D-002 Well Intervention Equipment

NORSOK Standard D-002

Revision 2, June 2013

Well intervention equipment

This NORSOK standard is developed with broad petroleum industry participation by interested parties in the Norwegian petroleum industry and is owned by the Norwegian petroleum industry represented by the Norwegian Oil and Gas Association and The Federation of Norwegian Industries. Please note that whilst every effort has been made to ensure the accuracy of this NORSOK standard, neither the Norwegian Oil and Gas Association nor The Federation of Norwegian Industries or any of their members will assume liability for any use thereof. Standards Norway is responsible for the administration and publication of this NORSOK standard.

Standards Norway Telephone: + 47 67 83 86 00 Strandveien 18, P.O. Box 242 Fax: + 47 67 83 86 01 N-1326 Lysaker Email: [email protected] NORWAY Website: www.standard.no/petroleum

Copyrights reserved

© NORSOK. Any enquiries regarding reproduction should be addressed to Standard Online AS. www.standard.no

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NORSOK standard D-002 Revision 2, June 2013

NORSOK standard 1

NORSOK Standard D-002

Well intervention equipment Contents 1� Scope ..................................................................................................................................................... 4�

2� Normative and informative references ................................................................................................... 4�2.1� Normative references ................................................................................................................... 4�2.2� Informative references ................................................................................................................. 5�

3� Terms, definitions and abbreviations ..................................................................................................... 6�3.1� Definitions .................................................................................................................................... 6�3.2� Abbreviations ............................................................................................................................... 7�

4� General requirements ............................................................................................................................. 8�4.1� Design principles .......................................................................................................................... 8�4.2� External standards ....................................................................................................................... 8�4.3� Applicability .................................................................................................................................. 8�4.4� Quality management systems ...................................................................................................... 8�4.5� Work string ................................................................................................................................... 9�4.6� Bottom hole assemblies ............................................................................................................... 9�4.7� Fluid pumps .................................................................................................................................. 9�4.8� Ignition source control .................................................................................................................. 9�4.9� Ambient conditions ..................................................................................................................... 10�4.10� Working environment ................................................................................................................. 10�4.11� Lifting equipment ........................................................................................................................ 10�4.12� Dropped objects ......................................................................................................................... 10�

5� Well control equipment ......................................................................................................................... 11�5.1� General ...................................................................................................................................... 11�5.2� Shear/seal rams ......................................................................................................................... 11�5.3� Safety head ................................................................................................................................ 11�5.4� BOP ............................................................................................................................................ 12�5.5� BOP and safety head control unit .............................................................................................. 12�5.6� Choke manifolds and choke lines .............................................................................................. 13�5.7� Kill lines ...................................................................................................................................... 13�5.8� Pump lines ................................................................................................................................. 13�

6� Snubbing .............................................................................................................................................. 14�6.1� General ...................................................................................................................................... 14�6.2� Stripper bowl .............................................................................................................................. 14�6.3� Dual stripper rams ...................................................................................................................... 14�6.4� Snubbing BOP ........................................................................................................................... 15�6.5� Snubbing unit ............................................................................................................................. 15�6.6� Jack/pulling unit .......................................................................................................................... 16�6.7� Work window .............................................................................................................................. 16�6.8� Slips............................................................................................................................................ 16�6.9� Control cabin .............................................................................................................................. 16�6.10� Work string ................................................................................................................................. 17�6.11� BHA ............................................................................................................................................ 17�6.12� Pipe handling ............................................................................................................................. 18�6.13� Tongs ......................................................................................................................................... 18�6.14� Winch package ........................................................................................................................... 18�6.15� Gin pole ...................................................................................................................................... 18� P

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2 NORSOK standard

6.16� Work basket ...............................................................................................................................18�6.17� Data acquisition ..........................................................................................................................18�6.18� Circulation system ......................................................................................................................19�

7� Coiled tubing .........................................................................................................................................19�7.1� General .......................................................................................................................................19�7.2� CT Strippers ...............................................................................................................................19�7.3� CT BOP ......................................................................................................................................19�7.4� Prevention of multiple strings through the BOP .........................................................................20�7.5� Injector head ...............................................................................................................................20�7.6� Tubing guide arch.......................................................................................................................21�7.7� Injector support frame and tower ...............................................................................................22�7.8� Injector tension frame .................................................................................................................22�7.9� Coiled tubing work string ............................................................................................................23�7.10� Coiled tubing reel .......................................................................................................................23�7.11� Control cabin ..............................................................................................................................24�7.12� Data acquisition ..........................................................................................................................25�7.13� BHA ............................................................................................................................................25�

8� Wireline .................................................................................................................................................26�8.1� General .......................................................................................................................................26�8.2� Pressure control head ................................................................................................................26�8.3� BOP ............................................................................................................................................27�8.4� Wireline unit ................................................................................................................................27�8.5� Control cabin ..............................................................................................................................28�8.6� Data acquisition ..........................................................................................................................28�8.7� Clamps .......................................................................................................................................28�8.8� Sheave wheels ...........................................................................................................................29�8.9� Pressure test pump ....................................................................................................................29�8.10� Wellhead pump ..........................................................................................................................29�

Foreword The NORSOK standards are developed by the Norwegian petroleum industry to ensure safety, value adding and cost effectiveness for petroleum industry developments and operations. Furthermore, NORSOK standards are, as far as possible, intended to replace oil company specifications and serve as references in the authorities' regulations.

The NORSOK standards are normally based on recognized international standards, adding the provisions deemed necessary to fill the broad needs of the Norwegian petroleum industry. Where relevant, NORSOK standards will be used to provide the Norwegian industry input to the international standardization process. Subject to development and publication of international standards, the relevant NORSOK standard will be withdrawn.

The NORSOK standards are developed according to the consensus principle generally applicable for most standards work and according to established procedures defined in NORSOK A-001.

The NORSOK standards are prepared and published with support by The Norwegian Oil and Gas Association, The Federation of Norwegian Industries, Norwegian Shipowners' Association and The Petroleum Safety Authority Norway. NORSOK standards are administered and published by Standards Norway.

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NORSOK standard 3

Introduction This revision was initiated to ensure a timely update of the standard and to harmonize it with applicable standards and regulations.

The following main changes are implemented in this revision:

� The well barrier terminology of the standard is harmonized to NORSOK D-010. � The requirements of safety heads have been expanded to reflect current expectations and

understanding. � External references have been updated and the number of references has been reduced. � Test requirements for pressure control equipment are further specified. � The structure is revised to increase readability.

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4 NORSOK standard

1 Scope The objective for this NORSOK standard is to provide common requirements for well intervention equipment across all exploration and production companies and service companies operating on the Norwegian Continental Shelf.

The standard defines what is considered typical and ordinary well intervention equipment. New equipment, special operations and operations in certain environments may require additional requirements and specifications. These specific additions are excluded from the standard and should be addressed in the risk assessment of the particular job. The general requirements in chapter 4 and 5 of this standard also apply to well intervention equipment falling outside traditional snubbing, coiled tubing and wireline.

2 Normative and informative references The following standards include provisions and guidelines which, through reference in this text, constitute provisions and guidelines of this NORSOK directive. 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 the requirements of the referenced standards.

2.1 Normative references

API 5ST, Specifications for Coiled Tubing

API 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment Second Edition

API RP 16ST, Coiled Tubing Well Control Equipment Systems

ATEX Directive, EU's directive 94/9/EC concerning equipment and protective systems intended for use in potentially explosive atmospheres

DNV-OS-E101, Drilling Plant

ISO 9001, Quality management systems – Requirements

ISO 10423, Petroleum and natural gas industries – Drilling and production equipment – Wellhead and Christmas tree equipment (API 6A)

ISO 13533, Petroleum and natural gas industries – Drilling and production equipment – Drill-through equipment (API 16A)

ISO 13628-7, Petroleum and natural gas industries – Design and operation of subsea production systems – Part 7: Completion/workover riser systems

