api norsok standardise for well intervention equipment
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NORSOK STANDARD
SYSTEM REQUIREMENTS WELL INTERVENTION
EQUIPMENT
D-002Rev. 1, October 2000
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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
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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
7.3 Power package 46
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
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System requirements well intervention equipment D-002
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8.3 Control cabin 52
8.4 Data acquisition 52
8.5 Clamps/sheaves and hay pulleys 53
8.6 Power package 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
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System requirements well intervention equipment D-002
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NORSOK standard Page 3 of 68
FOREWORD
NORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative to
add value, reduce cost and lead time and eliminate unnecessary activities in offshore field
developments and operations.
The NORSOK standards are developed by the Norwegian petroleum industry as a part of the
NORSOK initiative and supported by OLF (The Norwegian Oil Industry Association) and TBL
(Federation of Norwegian Manufacturing Industries). NORSOK standards are administered and
issued by NTS (Norwegian Technology Center).
The purpose of NORSOK standards is to contribute to meet the NORSOK goals, e.g. to develop
standards that ensure adequate safety, value adding and cost effectiveness and thus are used in
existing and future petroleum industry developments.
The NORSOK standards make extensive references to international standards. Where relevant, the
contents of a NORSOK standard will be used to provide input to the international standardisation
process. Subject to implementation into international standards, the NORSOK standard will be
withdrawn.
Annexes A, B, C and D are for information only.
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System requirements well intervention equipment D-002
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INTRODUCTION
The main objective of this NORSOK standard is to contribute to optimise the design of well service
and intervention facilities, their systems and equipment with respect to utilisation, operational
efficiency, life cycle cost and to stipulate acceptable safety levels.
NORSOK standard D-002 is an overall improvement and expansions of the former standards for
coiled tubing, snubbing and wire line equipment, and replace the following NORSOK standards:
• D-SR-005 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
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1 SCOPE
This standard describes the design, installation and commissioning principles and requirements for the well intervention equipment and their systems and equipment.
2 NORMATIVE REFERENCES
The following standards include provisions which, through reference in this text, constitute
provisions of this NORSOK standard. Latest issue of the references shall be used unless otherwise
agreed. Other recognized standards may be used provided it can be shown that they meet or exceed
the requirements of the standards referenced below.
NPD Regulations
NORSOK D-001, Drilling facilities.
NORSOK E-001 Electrical systems,
NORSOK E-002 Adjustable speed motor drives.
NORSOK H-001 HVAC Heating, ventilation and air conditioning
NORSOK N-001, Structural design.
NORSOK N-003, Actions and action effects.
NORSOK S-001, Technical Safety.
NORSOK S-002, Working Environment.
NORSOK S-003, Environmental Care.
NORSOK Z-010 Installation of Electrical, Instrument & Telecommunication
NORSOK Z-015, Temporary Equipment.
ISO 10423 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
ISO 13533 Petroleum and Natural Gas Industries – Drilling and production equipment –
Specification for drill through equipment
ISO 13535 Petroleum and Natural Gas Industries – Drilling and production equipment –
Hoisting equipmentISO 13626 Petroleum and Natural Gas Industries – Drilling and production equipment –
Drilling and well servicing structures – Specification
ISO 14693 Petroleum and Natural Gas Industries – Drilling and production equipment –
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
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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).
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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
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System requirements well intervention equipment D-002
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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.
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System requirements well intervention equipment D-002
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Planning, design, fabrication, operation and maintenance of well intervention equipment shall be
according to documents listed in Table 1, Table 2, Table 3, Table 4 and Table 5.
Table 1 Snubbing
Note: ( ) means standards under preparation
Equipment Norsok ISO API 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 Lifting Appliance
DNV Offshore standard OS-E101 Drilling
Plant
Pipe handling
system;
DNV Offshore standard OS-E101 Drilling
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
DNV Offshore standard OS-E101 Drilling
Plant
Slip bowls /
carriers
(13535)
(14693)
8 C
7K
DNV Offshore standard OS-E101 Drilling
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
DNV Offshore standard OS-E101 Drilling
Plant
Kelly valves (13535)
(10424)
(15156)
8C
7
NACE-MR-0175
DNV Offshore standard OS-E101 Drilling
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.
