API Norsok Standardise for Well Intervention Equipment

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NORSOK STANDARD

SYSTEM REQUIREMENTS WELL INTERVENTION

EQUIPMENT

D-002Rev. 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 theadministration 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

NORSOK standard Page 1 of 68

CONTENTS

FOREWORD 2

INTRODUCTION 2

1 SCOPE 52 NORMATIVE REFERENCES 5

3 TERMS, DEFINITIONS AND ABBREVIATIONS 7

3.1 Definitions 7

3.2 Abbreviations 7

4 GENERAL REQUIREMENTS 8

4.1 General 8

4.2 Design principles 8

4.3 Design principles references and standards 8

4.4 Verification, testing and marking 13

4.5 LCC and regularity 15

4.6 Process and ambient conditions 15

4.7 Layout and working environment requirements 15

4.8 Special requirements for skid base structures 16

4.9 Utility interfaces 16

4.10 Operational requirement 17

5 WELL INTERVENTION WELL CONTROL SYSTEM 18

5.1 Equipment configuration 18

5.2 Equipment requirements 21

5.3 Control system 30

6 SNUBBING EQUIPMENT 35

6.1 General 35

6.2 Snubbing equipment requirements 36

6.3 Data acquisition system 39

6.4 Power package 40

6.5 Circulating system 40

6.6 Well control system 40

6.7 Workstring and BHA 41

7 COILED TUBING EQUIPMENT 42

7.1 General 427.2 Coiled tubing equipment requirements 42


7.4 Coiled tubing workstring (steel coiled tubing) 46

7.5 Coiled tubing reel 47

7.6 Control cabin 48

7.7 Data acquisition system 49

7.8 Well control system 49

7.9 BHA 50

8 WIRELINE EQUIPMENT 51

8.1 General 518.2 Wireline equipment requirements 51






8.3 Control cabin 52

8.4 Data acquisition 52

8.5 Clamps/sheaves and hay pulleys 53


8.7 Pressure test pump 54

8.8 Wellhead pump 548.9 Well control system 54

8.10 Logging container (for logging and well tractor) 54

8.11 Wireline mast (crane) 54

8.12 Transport and storage racks for wireline equipment 54

8.13 Slick, braided and electrical line requirements 55

8.14 Down hole tools requirements 55

9 DOCUMENTATION 56

9.1 General 56

9.2 Specific well intervention requirements 58

ANNEX A 60

(informative) 60

DATA SHEET SNUBBING EQUIPMENT 60

ANNEX B 63

(informative) 63

SAFETY HEAD REQUIREMENTS, COILED TUBING AND SNUBBING OPERATIONS 63

ANNEX C 65

(informative) 65

SNUBBING AND COILED TUBING WELL CONTROL SYSTEM RIG UP 65

ANNEX D 66

(informative) 66

WIRELINE WELL CONTROL SYSTEM RIG UP 66

BIBLIOGRAPHY 67






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.






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 Coiled tubing equipment, revision 1 – January 1996

• D-SR-006 Snubbing equipment, revision 1 – January 1996

• D-SR-008 Wireline equipment, revision 1 – October 1996






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 Petroleum and Natural Gas Industries – Drilling and Production Equipment –

Specification for Valves, Wellhead and Christmas Tree Equipment

ISO 10424 Petroleum and Natural Gas Industries – Drilling and production equipment –

Rotary drilling equipment


Specification for drill through equipment


Hoisting equipmentISO 13626 Petroleum and Natural Gas Industries – Drilling and production equipment –

Drilling and well servicing structures – Specification


Drilling equipment

API Spec 4F Drilling and well servicing structures

API Spec 5CT Specification for Casing and Tubing (U.S. Customary Units)

API Spec 6A Specification for Wellhead and Christmas Tree Equipment

API Spec 7 Specification for Rotary Drill Stem Elements (replace with ISO 10424 when

issued)

API Spec 7K Specification for Drilling Equipment






API Spec 8C Specification for Drilling and Production Hoisting Equipment (PSL 1 and PSL

2), (replace with ISO 13535 when issued)

API Spec 9A Specification for Wire Rope

API Spec 16A Specification for Drill Through Equipment, (replace with ISO 13533 when

issued)

API Spec 16C Choke and kill systemAPI Spec 16D 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 plainBS 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, Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment.