ISO 15156-1, Petroleum and natural gas industries – Materials for use in H2S-containing environments in oil and gas production – Part 1: General principles for selection of cracking-resistant materials (NACE MR0175)

NORSOK D-001, Drilling facilities

NORSOK D-010, Well integrity in drilling and well operations

NORSOK N-001, Integrity of offshore structures

NORSOK S-001, Technical safety

NORSOK S-002, Working environment

NORSOK R-002, Lifting equipment

NORSOK R-003, Safe use of lifting equipment

NORSOK Z-015, Temporary equipment

Samarbeid for Sikkerhet, Handbook – Best Practice – Dropped Object Management

The Norwegian Oil and Gas Association, 070 – Application of IEC 61508 and IEC 61511 in the Norwegian petroleum industry P

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NORSOK standard 5

The Norwegian Oil and Gas Association, 081 – Norwegian oil and gas recommended guidelines for remote pipe handling operations

2.2 Informative references API RP 5C8, Recommended Practice for Care, Maintenance and Inspection of Coiled Tubing (when published)

PSA, Regulations relating to conducting petroleum activities (The Activities Regulations)

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6 NORSOK standard

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 can verbal form used for statements of possibility and capability, whether material, physical or causal

3.1.2 coiled tubing intervention using continuous tubing

3.1.3 intervention well servicing operations conducted within a completed wellbore

3.1.4 may verbal form used to indicate a course of action permissible within the limits of this NORSOK standard

3.1.5 maximum anticipated surface pressure the highest pressure predicted to be encountered at the surface of the well. This pressure prediction should be based upon formation pressure minus a wellbore filled with native formation fluid at current conditions. If formation fluid information is unknown, this pressure prediction should be based upon formation pressure minus a wellbore filled with dry gas from the surface to the completion interval.

3.1.6 maximum anticipated operating pressure the highest calculated pressure that a given equipment component will be subjected to during the execution of the prescribed service and/or during a contingency operation. The maximum anticipated operating pressure may be equal or greater than the maximum anticipated surface pressure.

3.1.7 rated working pressure maximum internal pressure that the equipment is designed to contain and/or control

3.1.8 safety head upper�closure�device�of�the�secondary�barrier

3.1.9 shall verbal form used to indicate requirements strictly to be followed in order to conform to this NORSOK standard and from which no deviation is permitted, unless accepted by all involved parties

3.1.10 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

3.1.11 snubbing intervention using jointed pipe and where the primary well control is at surface

3.1.12 wireline intervention using a continuous wire or cable

3.1.13 work string collective term for jointed pipe, coiled tubing and wireline, BHA excluded

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NORSOK standard 7

3.2 Abbreviations

API American Petroleum Institute

BHA bottom hole assembly

BOP blow out preventer

ESD emergency shut down

ISO International Organization for Standardization

IEC International Electrotechnical Commission

PSA Petroleum Safety Authority Norway

SIL safety integrity level

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8 NORSOK standard

4 General requirements

4.1 Design principles

An overall principle for well intervention activities shall be that no single failure shall entail a life-threatening situation for the involved personnel or lead to significant material or environmental damage. This shall constitute the basis for definition, revision, reduction and acceptance of risk with regards to well intervention activities.

The fulfilment of this principle shall be assessed on a system level. An intervention system includes, but is not limited to, equipment falling under the scope of this standard, auxiliary equipment, equipment permanently installed on the location and operational procedures.

Well intervention equipment shall be designed to withstand all loads it may be exposed to. Limitations shall be known to the users of the equipment.

The design and layout of well intervention equipment shall ensure a safe and efficient workplace.

4.2 External standards

Equipment under the scope of this standard will by default fall into at least one of the following categories and shall satisfy the requirements of the corresponding standards:

� topside pressure control equipment: ISO 10423 or ISO 13533; � subsea pressure control equipment: ISO 13628-7; � temporary equipment: NORSOK Z-015; � supporting structures: NORSOK N-001.

Furthermore, the equipment shall fulfil the requirements of additional external standards through direct references throughout the text.