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System requirements well intervention equipment D-002
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Table 2 Coiled Tubing
Norsok ISO API Other
Substructures N-001 NS-3472
BS449
BS7072
DNV Lifting Appliance
DNV Offshore standard OS-E101 Drilling
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
DNV Lifting Appliance
DNV Offshore standard OS-E101 Drilling
Plant
BHA 9001:,
Chapter
4.5 4.74.16
BS 308: Parts 1, 2, & 3.
BS 4656: Parts 1, 2, 3, & 4.
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Table 3 Wireline
Norsok ISO API Other
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;
DNV Offshore standard OS-E101 Drilling
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
DNV Offshore standard OS-E101 Drilling
Plant
Chiksan / stand
pipe
(10423)
(15156)
6A
NACE-MR-0175
ANSI B.31.3
DNV Offshore standard OS-E101 Drilling
Plant
Circulation hoses (15156) NACE-MR-0175
ANSI B.31.3
DNV Offshore standard OS-E101 Drilling
Plant
Lifting
requirements
Z-015
Containers Z-015
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System requirements well intervention equipment D-002
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Electrical
equipment design
and installation
Z-010
Z-015
E-001
E-002
FEA-M (1990)
Table 5 Well Control Equipment
Norsok ISO API Other
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
DNV Offshore standard OS-E101
Drilling Plant
Snubbing stripper bowl or
active stripper.
(13533)
(15156)
16A
NACE-MR-0175
DNV Offshore standard OS-E101
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
DNV Offshore standard OS-E101
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
DNV Offshore standard OS-E101
Drilling Plant
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System requirements well intervention equipment D-002
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BOP accumulator unit system
w/ BOP control hoses
Z-015
Z-010
E-001
E-002
16D
16E
DNV Offshore standard OS-E101
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.
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4.4.3 Marking
Equipment shall be clearly marked as follows with identification and operational limitations,
relating the equipment to certificates and fabrication documentation:
Equipment identification:
• manufacturer’s name or mark;
• equipment type no.;
• equipment serial no.
Operational limitations such as:
• working load limit;
• working pressure;
• maximum voltage;
•
maximum temperature.
There shall be consistency between units used for marking and units displayed on instruments.
CE marking applies to machines and simple pressure vessels on fixed installations.
Machinery placed on the market after 8 April 1995 shall be designed, manufactured and
documented in accordance with the requirements of the Machinery Directive 98/37/EC/Forskrift om
maskiner Best. nr. 522. The requirement entails that the individual contractor, sub-contractor etc.
shall ensure that machinery taken into use has received CE marking and that it is accompanied by a
declaration of conformity.
By marketing («place on the market») is meant the first time a product, against payment or free of
charge, is placed at disposal with a view to distribution or use within the EEA. The NPD has in 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.
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4.5 LCC and regularity
Regularity requirements shall be defined prior to detailed design, based on stability (MTBF/MTTR)
and service intervals. The service intervals shall reflect the MTBF. LCC shall be defined for all vital
parts in the well intervention equipment.
4.6
Process and ambient conditions
The well intervention equipment shall be selected and designed to operate under ambient conditions
prevalent in the intended area of operation, and shall be resistant to well intervention and formation
fluids.
4.6.1 Design basis
The equipment shall be designed as required for the following conditions:
• ambient temperature, structures: -20 °C to + 40 °C;
• ambient temperature, machinery: -10 °C to + 40 °C;
•
humidity: 100%;• for conditions where H2S service is required, NACE MR-0175 applies.
The design basis shall be defined for the following load combinations:
• operational load;
• snow and ice loads;
• earthquake conditions (optional);
• impact from transportation;
• wind conditions;
•
the structure shall as a minimum be designed for continuos operation with regards to hook load,rotary load for wind speeds up to 30 m/s, 10 min. mean values, considering a reference height of
50 m above lowest astronomical tide, unless otherwise specified.
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.
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4.7.2 Noise protection requirements.
Special attention hall be made to requirements defined in the NORSOK standard S-002 for design
of cabins, power generation packages, fluid and N2 pumping units and accumulator packages.
The control cabins for snubbing, coiled tubing, wireline equipment and pumping units shall be
designed to withstand a total outdoor area noise level impact of 90 dB (A) and be designed
according to values defined in NORSOK standard S-002, annex A, for driller cabins. The total noise
level shall not exceed 65 dB (A) inside the cabin.