NACE-TM-0177 Labory Testing of Metals Resistance to Sulfide Stress Cracking and Stress

Corrosion Cracking in H2S Environment. Item no 21213

ASME VIII Div. 1 and Div. 2, Pressure vessel code

NS 3472 Steel structures – Design rules NS 5820, Suppliers documentation of equipment.

DNV Offshore standard OS-E101 Drilling Plant

DNV Lifting Appliance

ANSI/ASME B31.3 Process Piping

ANSI/AWS D1.1 Structural Welding Code - Steel

ASTM-E466-82 Standard Practice for Conduction Force Controlled Constant Amplitude AxialFatigue Tests of Metallic Materials

ASTM-E468-90 Standard Practice for Presentation of Constant Amplitude Fatigue Test Results

for Metallic Materials

ASTM-E739-91 Standard Practice for Statistical Analysis of Linear or Linearized Stress-Life

(S-N) and Strain-Life (e-N) Fatigue Data

ASTM-A450 Standard Specification for General Requirements for Carbon, Ferritic Alloy,

and Austenitic Alloy Steel Tubes

IEC 60068 Environmental testing

FEA-M Forskrifer for elektriske anlegg. Maritime installasjoner. Norsk Vassdrags ogEnergiverk (NVE).






3 TERMS, DEFINITIONS AND ABBREVIATIONS

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

3.1 Definitions

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: Verbal form used to indicate requirements to be followed in order to conform

to the standard.

Should: 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.

May: Verbal form used to indicate that among several possibilities, one is suitable,

without mentioning or excluding others, but not necessarily required.

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 3rd

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 valveCE 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 supplyANSI American National Standards Institute






ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

BS British Standards

DNV Det Norske Veritas

NACE National Association of Corrosion Engineers

NS Norsk StandardFEA-M 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.






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 Other

Substructures /

masts / gin pole

N-001 (13626) 4F NS-3472 Steel structures – Design rules

BS-7072 Code of practice for inspection and

repair of offshore containers


DNV Offshore standard OS-E101 Drilling

Plant

Pipe handling

system;


Plant

Jack/pulling unit; (13535) 8C DNV Offshore standard OS-E101 Drilling

PlantRotary / power

swivel

(13535) 8C DNV Offshore standard OS-E101 Drilling

Plant

Work window N-001 (13626) 4F NS-3472


Plant

Slip bowls /

carriers

(13535)

(14693)

8 C

7K


Plant

Make up / brake

out tongs

(14693) 7K DNV Offshore standard OS-E101 Drilling

Plant

Winch package /hoisting equipment 9A DNV Offshore standard OS-E101 DrillingPlant

Circulating swivel (10423)

(15156)

6A NACE-MR-0175


Plant

Kelly valves (13535)

(10424)

(15156)

8C

7

NACE-MR-0175


Plant

Workstring (10424)

(11960)

7

5CT

BHA 9001:

Chapter

4.5 4.7

& 4.16

BS 308: Parts 1, 2, & 3.

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






Table 2 Coiled Tubing

Norsok ISO API Other

Substructures N-001 NS-3472

BS449

BS7072



Plant

Injector head w/

Tubing guide arch

(gooseneck),

Injector support

frame(s) & Injector

lifting frame

N-001

NS-3472

BS-449

BS7072

ANSI B31.3

AWS D1.1

DNV Lifting ApplianceDNV Offshore standard OS-E101 Drilling

Plant

Coiled tubing

workstring (steel

coiled tubing)

(11960)

(15156)

9001

5CT,

5C7

NACE-TM-0177

NACE- MR- 0175

ASTM-E466-82

ASTM-E468-90

ASTM-E739-91

ASTM-A450

ASME- sec. VIII Div.1&2

Coiled tubing reel Z-015 NS-3472

BS449

BS7072



Plant

BHA 9001:,

Chapter

4.5 4.74.16

BS 308: Parts 1, 2, & 3.