Equipment potentially exposed to H2S shall be designed according to ISO 15156-1.

The intention of the above is not to provide an exhaustive list of all relevant standards and regulations. The majority of well intervention equipment will also fall within the scope of European directives and specific standards issued by API, ISO and IEC. It is the responsibility of the equipment manufacturers and those responsible for the use of the equipment to define the complete list of applicable standards and regulations for each individual product.

4.3 Applicability

This revision of NORSOK D-002 is applicable for all well intervention equipment manufactured after the 1st of July 2014. A gap analysis shall be available by the 1st of July 2014 for existing equipment to identify any non-conformances under NORSOK D-002 Revision 2.

All equipment under the scope of this standard shall comply with this revision no later than the 1st of July 2018.

4.4 Quality management systems

All suppliers that design, manufacture or sell well intervention equipment shall have a quality management system based on ISO 9001 or equivalent.

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NORSOK standard 9

4.5 Work string

Work strings shall have

� documented traceability, � historical use records, � periodic and systematic inspection.

Work strings shall meet all relevant operational requirements with respect to expected pressures, temperatures, chemicals, hydraulics, tension, compression and torque.

4.6 Bottom hole assemblies

The following information shall be documented for all parts of a BHA:

� dimensions, including fishing neck details; � maximum loads; � service temperature range; � chemical compatibility; � special consideration necessary for safe use.

4.7 Fluid pumps

Fluid pumps includes positive displacement pumps, electric or diesel driven, used for well intervention activities such as; flush and test circulation systems, testing of well barriers, circulation through work string, well stimulation and other pumping application that requires high volume or pressure. Pumps may also be used as well kill pumps for well intervention activities.

Fluid pumps shall have a pressure relief valve and an adjustable pressure limiting device. These two functions shall be independent of each other.

The pressure relief valve shall be set slightly above the maximum anticipated operating pressure. It shall be connected to discharge ports that are directed away from work areas.

The adjustable pressure limiting device shall be used to prevent excessive pressurisation of the connected surface equipment or the well. Pump units shall have, or be connected to, a data acquisition system to display and record operational parameters. The sampling rate shall be sufficient to record relevant parameter variations.

The following parameters shall, as a minimum, be monitored, recorded and available to the pump operator:

� time and date; � pump pressure; � wellhead pressure (if connected to a well); � annulus pressure of nearest annulus if connected to a well); � pump rate; � total volume of fluid pumped.

4.8 Ignition source control Equipment necessary to ensure and maintain well control is classified as safety critical equipment, group 3 according to NORSOK S-001 and should have emergency shutdown level c according to NORSOK Z-015. Such equipment shall as a minimum be classified as ATEX equipment-group II, category 3. The zone classification of the area where the equipment will be located might require category 2 or 1.

Equipment necessary to maintain the well intervention operation is classified as essential equipment, group 2 according to NORSOK S-001. This category includes snubbing units, coiled tubing units and wireline units. Pumps and other equipment are included in this group as far as they are necessary to maintain the current operation.

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10 NORSOK standard

Other auxiliary non-essential equipment falling outside the scope of group 3 and group 2 of NORSOK S-001 shall be in accordance with the general requirements to ignition source control given by NORSOK Z-015.

4.9 Ambient conditions

The well intervention equipment shall be designed and selected to operate under those ambient conditions that the equipment will be exposed to. These conditions may vary across different areas of operation.

The following should�be�used�as�default�conditions�unless�otherwise�specified:

� ambient temperature for storage: -20º C to +40º C; � ambient temperature for operation: -10º C to +40º C; � maximum humidity: 95 %.

It is the responsibility of the facility owner to define the ambient conditions at areas of operations deviating from these default conditions.

4.10 Working environment

The working environment for well intervention equipment shall be in accordance with NORSOK S-002, chapter 5 and Annex A, B, C and D.

External noise emissions from the equipment should be lower than 82 dB(A).

Control cabins shall satisfy the requirements for driller’s cabin in NORSOK S-002 Annex A while withstanding an external noise level impact of 90 dB(A). Control cabins shall be designed to be permanently manned. There should be at least one extra seat available inside the cabin.