The power packages, fluid and N2 pumping units and accumulator packages for snubbing, coiled
tubing and wireline operations shall be designed according to values defined in NORSOK standard
S-002. The equipment shall be designed in such a manner that the total noise level from the
equipment shall not exceed 82 dB (A) and the equipment shall not contribute to exceed a max area
noise level as defined in NORSOK standard S-001, i.e. 85 dB (A) on pipe deck area.
4.7.3 Material handling
The layout and design of the well intervention equipment shall ensure safe and efficient transport
and handling of equipment and materials. A material handling study should be performed to secure
safe and efficient operation.
4.8 Special requirements for skid base structures
The skidable part of the well intervention rig up frames and structures should be installed on the
platforms integrated skid beams, extending to at least one platform edge to facilitate on/off loading
of modules. The frames and structures shall be designed to suit all relevant load conditions, see
NORSOK standard N-001 and NORSOK standard N-003. The remaining parts of the well
intervention equipment shall be located adjacent to the skidable structure.
Contaminated fluids shall be collected and routed to a dedicated slop tank system. All other fluids
from the well intervention equipment, rigged up on top of the skid base substructure, shall be
discharged to the installations drain points.
4.9 Utility interfaces
The well intervention equipment should be supplied with dedicated interface termination points.
Mechanic, electric, hydraulic and pneumatic interface connections shall be compatible with rig or platform connections.
The following utilities should typically be supplied by the platform facilities to support the well
intervention equipment:
• electrical power supply;
• emergency power supply;
• fire and gas control interface;
• emergency shutdown interface;
•
sea, fresh water, steam and hot water;• drains;
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 17 of 68
• 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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 18 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 19 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 20 of 68
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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 21 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 22 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 23 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 24 of 68
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
Equipment Snubbing Coiled
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 25 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 26 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 27 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 28 of 68
5.2.6 Riser, lubricator, tool catcher and chemical injection sub
Equipment Snubbing Coiled
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 29 of 68
5.2.7 Piping and hook-up valves to well control system
Equipment Snubbing Coiled
tubing
Wireline
Piping and hook-up valves
All piping and hook-up valves to the well control system shall have
a pressure rating in accordance with the needs for the operation.
The piping and valves to treating and flowing lines should be
minimum 50,8 mm (2 “ in) nominal size.
Kill line for wireline should be minimum 50,8 mm (2 in) nom size.
All outlets and inlets on the BOP system shall have metal to metal
seals. The outlets and inlets shall be fitted with at least two valves.
1) All outlets and inlets.2) All outlets and inlets below shear/seal ram.
• The valves shall be bi-directional and the inner valve, closest to
the wellbore, should be flanged and have metal to metal sealing
in the bore (gate valve type).
• Threaded connections are permissible only downstream the first
valve away from the well and riser bore.
• One of the two valves on outlets and inlets for treatment or
flow lines shall be remotely operated. On the kill line, a manual
operated valve and a check valve can replace the remotely
operated valve.
• The inner valve shall not be used as a working valve.
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 30 of 68
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).
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 31 of 68
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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 32 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 33 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
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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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 35 of 68
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 .
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System requirements well intervention equipment D-002
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6.2 Snubbing equipment requirements
6.2.1 Snubbing units / snubbing units with derrick/mast type structures
The derrick, mast or hoisting structure shall be designed to withstand the loads and forces imposed
by the relevant operational and environmental loads. In addition, the structure can be used for
support of pipehandling equipment, and support for racked tubular on setback areas if applicable.
see NORSOK standard N-001.
Access in connection with operation and maintenance of equipment shall be catered for by suitable
and safe access from deck or installed work platforms. From current practice it follows that the
various work platforms in structures (including platform for installation of casings) shall be
adequately equipped with safety devices, lifts, stairs or ladders for safe access, see NORSOK D-001
standard.
Lubrication points with difficult access in the workover area, such as sheaves, shall be routed to a
readily accessible area. Sufficient number of hang off points of required capacity for 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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
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• stowage, make up, break out and suspension of workstring, collars, casings and tubing in the
rotary table;
• transport of workstring, casing, collars etc. to and from storage location in front of “ V- door “ to
the snubbing unit working platform area. The complete string of tubular shall be stored on a
location where it require no platform crane handling between the storage location to 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:
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System requirements well intervention equipment D-002
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• the height from the tong post arm to the workbasket handrail shall be adequate to accommodate
the power tong and with a suspension and trolley arrangement to allow swinging of tong away
from the centre line;
• tong suspension arrangement to allow the introduction of a spring to prevent overload of tong
arm during make-up of tubular joints;
• to incorporate tong backup attachment eye, rated at the maximum horizontal force resulting
from the maximum tong torque capacity.