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






Table 3 Wireline


Substructures N-001 DNV Offshore standard OS-E101 Drilling

Plant

Wireline unit Z-015 DNV Offshore standard OS-E101 Drilling

Plant

Clamps/sheaves

and hay pulley;


Plant

Pressure test pump Z-015 DNV Offshore standard OS-E101 Drilling

Plant

Wellhead pump Z-015 DNV Offshore standard OS-E101 Drilling

Plant

Wireline mast

(crane)

(13626) 4F

Slick, braided andelectrical line down

hole tools

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

Table 4 Snubbing Coiled Tubing and Wireline – General

Equipment Norsok ISO API Other

Operator cabin w/

Control system &

Data acquisition

system

H-001

Z-015

9241 IEC60068

Hydraulic power

pack

Z-015

Z-010

Circulating system (10423)

(15156)

6A

NACE-MR-0175


Plant

Chiksan / stand

pipe

(10423)

(15156)

6A

NACE-MR-0175

ANSI B.31.3


Plant

Circulation hoses (15156) NACE-MR-0175

ANSI B.31.3


Plant

Lifting

requirements

Z-015

Containers Z-015






Electrical

equipment design

and installation

Z-010

Z-015

E-001

E-002

FEA-M (1990)

Table 5 Well Control Equipment


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

(13533)

(15156)

16A

NACE-MR-0175

DNV Offshore standard OS-E101

Drilling Plant

Annular preventer (13533)(15156)

16A NACE-MR-0175


Drilling Plant

Snubbing stripper bowl or

active stripper.

(13533)

(15156)

16A

NACE-MR-0175


Drilling Plant

CT dual stripper (13533)

(15156)

16A

NACE-MR-0175

DNV Offshore standard OS-E101Drilling Plant

Gate & plug valves, check

valves and loops

(10423)

(15156)

6A

NACE-MR-0175


Drilling Plant

Stuffing box for solid

wireline - Slickline

(10423)

(15156)

6A

NACE-MR-0175

Grease injection head with

relevant sized flowtubes -

Braided cable

(10423)

(15156)

6A

NACE-MR-0175

Hydraulic line wiper and

stuffing box, Open hole

operations

(10423)

(15156)

6A

NACE-MR-0175

Choke & kill systems

(15156)

16C

NACE-MR-0175


Drilling Plant






BOP accumulator unit system

w/ BOP control hoses

Z-015

Z-010

E-001

E-002

16D

16E


Drilling Plant

FEA-M (1990)

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 goingthrough 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.






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 co-

operation 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 animporter 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.






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.

4.7 Layout and working environment requirements

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.






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;






• 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).

4.10 Operational requirement

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 toeach 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.






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

Internal

well control

Snubbing

• Stripper bowl or active stripper.

• Two stripper rams

•

Equalising loop system• One annular preventer

• Workstring

• Two back pressure valves in the BHA

X

X

XIf used

X

X

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

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






Secondary well control system is defined as follows:

Equipment External well

control

Internal well

control

Snubbing

•

One combined blind/shear ram

• Two pipe rams ( fixed or variable )

• One annular preventer

• Minimum one choke line outlet

• Minimum one kill line inlet

• 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

X

X

X

X

X

X

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. Alternativelyremote valve can be replaced with one manual valve

and a check valve.

X

X

X

X

X






Slick line Braided

or electric

line

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

X

X

X

X

XX

X

Tertiary well control system is defined as follows:

Equipment External

well control

Internal

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.






5.2 Equipment requirements

5.2.1 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 internaldiameter less than the x-mas tree bore.

X

X

X

X

X

X

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.

X X X

Consideration shall be given to H2S protection of the complete

system.

X X X

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.

1) 1) 2)

All side connections shall have metal to metal seal and have at

least have 50,8 mm (2 in) nominal size.

X X

Kill line connections shall have metal to metal seal. X

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.