4.11 Lifting equipment Lifting equipment shall be designed according to NORSOK R-002 and used according to NORSOK R-003.

4.12 Dropped objects Well intervention equipment shall be designed according to Handbook – Best Practice – Dropped Object Management, part 2, to reduce the risk of dropped objects.

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NORSOK standard 11

5 Well control equipment

5.1 General

NORSOK D-010 defines�well�barrier�requirements for well activities and is therefore indispensable for safe well intervention operations. NORSOK D-002 includes technical and functional requirements for some of the well barrier elements prescribed by NORSOK D-010, such as safety head.

The rated working pressure of all well control equipment shall be greater or equal to the maximum anticipated operating pressure for the planned activity.

The product specification level (PSL) of well control equipment shall be determined by ISO 10423 Annex A.

Ram-type BOPs and safety heads shall be designed, manufactured and tested according to ISO 13533, irrespective of their vertical through-bore dimensions.

All side inlets (excluding instrument and monitoring ports) above the BOP (e.g. for lubrication, chemical injection and grease injection) should be fitted with a check valve.

The pressure control stack should include measures to enable bleed off and to verify that no pressure is trapped prior to rig-down.

5.2 Shear/seal rams Shear/seal rams shall be able to shear the work string in use and seal the wellbore. This shall be tested according to ISO 13533 Annex C.2.3. Less than 90 % of the maximum force available shall be utilized during the shear test. The force required to close the rams against an elevated internal pressure shall be accounted for.

Shear/seal rams shall also be able to close and seal blind, i.e. without any work string present in the wellbore.

5.3 Safety head

Safety head is a shear/seal ram or valve with the following requirements:

� It shall fulfil the requirements of section 5.2 above. � Its control unit shall fulfil the requirement of section 5.5 below. � It shall be certified as equipment category I according to DNV-OS-E101. � The closing of a safety head shall have a minimum safety integrity level of 2 (SIL 2), calculated

according to Norwegian Oil and Gas Association guidelines 070 - Application of IEC 61508 and IEC 61511 in the Norwegian Petroleum Industry.

� It shall be installed in the proximity of the tree and with a minimum number of connections between the safety head and tree (to allow the work string to drop below the tree if activation is required).

These physical objects may be used as a safety head, given that the above requirements are met:

� the hydraulic master valve (HMV) of the production tree; � a separate shear/seal ram or valve; � a BOP shear/seal ram; � a lower riser package (LRP).

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12 NORSOK standard

5.4 BOP Basic BOP configurations for snubbing, coiled tubing and wireline are stated in chapter 6, 7 and 8, respectively.

API RP 16ST, section 4.3, may be referenced for the function of the various types of rams specified.

BOPs shall have the following features:

� mechanical lock of the rams in closed position that is capable of holding the rams in the closed position in the absence of closing pressure;

� either local indication of ram status or remote operated mechanical lock; � designed and dimensioned to suit the work string in use and maximum anticipated operating

pressure; � able to close while being exposed to maximum anticipated operating pressure; � cable rams, slip rams and pipe rams shall be able to centralize the work string without damaging

it.

5.5 BOP and safety head control unit The same control unit may be used for both the BOP and the safety head but it shall be independent of any other functionality. It shall meet the following requirements:

� Hoses and connections from the power unit to all rams shall be fire resistant, tested according to API 16D.

� The accumulator capacity shall as a minimum have sufficient volumetric capacity to close, open and close all installed functions plus 25% of the volume for one closing operation for each one of the functions.

� It shall be designed with a minimum of four independent cells / flasks for backup power and remain operational after the loss of one or more cells / flasks.

� It shall be capable of maintaining operation of its functions for a minimum of two hours if all external power is lost.

� It should be located along the most likely escape route for the operational personnel.

� There shall be at least two control panels / stations. Both shall include these functions:

� open and close;

� status indication of all functions;

� positive confirmation of ram/valve position (e.g. from flow measurement or ram position sensor);

� alarms for low accumulator pressure, loss of power supply and low level of control fluid.