One set of tubing tong with slide heads for both tong and back-up to fit the tube and upset
connection of the workstring.
6.2.7 Winch package
The dual type counterbalance winch package shall if used be skid mounted with drip pan.
The winch package to contain an automatic fail-safe brake in the event of hydraulic failure and the
safe working load on the winch shall be determined by the work program.
Winch package can be voided if design of unit do not require such system.
6.2.8 Gin pole
Where a gin pole system is required, it shall be able to extend to such a height that the distance from
the bottom of the gin pole sheaves to the workbasket (handrail) is sufficient to accommodate the
pipe length (Range II or III) plus safety valve, circulation swivel, swivel with tackle including a
reserve air gap of minimum 1,0 m (3 ft).
The system shall contain a hydraulic arrangement for raising and lowering of the gin pole.
6.2.9 Workbasket and operator cabin
If the jack and pulling unit is designed with a workbasket, the travelling head area shall be equipped
with removable internal handrail to guard against the rotating workstring. Personnel safety and
working environment shall be given due consideration.
The workbasket shall have two independent escape exits and be equipped with wind walls for
weather protection, and a workstring mark board in the workbasket area for operator quick reference
of workstring depth.
The layout of the operator cabin shall ensure full operational control and view from the operator’s
position to the various parts of the work floor area.
The control cabin shall have an ergonomic layout and be designed according to NPD Regulations
and NORSOK standard S-002.
The control cabin shall facilitate all necessary controls and monitoring equipment to operate the
complete snubbing unit and well control equipment as defined in clause 5.
Control cabins shall satisfy the following requirements:
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System requirements well intervention equipment D-002
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• the operator cabin shall have an ergonomic layout and shall be equipped with laminated glass,
oil resistant wiper or cleaner and a suitable mechanical ventilation system;
• the roof and windows shall have adequate strengthening or protection against falling objects.
• due consideration to be given to visibility on control system visual display unit screens;
• jack "snub" and "heavy" force limitation shall be pre-set at power pack manifold local
adjustments in workbasket and cabin shall not override the pre-set value;
• there shall be individual hydraulic circuits for jack, pipe-handling system, BOP and auxiliary
system. Each circuit shall have an adjustable pressure safety relief and pressure indicator;
• interlock shall be provided to prevent inadvertent opening of the stationary and the travelling
heavy slips simultaneously. It shall be possible to manually over ride this interlock.
The controls and monitoring equipment shall as a minimum include the following:
• torque control for rotary or top drive;
• rotary/top drive speed adjustment;
•
rotary/top drive direction control;• power package speed control;
• power package shut down;
• power package ESD,
• selector for operating jack by two of four cylinders (option);
• jack direction control lever;
• slip bowl control levers;
• slip pressure regulator;
• weight indicator (heavy and snub force);
• wellhead pressure;
•
circulating pressure.
6.3 Data acquisition system
The snubbing unit shall be equipped with a data acquisition system to display and record operational
parameters. The data-sampling rate shall be sufficient to record relevant variations in the displayed
and recorded parameters. A system for analyzing the recorded data shall be available at the location.
The snubbing unit shall be equipped with a data acquisition system to monitor and record the
following parameters:
•
time and date;• workstring weight, positive and negative (heavy and snub);
• jack hydraulic system pressure;
• wellhead pressure;
• workstring pressure;
• workstring depth;
• rig and slip hydraulic pressure;
• rotary torque and rpm.
• workstring connection torque;
• optional: volume control;
•
optional: pump speed.
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System requirements well intervention equipment D-002
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In addition, there shall be a back-up system, which records
• workstring weight (positive and negative);
• wellhead pressure;
• workstring pressure.
6.4 Power package
Two independent power packages are required at the work site. Minimum one unit shall be diesel
driven and capable of supplying sufficient power to operate all operating systems of the snubbing
unit on a continuos basis and at peak demand.
The power package shall be designed and sound proofed in accordance with NPD Regulations.
Provisions shall be made for a manual ESD system that is operated locally and remotely from the
workbasket/control cabin.
The power package shall be certified for operating in Zone II areas and in accordance with
NORSOK standard Z-015.
Provisions shall be available for remote and local control. Individual adjustment and pre setting of
the operating limits for maximum pull and push forces to the snubbing unit shall be possible. These
shall be protected from adjustment during normal operating conditions.