X X X

The position of the kill and choke outlets should be arranged so

that circulation for well control can be carried out with theworkstring suspended in the BOP and the shear/blind ram

closed.

X X






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.

XX

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

Hydraulic operated stripper

The stripper system shall be a dual system that can be individually

and hydraulically controlled from the control cabin.

X

The upper stripper shall be located at shortest possible distance

from the injector drive chains to minimise buckling potential when

snubbing.

X

Pressure rating in accordance with the needs for the operation. The

stripper sealing elements shall fit the proper temperature and well

pressure range.

X X

The sealing elements and extrusion rings shall be replaceable with X






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

X

The stripper control system shall be hydraulic operated and

incorporate a regulating system to avoid over-pressurisation and

collapse of the workstring.

X X

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.

X

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.

X

The connection between the upper and lower stripper can be of a

quick hand union design, providing the connection has been

qualified.

X

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.

X

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.

X

The active stripper system for snubbing shall be hydraulically

controlled from the workbasket/control cabin.

X

Stripper bowl

Gauge and bleed off port on stripper bowl housing for trapped

pressure.

X

Stripper bowl shall be prepared to allow for installation of a

wireline adapter






5.2.4 Stuffing box, grease injection head, hydraulic line wiper and

Equipment Wireline

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

X

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

X

Hydraulic line wiperHydraulic actuated rubber element operated from hydraulic control unit. X

5.2.5 Pipe, stripper, slip, tubing, wireline shear blind, shear / seal, safety head rams and

annular preventer requirements


tubing

Wireline

GeneralThe 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 wellboreworking 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.

X

X

X

X

X

X1

X

X

X

X

X

X1

X

X

X

X

X

X2






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 theworkstring 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.

The slip ram shall be of a design that minimises or avoids

stress marking of the tubing.

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.

X1

X

X

X

X

X1

X

X

X

X2

X






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 theannular 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

X

X

If used

If used

Shear/blind ram or seal ram

The shear/blind ram shall be capable of shearing the highest-

grade of workstring, as well as sealing off the wellbore with

lateral and face seals.

The shear/seal ram shall be capable of shearing the highest-

grade 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, toenable 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

X

X1

X

X

X2

X

1 Workstring2 Wire






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 x-

mas tree bore.

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

X






5.2.6 Riser, lubricator, tool catcher and chemical injection sub


tubing

Wireline

RiserThe 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.

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.

X

X

X

X

X

X

X

X

X

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.

X

Tool catcher

The tool catcher shall be of failsafe type spring catch/hydraulic

release design.

X

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






5.2.7 Piping and hook-up valves to well control system


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.

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 plugswith metal to metal seals instead of two valves.

X

1)

X

X

X

X

X

X

X

X

2)

X

X

X

X

X

X

X

X

2)

X

X

X

X

X

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






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 pressureshall 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).






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 functionsare 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

• 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

• Shear/seal ram

There shall be documentary evidence that the pressure capacity of the accumulators is capable of

operating the rams according to the design requirements.






As a minimum for dimensioning total accumulator volumes and capacities (isotherm, adiabatic slow

charge and fast operation) shall be included.

Snubbing Coiled

tubing

Wireline

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:

Workstring Coiled

tubing

string

Wire/cable

Closing and opening of one Annular

preventer

N/A N/A

Closing, opening and closing of one Pipe ram Pipe ram Wireline

ram

Alternatively a dedicated shear ram auxiliary pressure system (shear boost system) may be installedto 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 Regulationsand NORSOK standard S-002






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

Regulators for as follows: Acc. unit Work

basket

cabin

Acc. unit Coiled

tubing

cabin

Acc. unit Wireline

cabin

BOP ram activation

pressure-manifold pressure.

Annular preventer regulator.

Active stripper regulator.

Upper stripper regulator.

Lower stripper regulator.

X

X

If used

If used

X

If used

X

If used

If used

If used

X

X

If used If used

Alarms for as follows:

Low accumulator pressure.

Loss of power supply.

Low level of control fluid.

X

X

X

X

X

X

X

X

X

If used

If used

If used

X

X

X

If used

If used

If used

Pressure monitoring:

Accumulator pressure

BOP ram activation/

manifold pressure.