� One control panel shall be located inside the control cabin.

� Control panels shall be designed to minimize the risk of unintentional operation.

� It shall take less than 30 seconds from the closing function is activated until confirmation of closure is obtained.

API 16D can be referenced when designing power units for intervention BOPs and safety heads.

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NORSOK standard 13

5.6 Choke manifolds and choke lines

Choke manifolds and choke lines should be designed according to API RP 16ST, chapter 8.

The choke manifold shall include two chokes where at least one is remotely operated.

The external choke manifold control panel shall at least indicate

� circulation pressure (internal pressure of work string ),

� pump rate,

� total volume pumped,

� choke position indicators,

� up and downstream pressure.

5.7 Kill lines

Kill lines should be designed according to API RP 16ST, chapter 9.

5.8 Pump lines

Pump lines should be designed according to API RP 16ST, chapter 10.

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14 NORSOK standard

6 Snubbing

6.1 General

The snubbing equipment with associated systems shall be capable of handling the work string, well conditions and other work parameters specified by the work program.

Most snubbing operation on the Norwegian Continental Shelf are performed as rig assisted snubbing (RAS) due to the requirement in PSA's Regulations relating to conducting petroleum activities § 89 for a remotely operated pipe handling system.

Rig assisted snubbing utilizes permanently installed equipment on the offshore installation in conjunction with snubbing equipment specifically mobilized for an operation. NORSOK D-002 does not intend to introduce additional requirements for permanently installed drilling equipment which is covered by NORSOK D-001.

Typically equipment mobilized for a rig-assisted snubbing operation is:

� well control equipment; � jack/pulling unit; � work window; � slips; � control cabin; � power pack; � work string and BHA.

The following additional equipment is typically mobilized for a stand-alone snubbing operation:

� pipe handling system; � tongs; � winch package; � gin pole; � workbasket; � data acquisition system; � circulation system.

The system shall be capable of handling work strings and casings and allow wireline work to be carried out.

6.2 Stripper bowl The stripper bowl housing shall include a gauge and bleed off port. It shall facilitate the installation of a wireline adapter.

6.3 Dual stripper rams The stripper rams shall be able to provide a seal on the snubbing annulus and fulfil the following requirements;

� they shall be suitable for stripping of the work string; � the response time for the stripper rams shall be less than 5 seconds; � they shall include an equalizing loop system with pressure monitoring; � the response time for equalization, bleed off, kill line and choke line valve shall be less than 1

second.

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NORSOK standard 15

6.4 Snubbing BOP Connections below the snubbing BOP shall have metal-to-metal seals.

A snubbing BOP shall as a minimum consist of the following:

� one combined shear/seal ram: � The design of the rams and the position of the kill line shall enable circulation through a

sheared work string after cutting. � two pipe rams, which shall

� be able to close around the work string and seal off the annular space in the bore, � have the capacity to hold the weight of the work string, � be designed to minimize stress marking of the work string.

� one annular preventer, which shall � be able to close and seal at the maximum anticipated operating pressure on open hole, � be able to close on both stationary and running objects, � allow stripping of the work string without inflicting any damage to it, � be equipped with a surge dampener accumulator for stripping of pipe and tubular.

� at least one choke line outlet; � at least one kill line inlet.

Outlets and inlets:

� Outlets and inlets on the BOP and below shall have metal-to-metal seals. � Outlets and inlets shall be fitted with either two bi-directional valves or be blocked. � The valves shall be bi-directional. � The inner valve, closest to the wellbore, shall be flanged. This inner valve shall not be used as a

working valve. Threaded connections can be used downstream of the first valve, away from the well and riser bore.

� A check valve shall be included if both valves are manually operated.

6.5 Snubbing unit The derrick, mast or hoisting structure shall be designed to withstand the loads and forces imposed by the relevant operational and environmental loads. The structure can also be used for support of pipe handling equipment and racked tubular on setback areas.