If the power package is used for charging the accumulator system for the well control equipment,
the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic
circuits. Only the well control system shall be able to take hydraulic pressure from the dedicated
accumulators.
6.5 Circulating system
The circulating swivel and circulating hose working pressure to comply with operational
requirement. The integral 90° gooseneck with lift eye shall if used be compatible with
counterbalance winch.
Pin connection on swivel shall be compatible with the safety valve requirements.
Minimum circulating hose length shall be equal to one single joint and end connection equipped
with safety clamps and chain.
6.6 Well control system
Well control system to be according to clause 5.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
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6.7 Workstring and BHA
6.7.1 General
The workstring shall meet the operational requirements with respect to maximum anticipated pressure, temperature, torque, tension and compression. The workstring shall be inspected and a
verification report shall be issued stating approved and found suitable for operation as a minimum.
The tubing shall have documented tracability. A pipe tracking system may provide documented
tracability.
During operations the workstring limitation for over pull shall be set to 80% of manufacture's
tensional yield/torsional yield of the workstring.
For live well interventions, the type of connection for use in the workstring above the BPVs (check valves) to meet the requirement of minimum two independent gas tight metal- to - metal seals. The
seals to withstand internal and external pressure.
Drifts (2 each size), stabbing guides (2 each size), necessary x-overs and overshots for fishing the
workstring components shall be included.
6.7.2 Back pressure valve (BPV)
The BPVs prevents well fluids from entering into the workstring. The BPV is a barrier element and
shall have a working pressure rating equal to the expected wellbore pressure. The BPVs shall be
provided with seals in the bore towards the BHA and provide internal and external seal.
Provisions shall be made for pumping balls through the BPVs.
6.7.3 Others
All other equipment or tools in the BHA shall be qualified and designed to withstand all expected
down hole forces and conditions.
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System requirements well intervention equipment D-002
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7 COILED TUBING EQUIPMENT
7.1 General
A coiled tubing unit with associated systems shall be capable of handling the workstring, 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.
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System requirements well intervention equipment D-002
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7.2.1.3 Drive chain system
The drive chain system shall be capable of handling the maximum weight of the workstring with
minimum damage.
The drive chain shall be easily replaceable in the field or be equipped with replaceable gripper
blocks.
7.2.1.4 Traction system
The traction system shall provide variable gripping force designed to minimise tubing damage and
prevent tubing slippage.
The traction force shall be adjustable from the control cabin and be capable of generating sufficient
friction to push or pull the workstring at maximum rated loads without slippage or damage to the
workstring.
The traction system shall have a fail-safe device preventing loss of traction pressure in case of a
broken hose.
The traction system shall be provided with an accumulator system for each traction circuit at the
injector head.
Provisions shall be available to provide traction in the event of power supply failure.
7.2.1.5 Tension system
The chain tension system should be adjustable from the control cabin and be capable of tensioning
the injector chain sufficiently to avoid damage to bearings and the coiled tubing workstring.
The tension system should be provided with an accumulator system at the injector head.
7.2.1.6 Hydraulic drive system
The hydraulic drive system shall provide accurate fine movement control of the tubing in and out of
hole during maximum load conditions.
Provisions shall be available at the injector head, control cabin or power unit, for individual
adjustment and pre-set of the operating limits for maximum pull and push forces to the injector head. These shall be protected from adjustment during normal operating conditions.
The hydraulic drive system shall be capable of pushing or pulling the maximum rated load at a
speed of 10 m/min.
The hydraulic system shall be fail safe and stop the chains from moving if hydraulic power is lost.
Charts for hydraulic pressure with corresponding load and available hydraulic pressure shall be
provided.
Provisions shall be made for hydraulic drive lockout when the reel brake is engaged.
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System requirements well intervention equipment D-002
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7.2.1.7 Brake system
The brake system shall be capable of holding the maximum rated loads and be fail safe so that the
brakes will stop the chains from moving and hold the load in case hydraulic power is lost.
7.2.1.8 Weight indicator
The weight indicator system shall be capable of measuring all tensile and compressive forces
(positive and negative weights) in the workstring above the stripper. Provisions shall be made for
adjusting zero to compensate for the weight of the injector and BHA when required. The weight
indicator system shall not be affected by conditions such as temperature changes or radio signals,
etc.
The injector head weight indicator system shall be equipped with a fail-safe transport-locking
device, i.e. the transport locking device shall either be fully locked or fully open.
