries ­ Subsurface Safety Valve Systems ­ Design Installation, Operation and Repair. ISO 10432, Petroleum and Natural Gas Industries ­ Subsurface Safety Equipment ­ Specification. ISO 10433, Petroleum and Natural Gas Industries ­ Drilling and Production Equipment ­ Specification for Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service. ANSI/ASME B31.3, Process Piping. API RP 5C7, Coiled Tubing Operations in Oil and Gas Well Service. API RP 7G, Drill Stem Design and Operating Limits. API RP 8B, Recommended Practice for Procedures for Inspection, Maintenance, Repair and Remanufacture of Hoisting equipment. API RP 16E, Design of control systems for drilling well control equipment. API RP 53, Blow-out Prevention Equipment Systems for Drilling Wells. ASTM A 370, Test methods and definitions for mechanical testing of steel products. ASTM A 450, Specification for general requirements for carbon, ferritic alloy, and austenitic alloy steel tubes. ASTM E 18, Test methods for rockwell hardness and rockwell superficial hardness of metallic materials. ASTM E 94, Guide for radiographic testing. ASTM E 140-88, Hardness conversion tables for metals. BS 5500, Pressure vessels, accumulators and piping systems. BS 6755: Part 1: ISO 5208 Specification for production pressure testing requirements

NORSOK standard

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System requirements well intervention equipment

D-002 Rev. 1, October 2000

[45] ISO 5208, Industrial valves ­ Pressure testing of valves. [46] TBK 1-2, General rules for pressure vessels.

NORSOK standard

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