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 equipped with lifts, stairs or ladders for safe access. NORSOK D-001 can be used as a reference.

Lubrication points with difficult access in the workover area, such as sheaves, shall be routed to a readily accessible area. Sufficient number of hang off points of required capacity for travelling assembly, manual rig tongs and work winches shall be installed. All hang off points and/or pad eyes shall be properly marked with safe working load.

The snubbing unit working platform area shall have protection for dropped objects. It shall be able 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 a foundation for the structure/mast or hoisting structure and the snubbing unit working platform area and to provide required elevations and handling space for BOPs and optional 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.

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16 NORSOK standard

The complete design shall cater for lubrication (space out) of applicable BHA such as running and pulling perforating and gravel pack assemblies when rigged up on a live well.

6.6 Jack/pulling unit

The snubbing unit shall have a pulling and pushing (snub) capacity to the maximum expected and anticipated load for the operation.

All hoses in suspension from a connection shall be equipped with a quick disconnect locking feature.

The unit shall be equipped with an anti-buckling guide tube system to support the work string and the inside diameter to suit actual work string

6.7 Work window

The unit shall contain a work window assembly and the height shall be in accordance with the requirements in the work program.

The word window shall have a load rating greater or equal to the load rating of the jack and/or pulling unit, and include a device for hanging off the work string.

There shall be a work platform at the work window level.

6.8 Slips

The slips design rating shall be equivalent to at least the maximum thrust of the jack/pulling unit system, including a safety factor, and shall be remote operated.

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.

Dual redundant stationary snub slips should be used if the operator does not have visual contact with the slips.

6.9 Control cabin The following controls and monitoring equipment shall as a minimum be available from the control cabin:

� 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 (pipe heavy and pipe light); � wellhead pressure; � circulation pressure.

BOP:

� shear/seal ram control; � pipe ram control; � annular preventer control; � accumulator pressure; � control pressure; � ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

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Safety head:

� ram control; � ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

Additional requirements:

� The roof and windows shall provide protection against falling objects. � Jack "snub" and "heavy" force limitation shall be pre-set at the power pack. Local

adjustments in the workbasket or inside the cabin shall not override these settings. � 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. � Interlocks shall be provided to prevent inadvertent opening of the stationary and the travelling

heavy slips simultaneously. It shall be possible to manually override this interlock.

6.10 Work string

The connections in the work string above the check valves shall have two independent gas tight metal-to-metal seals. These seals shall withstand both internal and external pressure.

The work string shall be inspected and a verification report shall be issued prior to any offshore mobilization. The report shall as a minimum state that the string is approved and suitable for the planned operation.

The pull limitation shall during operations be set to maximum 80 % of the tensional yield of the work string.

6.11 BHA

6.11.1 General

The BHA shall as a minimum consist of the following:

� nipple profile; � two check valves.

A circulation sub with sufficient flow area is required if a ball operated release sub is to be run below the check valves.

The following equipment shall be available at location:

� four check valves; � drifts (two of each relevant size); � stabbing guides (two of each relevant size); � x-overs and overshots for fishing the work string; � pump down plugs for each nipple size specified in workover program; � two stabbing valves and necessary x-overs.

All parts of a BHA that will be exposed for hydraulic forces and/or rotation shall be inspected and a verification report shall be issued prior to any offshore mobilization. The report shall as a minimum state that the part is approved and suitable for the planned operation.

6.11.2 Landing nipple

A landing nipple shall be run above the check valves. Landing nipples have a profile that accepts a dart or plug and will seal the string in the event of a check valve failure. This enables the string to be pulled to surface in order to replace failed check valves.

Check valve pump through type darts may be used.

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6.11.3 Check valves

The check valves are a barrier element that prevents well fluids from entering the snubbing string and shall have a rated working pressure equal to the maximum operating pressure. The check valve connections shall have dual seals that can withstand both internal and external pressure.

Provisions shall be made for pumping balls and darts through the check valves.

6.12 Pipe handling

The snubbing unit shall be equipped with a remote pipe handling system fulfilling the requirements of Norwegian Oil and Gas Association guidelines 081 – Norwegian oil and gas recommended guidelines for remote pipe handling operations.