Provisions shall be made for easy replacement of the weight indicator in the field and a back-up
weight indicator system shall be provided.
7.2.1.9 Depth counter system
At least two independent depth counters (one at the injector and one at the reel) shall be provided.
The injector head should be equipped with a system for monitoring tubing and chain slippage.
Provisions shall be made for installing a 3rd party depth counter system for logging services.
7.2.2 Tubing guide arch (gooseneck)
7.2.2.1
Mounting and support system
Provisions shall be made for easy installation and removal of the tubing guide arch on top of the
injector head.
The tubing guide arch and support base shall be designed to withstand the forces imposed by the
back-tension from the reel. On floating vessels the vessel movement will generate additional forces
that has to be accounted for.
A weak point may be built in to the tubing guide arch system for operations on floating installations.
The strength of the tubing guide arch must be documented.
Provisions shall be made for safe access of all the top rollers of the tubing guide arch.
7.2.2.2 Guide arch size (radius)
The minimum bending radius should as a guideline be 48 times the workstring diameter. Other sizes
tubing guide arch radiuses may be used if the fatigue life of the workstring is rated accordingly.
Reference is made to recommendations provided in API RP 5C7 [27].
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7.2.2.3 Guiding system
The tubing guide arch shall be provided with shaped rollers or a similar system for guiding the
workstring into the injector. A system to prevent the workstring from sliding off sideways shall also
be included.
Provisions shall be made for allowing the workstring to enter or exit the tubing guide arch tangent
to the curve of the tubing guide arch.
Provisions shall be made for allowing the workstring to enter or exit the tubing guide arch from the
angle made by spooling the workstring across the width of the reel. The tubing guide arch shall
support the side loads.
7.2.3 Injector support frame
The injector support frame system will normally be utilised for non-derrick operations.
The injector support frame system should be designed to withstand the expected dynamic, static and
bending forces it will be subjected to during normal operations. The operational limits for the
system shall be clearly identified to enable operation within the design criteria. When the injector
support frames are designed to transmit the load from the coiled tubing to the deck during
operations, the maximum pull- and snub force capacity of the injector head shall be included in the
design.
Provisions should be made for moving the injector 3 ways (up and down and sideways in 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
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System requirements well intervention equipment D-002
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connector plus the weight of the heaviest anticipated BHA and the forces required to open/unlatch
the quick connector.
The lifting frame should have an integrated hydraulic man rider winch that is remotely operable
from the work platforms in the lifting frame and/or from the rig floor.
Work platform(s) to access relevant working areas shall be provided.
The lifting frame shall have a system to guide and prevent horizontal movement of the injector
during operations.
Provisions should be made for handling and make/brake of BHA in the lifting frame.
Provisions shall be made for anchoring personnel safety harness at suitable areas.
7.3 Power package
The power package shall be capable of supplying sufficient power to operate all operating systems
of the coiled tubing unit on a continuous basis and at peak demand.
The power package shall be designed and sound proofed in accordance with NPD Regulations and
NORSOK standard S-002.
Provisions shall be made for a manual ESD system that is operated locally and remotely from the
control cabin.
The power package shall be certified for operating in Zone II areas and in accordance with
NORSOK standard Z-015.
Provisions shall be available at the injector head, control cabin or power unit, for individual
adjustment and pre-set of the operating limits for maximum pull and push forces to the injector
head. These shall be protected from adjustment during normal operating conditions.
If the power package is used for charging the accumulator system for the well control equipment,
the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic
circuits. Only the well control system shall be able to take hydraulic pressure from the dedicated
accumulators.
7.4
Coiled tubing workstring (steel coiled tubing)
The workstring shall have documented tractability, see API RP 5C7 [27] for guidance.
The workstring shall have documentation of fatigue cycle history, weld location, tapers, length,
property de-rating and inspection record.
The workstring shall meet the operational requirements with relation to maximum calculated
pressure, temperature, hydraulics, tension and compression. A tubing force calculation shall be
performed for each operation.
The workstring shall be leak tested and drifted prior to each mobilisation. Workstring with e-lineinstalled may be drifted if applicable.
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The workstring shall be quality checked (continuously inspected) and a verification report shall be
issued stating the status and suitability for the upcoming operation(s) prior to each mobilisation. The
tubing quality check shall as a minimum include wall thickness, surface condition, outside diameter,
corrosion, ovality and ballooning.