Annular preventer pressure.

Active stripper pressure.

Upper stripper pressure.

Lower stripper pressure.

X

X

X

If used

X

X

X

If used

X

X

If used

X

X

If used

X

X

X

X

X

X

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

X

X

X

X

X

XX

X

X

X

X

X

X

X

X

XX

X

If used

X

X

X

If used

X

X

X

X

X

X

X

X

X

X






Flow monitoring:

BOP fluid monitoring. X X X X X X

Optional BOP ram/valve

open and close functions:

Active stripper.

Deployment functions

Seal/slip ram.

Blind ram.

Locking holding ram.

Disconnect ram.

Auxiliary valve.

X

X

X

X

X

X

X

If used

If used

If used

If used

X

X

X

X

BOP accumulator bypass:

BOP accumulator unit shall

be equipped with a bypass

function for allowingaccumulator pressure to

bypass the regulated

manifold pressure.

X If used

Additional control

functions:

Grease injection to BOP.

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.






6 SNUBBING EQUIPMENT

6.1

GeneralThe 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 .






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 travellingassembly, 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 systemThe 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






• 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 thesnubbing 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:






• 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:






• 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;


• workstring pressure;

• workstring depth;

• rig and slip hydraulic pressure;

• rotary torque and rpm.

• workstring connection torque;

• optional: volume control;

•

optional: pump speed.






In addition, there shall be a back-up system, which records

• workstring weight (positive and negative);


• 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.






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.






7 COILED TUBING EQUIPMENT

7.1 General

A coiled tubing unit with associated systems shall be capable of handling the workstring, wellconditions 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:

• 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.

7.2 Coiled tubing equipment requirements

7.2.1 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.






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.






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].






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 north-

south 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-submersibleoperations.

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 loadcapacity shall minimum be 30 % above the weight of the injector head assembly above the quick






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.


control cabin.



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.



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-lineinstalled may be drifted if applicable.






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.






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 thecomplete 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;






• 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 individualadjustment 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;



• 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;



• 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 systemWell control system shall be in accordance with clause 5.






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 andtorsion) 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.






8 WIRELINE EQUIPMENT

8.1 General

The wireline unit with associated systems shall be capable of handling the tool string, wellconditions 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:

• 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.

8.2 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: 2,7 mm (0,108 in); 3,2 mm (0,125 in) 80 % of breaking strength

• Braided/electric cable: 4,8 mm (0,188 in); 5,6 mm (0,219 in) 80 % of breaking strength

• Braided/electric cable: 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 systemshall 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)






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.






Depth indicator system: Calibration range of +/-1,5 m for a depth of 5 000 m

(+/- 4,9 ft for depth of 16 400 ft)

Weight indicator system: 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) 0,30 m to 0,36 m (12 in to14 in)

• Slickline, 3,2 mm (0,125 in) 0,30 m to 0,36 m (12 in to14 in)

• Braided/electric cable, 4,8 mm (3/16 in), 5,6 mm (7/32 in) 0,30 m to 0,36 m (12 in to14 in)

• Braided/electric cable, 7,9 mm (5/16 in) 0,41 m to 0,49 m (16 in to19 in)

• Electric cable, 11,9 mm (15/32 in) 0,51 m to 0,61 m (20 in to 24 in)

• Electric cable, 12,7 mm (1/2 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.


control cabin.










circuits and only the well control system shall be able to take hydraulic pressure from the dedicatedaccumulators.

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

6,9 MPa

(1 000 psi)

34,5 MPa

(5 000 psi)

69,0 MPa

(10 000 psi)

103,4 MPa

(15 000 psi)

Pump rate 30 l/min 3 l/min 1,0 l/min 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 operationalrequirements, 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.






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;


c) fishing tool components;

• fishing neck on all components;


• rated for the exposed loads;


d) explosive tool components;


•

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.