The workstring should be inspected continuously during the operation to maintain a real time string
condition record. The inspection prior to mobilisation may be omitted if the workstring is
continuously inspected during the operation.
The workstring shall never exceed more than 80 % of manufacturer's specified yield strength as
new. Any de-rating shall be according to recognised standards, e.g. API RP 5 C7 [27]
A system for maintenance and preservation (internal and external) of the workstring shall be in
place.
7.5
Coiled tubing reel
The coiled tubing reel shall be equipped with drip tray(s) and drains.
Access and work platforms shall be provided at suitable areas for normal operations.
The drive system shall be capable of driving the reel faster than the maximum (operating) speed of
the injector head. It shall provide the required tension necessary to bend the workstring over the
guide arch and onto the reel and provide sufficient torque to accelerate the reel drum from stationary
to maximum (operating) speed with the reel drum fully loaded of workstring filled with fluid.
The reel drive system shall be variable, adjusted and controlled from the control cabin.
The coiled tubing reel core diameter shall, as a minimum be 48 times the coiled tubing diameter. A
smaller core diameter can be utilised providing the fatigue life of the workstring is de-rated
accordingly.
The level wind system shall be designed to withstand the bending and side load forces from the
workstring. A guiding system with an override function shall be provided for proper spooling of the
workstring on and off the reel drum.
The level wind system should be equipped with a remotely operated tubing clamp.
The coiled tubing reel shall have a reel brake system that automatically engages with loss of
hydraulic power. This system must have provisions for manual override when operating on floating
vessels/semi-submersibles.
The coiled tubing reel shall have a brake system that is designed to prevent operation of the injector
head when the coiled tubing reel brake system is engaged.
An additional brake system should be installed and to be activated in the event of drive gear or
chain failure. This could either be a capillary brake system or an additional drive motor with internal
brake.
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System requirements well intervention equipment D-002
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The coiled tubing reel shall be equipped with a depth counter.
The coiled tubing reel shall have a pig and ball launcher system by-pass and an isolation valve
between the launcher and workstring end termination. The launcher system shall have an internal
diameter equal to or greater than the internal diameter of the workstring.
The workstring reel end termination shall be a qualified connection.
The coiled tubing reel shall be provided with additional piping as follows: Inlet and isolation valves,
swivel joint, pressure sensing device and connection point for pressure relief valve.
7.6 Control cabin
The control cabin shall have an ergonomic layout and be designed according to NPD Regulations
and NORSOK standard S-002.
The control cabin shall facilitate all necessary controls and monitoring equipment to operate 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;
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System requirements well intervention equipment D-002
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• engine throttle control;
• priority supply pressure.
d) stripper;
• upper and lower stripper control;
•
upper and lower stripper pressure.
e) BOP.
• shear and seal ram control;
• pipe ram control;
• slip ram control;
• BOP accumulator pressure supply;
• BOP control pressure;
• BOP fluid volume control (flow meter) (see also well control system clause 5).
Provisions shall be available at the injector head, control cabin or power unit, for 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;
• wellhead pressure;
• circulating pressure;
• depth;
• running and pulling speed.
The following parameters shall, as a minimum, be recorded:
•
time and date;• injector load (positive and negative);
• injector hydraulic system pressure;
• wellhead pressure;
• circulating pressure;
• depth;
• running and pulling speed;
• pump rate (unless recorded at the pump unit);
• required data for updating the workstring fatigue model.
7.8
Well control systemWell control system shall be in accordance with clause 5.
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7.9 BHA
7.9.1 General
The BHA shall be designed to withstand all expected downhole forces and conditions.
The BHA shall as a minimum consist of the following from top:
• end-connector;
• dual check valve (BPV). NOTE The dual check valve can be replaced with a tested plug.
7.9.2 End connector
The end-connector provides the interface between the workstring and the rest of the BHA. It is a
barrier element and shall have a working pressure rating equal to the maximum operating pressure.
The end connector shall be provided with dual seals on both sides and provide an internal and
external seal. The end-connector shall be qualified to withstand all forces (tension, compression 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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 51 of 68
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)
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System requirements well intervention equipment D-002
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8.2.3 Speed range requirements
8.2.3.1 Slick line
• Low speed: 500 m/h (1 600 ft/h) constant speed at outer diameter of drum.
• High speed: 10 000 m/hr (33 000 ft/h) constant speed at outer diameter of drum.