9 DOCUMENTATION

9.1 General

The following equipment is considered to be comprised by this category and shall be presentedaccording 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) substructures;

b) masts with bolts and shackles;

c) hoisting machinery with complete associated equipment;

d) running tools and workstring (tubular) and BHA;

e) BOP with choke manifold;

f) wellhead arrangement;

g)

hydraulic and flange and clamp connection unit to wellhead;h) lifting equipment/cranes;

i) deadline anchor for the wire rope of the draw-work;

j) wire rope of the draw-work;

k) testing equipment with piping arrangement;

l) high pressure piping systems and pressure vessels;

m) wire line masts and units;

n) coiled tubing equipment;

o) snubbing equipment;

p) pipehandling equipment;

q) pumping equipment;

r) power generation packages;

s) 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






a) name of equipment;

b) production number;

c) name of manufacturer and supplier;

d) description of design and manufacture, indicating safety factors;

e)

verification of design and strength control;f) material certificates and confirmation as to where materials have been used;

g) welding procedure specifications and qualification;

h) confirmations with that manufacture, inspection and final control have been subjected to

independent verification;

i) report from testing including testing conditions, and information on how testing has been carried

out;

j) independent verification of design assumptions with regard to strength;

k) supplier’s operation and maintenance specifications, with indication of operational criteria and

limitations;

l)

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) analysis of elements (chemical composition);

b) hardness measurements;

c) non-destructive examination (magnetic particle inspection, replica etc.);

d) 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) capacity (e.g.lifting capacity);

b) pressure;

c) volume;

d) temperature;

e) exposure time;

f)

environmental loads;g) tensile loads;

h) corrosion;

i) erosion;

j) thickness measurements;

k) 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.






9.2 Specific well intervention requirements

9.2.1 Downhole tools and strings for snubbing, coiled tubing and wireline

The manufacture's quality control certificate and documentation shall include




d) description of design and manufacture, indicating safety factor used;

e) 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) receiving - quality control of the tool;

b) marking of equipment;

c) updating of items in the case of modification of equipment;

d) quality audit of the maker's manufacturing process;

e) inspection report;

f) drawings showing internal parts and functions, overall length, maximum outside diameter,

minimum internal diameter and weight;

g)

tool description, function, maximum and minimum parameters;h) strength calculations indicating safety margins;

i) operational manual/operating procedures;

j) 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





d) 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;






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 firmand 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





d) description of design and manufacture, indicating safety factor used;

e) material certificates including chemical analysis and mechanical strengths;

f)

report from testing including testing conditions, and information on how testing has been carriedout;

g) quality audit of the maker's manufacturing process;

h) inspection reports;

i) physical dimensions.






ANNEX A

(informative)

DATA SHEET SNUBBING EQUIPMENT

Operator: D-002

Project: Rev. 1

Document no: Sep. 2000

Date and revision:

System/equipment NORSOK

I3

NORSOK

II1

Your

choice

NORSOK classification selectedGeneral snubbing

Module size maximum L x W x H

Module weight maximum MT (Megatonnes)

Derrick/mast /hoisting structure/hoisting

equipment minimum static capacity:

1510 kN

(340 klbf)

2930 kN

(658 klbf)

Rotary table loading 1510 kN

(340 klbf)

2930 kN

(658 klbf)

Structures snubbing

Derrick/mast /hoisting structure and hoistingequipment minimum capacity

1510 kN(340 klbf)

2930 kN(658 klbf)

Rotary table load rating 1510 kN

(340 klbf)

2930 kN

(658 klbf)

BOP handling equipment – maximum load rating kN (klb) kN (klb)

Pad eyes / hang off points for travelling

assemblies, minimum safe working load capacity 49 kN

(11,0 klbf)

49 kN

(11,0 klbf)

Pad eyes/hang off points for rig tongs, work

winches etc., minimum safe working load

capacity

24 kN

(5,4 klbf)

24 kN

(5,4 klbf)

Hoisting and rotary systems

Minimum lifting capacity 1510 kN

(340 klbf)

2930 kN

(658 klbf)

Lifting speed – minimum 1 m/s (ft/s) 1 m/s (ft/s)