Logging speed range requirements - all size logging cables:
• Low speed: 90 m/hr (300 ft/h) constant speed at outer diameter of drum.
• High speed: 3 000 m/h (10 000 ft/h) constant speed at outer diameter of drum.
8.2.3.2 Fishing/braided line
• Low speed: 300 m/h (1 000 ft/h) constant speed at outer diameter of drum.
• High speed: 5 000 m/h (16 500 ft/h) constant speed at outer diameter of drum.
8.3 Control cabin
The control cabin shall have an ergonomic layout and be designed according to NPD Regulations.
The cabin shall have protection over windows facing upwards and equipped with splint safe
windows. There shall be minimum one extra seat
The control cabin shall facilitate all necessary controls and monitoring equipment to operate the
complete wireline unit. The controls and monitoring equipment shall as a minimum include and be
located such that operator at all times can read the following:
a) controls;
•
depth counter;• weight indicator;
• level wind control;
• reel brake;
• reel forward /reverse;
• cable speed when required for the operation.
b) BOP.
• shear seal ram;
• wireline rams;
•
BOP control pressure;• flow monitoring;
• BOP accumulator pressure.
8.4 Data acquisition
A data acquisition system should monitor and record the following parameters:
• depth;
• tension;
• cable speed;
•
tubing pressure.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
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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.
Provisions shall be made for a manual ESD system that is operated locally and remotely from the
control cabin.
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System requirements well intervention equipment D-002
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The power package shall be certified for operating in Zone II areas and in accordance with
NORSOK standard Z-015.
If the power package is used for charging the accumulator system for the well control equipment,
the hydraulic circuit from the well control accumulators shall be separate from the other hydraulic
circuits and only the well control system shall be able to take hydraulic pressure from the 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.
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System requirements well intervention equipment D-002
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8.13 Slick, braided and electrical line requirements
The slick line, braided line and electric line shall have a periodic wire inspection, preventive
maintenance program and be well conditions compatible.
Wire loaded to yield strength shall be replaced immediately
Wire log with relevant data shall be kept.
8.14 Down hole tools requirements
The following requirements apply:
a) wireline tool string components;
•
fishing neck on all components;• well condition compatible;
• there shall be fishing tools available on the location;
• Rockwell HRC 30-36 on low alloyed steel.
b) running and pulling tool components;
• fishing neck on all components;
• well condition compatible;
• Rockwell HRC 30-36 on low alloyed steel.
c) fishing tool components;
• fishing neck on all components;
• well condition compatible;
• rated for the exposed loads;
• Rockwell HRC 30-36 on low alloyed steel.
d) explosive tool components;
• well condition compatible;
•
fishing tools shall be available on location;
• pressure relief port for bleeding off trapped pressure;
• firing system independent of radio silence.
e) logging tools components.
• well conditions compatible;
• fishing tools shall be available on location.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 56 of 68
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
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System requirements well intervention equipment D-002
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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.
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System requirements well intervention equipment D-002
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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
a) name of equipment;
b) production number;
c) name of manufacturer and supplier;
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
The manufacture's quality control certificate and documentation shall include
a) name of equipment;
b) production number;
c) name of manufacturer and supplier;
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;
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System requirements well intervention equipment D-002
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g) inspection report, including non-destructive inspection of coiled tubing body and welds,
locations of all imperfections and details of drift ball test;
h) report from testing including testing conditions, and information on how testing has been carried
out. Minimum required is hydrostatic test report;
i) repair record;
j)
statement of manufacture and inspection signed by manufacturer and surveyor/surveying 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
The manufacture's quality control certificate and documentation shall include
a) name of equipment;
b) production number;
c) name of manufacturer and supplier;
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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
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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
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System requirements well intervention equipment D-002
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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
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System requirements well intervention equipment D-002
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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)
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 63 of 68
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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 64 of 68
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.
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 65 of 68
ANNEX C
(informative)
SNUBBING AND COILED TUBING WELL CONTROL SYSTEM RIG UP
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 66 of 68
ANNEX D
(informative)
WIRELINE WELL CONTROL SYSTEM RIG UP
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System requirements well intervention equipment D-002
Rev. 1, October 2000
NORSOK standard Page 67 of 68
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
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System requirements well intervention equipment D-002
Rev. 1, October 2000
[45] ISO 5208, Industrial valves – Pressure testing of valves.
[46] TBK 1-2, General rules for pressure vessels.