Topdrive – minimum load rating 1510 kN

(340 klbf)

2930 kN

(658 klbf)

Topdrive maximum at max continuous torque - 160 rpm 160 rpm

3 -Ref: D-001 chapter 4.4






minimum

Topdrive maximum continuos torque – minimum 9 kNm

(6,6 klb·ft)

29 kNm

(21,4 klb·ft)

Topdrive breakout torque - minimum kNm (klb·ft) kNm (klb·ft)

Topdrive makeup torque – minimum 80 kNm

(59,0 klb·ft)

80 kNm

(59,0 klb·ft)

Topdrive/rotary speed at maximum continuous

torque

120 rpm 160 rpm

Topdrive/rotary minimum speed at maximum

torque

10 rpm 10 rpm

Topdrive/swivel maximum speed 160 rpm 220 rpm

Topdrive/swivel minimum pressure rating 34,5 MPa

(5 000 psi)

51,7 MPa

(7 500 psi)

Rotary table – minimum internal diameter 0,345 m

(1,13 ft)

0,345 m

(1,13 ft)

Rotary table – minimum load rating 1510 kN(340 klbf)

2930 kN(658 klbf)

Rotary table - minimum 160 rpm 220 rpm

Rotary table - torque, minimum 9 Nm

(6,6 lbf·ft)

29 Nm

(21,4 lbf·ft)

Lifting height – to be defined. m (ft) m (ft)

System/equipment NORSOK I NORSOK II Your

choice

Pipehandling systems

Vertical pipehandling system (s):

Lifting capacity - minimum 3 kN (674

lbf)

3 kN (674

lbf)

Minimum average drillpipe tripping speed 45 joints/h 45 joints/h

Horisontal pipehandling system(s)

Tubular range – handling capacity 73,0 mm to

177,8 mm

2,875 in to -

7 in

73,0 mm to

330,3 mm

2,875 in to –

13,375 inLifting capacity - minimum 10 kN

(2,2 klbf)

30 kN

(6,7 klbf)

Handling capacity – tubular per, minimum:

330,3 mm (13 3/8 in) 25 25

244,5 mm (9 5/8 in) 35 35

177,8 mm (7 in) or smaller 45 45

Iron roughneck – break-out torque - minimum 100 kNm

(73,8

klbf·ft)

100 kNm

(73,8 klbf·ft)

Tubing tongs – break – out torque - minimum






Associated equipment

Minimum capacities unless otherwise specified:

Work winches 30 kN

(6,7 klbf)

30 kN

(6,7 klbf)

Manrider winches 1,5 kN

(337 lbf)

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

69,0 MPa

(10 000 psi)

69,0 MPa

(10 000 psi)

BOP internal diameter - optional 179,4 mm

(7 7,063 in)

179,4 mm (7

7,063 in)

No. of rams - minimum 5 5

Ram sizes - optional

No. of annular preventer(s) - minimum 1 1

Annular preventer(s) internal diameter - as for

BOP

179,4 mm

(7 7,063 in)

179,4 mm (7

7,063 in)

Annular preventer pressure rating - minimum 69,0 MPa

(10 000 psi)

69,0 MPa

(10 000 psi) No. of choke/kill outlets - minimum 2 2

Choke/kill valves pressure rating - minimum 69,0 MPa

(10 000 psi)

69,0 MPa

(10 000 psi)






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 Description Each Your choice

1 2,7 mm (0,108 in) slick line withouttension

1 ea. strand

2 2,7 mm (0,108 in) slick line 10 ea. strands

3 11,1 mm (0,438 in) el. cable w/ 2,2 kN

(500 lbf) tension

1 ea. strand

4 11,1 mm (0,438 in), 5 cores el. cable

without tension

10 strands

5 31,8 mm (1,25 in), 2,8 mm (0,109 in)

wall thickness coiled tubing

10-12 ea. parallel

strings

6 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.

3 parallel strings

7 Heavy wall 4,8 mm (0,188 in) wall

thickness 60,3 mm (2 3/8 in) and 73,0mm (2 7/8 in) coiled tubing with 11,1

mm (7/16 in) cable inside.

2ea. parallel strings

8 50,8 mm (2 in) sinker bar, ANSI 4230

steel quality

1 ea.

9 88,9 mm (3,5 in) Drillpipe S-135, 226,2

N/m (15,5 lbf/ft)

1 ea.

10 101,6 mm (4 in) tubing 13 chrome L-80 1 ea.






11 114,3 mm (4,5 in) perforating gun 1 ea.

12 114,3 mm (4,5 in) 184,0 N/m

(12,6 lbf/ft) tubing

1 ea.

13 117,5 mm (4 5/8 in) gravel pack screenw/ 60,3 mm (2 3/8 in) washpipe inside

1 ea.

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.






ANNEX C

(informative)

SNUBBING AND COILED TUBING WELL CONTROL SYSTEM RIG UP






ANNEX D

(informative)

WIRELINE WELL CONTROL SYSTEM RIG UP






BIBLIOGRAPHY

[1] NORSOK C-001, Living quarters area.

[2] NORSOK C-002, Architectural components and requirements.

[3] NORSOK D-010, Drilling & Well operations.

[4] NORSOK D-CR-003, Surface Christmas Tree.

[5] NORSOK D-SR-007, Well testing system.

[6] NORSOK E-001 , Electrical systems.

[7] NORSOK E-002, Adjustable speed motor drives.

[8] NORSOK I-001, Field Instrumentation, 1.

[9] NORSOK I-002, Safety and automation systems (SAS).

[10] NORSOK I-SR-001, Wellhead Control and Hydraulic Power .

[12] NORSOK L-001, Piping and valves.

[13] NORSOK M-001, Material Selection.[14] NORSOK M-702, Drill string components.

[15] NORSOK S-005, Machinery – working environment analysis and documentation.

[15] NORSOK Z-008, Criticality Classification Method.

[17] NORSOK Z-016, Management and Regularity Technology.

[18] ISO 1000, SI units and recommendations for the use of their multiples of certain other units.

[19] ISO 9000, Quality management and quality assurance standards.

[20] ISO 10400, Formulae and calculation for casing, tubing, drill pipe and line pipe properties.

[21] ISO 10407, Petroleum and Natural Gas Industries – Drilling and Production Equipment –

Drill Stem Design and Operating Limits .

[22] ISO 10417, Petroleum and Natural Gas Industries – Subsurface Safety Valve Systems –

Design Installation, Operation and Repair.

[24] ISO 10432, Petroleum and Natural Gas Industries – Subsurface Safety Equipment –

Specification.

[25] ISO 10433, Petroleum and Natural Gas Industries – Drilling and Production Equipment –

Specification for Wellhead Surface Safety Valves and Underwater Safety Valves

for Offshore Service.

[26] ANSI/ASME B31.3, Process Piping.

[27] API RP 5C7, Coiled Tubing Operations in Oil and Gas Well Service.

[28] API RP 7G, Drill Stem Design and Operating Limits.

[29] API RP 8B, Recommended Practice for Procedures for Inspection, Maintenance, Repair and

Remanufacture of Hoisting equipment.[30] API RP 16E, Design of control systems for drilling well control equipment .

[31] API RP 53, Blow-out Prevention Equipment Systems for Drilling Wells.

[39] ASTM A 370, Test methods and definitions for mechanical testing of steel products.

[40] ASTM A 450, Specification for general requirements for carbon, ferritic alloy, and austenitic

alloy steel tubes.

[41] ASTM E 18, Test methods for rockwell hardness and rockwell superficial hardness of

metallic materials.

[42] ASTM E 94, Guide for radiographic testing.

[43] ASTM E 140-88, Hardness conversion tables for metals.

[44] BS 5500, Pressure vessels, accumulators and piping systems.

[44] BS 6755: Part 1: ISO 5208 Specification for production pressure testing requirements





[45] ISO 5208, Industrial valves – Pressure testing of valves.

[46] TBK 1-2, General rules for pressure vessels.

Documents

API Norsok Standardise for Well Intervention Equipment