6.13 Tongs

Tongs shall be remote operated.

6.14 Winch package

The following requirements shall be met if a winch package is mobilized for the operation:

� It shall contain an automatic fail-safe brake in the event of a power failure. � It shall be a dual type counterbalance winch. � It shall include a drip pan.

6.15 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) accommodates the pipe length (Range II or III) plus safety valve, circulation swivel, swivel with tackle and a reserve air gap of minimum 1,0 m.

The system shall contain a hydraulic arrangement for raising and lowering of the gin pole.

6.16 Work basket

The travelling head area shall be equipped with removable internal handrail to guard against the rotating work string if the jack and pulling unit is designed with a workbasket.

The workbasket shall have two independent escape exits and be equipped with wind walls for weather protection. A work string mark board shall be included in the workbasket area for operator quick reference of work string depth.

6.17 Data acquisition

The snubbing unit shall be equipped with a data acquisition system to display and record operational parameters. The sampling rate shall be sufficient to record relevant parameter variations. A system for analysing the recorded data shall be available at the location.

The following parameters shall, as a minimum, be monitored and recorded:

� time and date; � work string weight, positive and negative (heavy and snub); � jack hydraulic system pressure; � wellhead pressure; � work string pressure; � work string depth; � rig and slip hydraulic pressure; � rotary torque and revolutions per minute; � work string connection torque.

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6.18 Circulation system

The pin connection on the swivel shall be compatible with the safety valve.

The minimum circulation hose length shall be equal to one single joint and end connection equipped with safety clamps and chain.

7 Coiled tubing

7.1 General A coiled tubing unit with associated systems shall be capable of handling the work string, well conditions and other work parameters specified by the work program. This section describes the minimum functional requirements for a coiled tubing unit with associated equipment.

The well intervention system for coiled tubing consists typically of the following main items:

� well control equipment; � injector head; � tubing guide arch (gooseneck); � injector frames; � power package; � coiled tubing work string; � coiled tubing reel; � control cabin; � data acquisition system; � BHA.

7.2 CT Strippers The coiled tubing strippers shall fulfil the following requirements;

� A dual stripper or two separate single strippers shall be used. � They shall be individually controlled from the control cabin. � The stripper shall be able to maintain a pressure seal with a static work string even if the

external power supply is lost. � The stripper sealing elements shall be designed for the maximum anticipated operating

pressure and temperature. � The control system shall include measures to avoid excessive forces and collapse of the

work string. � The sealing elements, extrusion rings and wear bushings shall be replaceable with coiled

tubing running through. � The primary stripper shall have redundant pumps. � An injection port shall be incorporated between the upper and lower stripper to enable

injection of inhibitors and lubricants. � The interface between the injector and upper stripper shall be designed to minimize the

buckling failure potential.

7.3 CT BOP Connections below the coiled tubing BOP shall have metal-to-metal seals.

A coiled tubing BOP shall as a minimum be able to:

� seal blind, i.e. without any work string present in the wellbore; � shear the coiled tubing in use and then seal afterwards;

� The design of the rams and the position of the kill line shall enable circulation through sheared coiled tubing after cutting.

� hold the weight of the coiled tubing; Pro

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� It shall be designed to minimize stress marking of the work string. � close around the work string and seal off the annular space in the bore; � provide one kill line inlet.

Outlets and inlets:

� Outlets and inlets on the BOP and below shall have metal-to-metal seals. � Outlets and inlets shall be fitted with either two bi-directional valves or be blocked. � The inner valve, closest to the wellbore, shall be flanged. This inner valve shall not be used

as a working valve. Threaded connections can be used downstream of the first valve, away from the well and riser bore.

� A check valve shall be included if both valves are manually operated. Additional requirements:

� An annular preventer, if used, shall fulfil the requirements of an annular preventer for snubbing, specified in section 6.4.

� A remote operated quick latch type connection should be utilized between the lower stripper and the coiled tubing BOP.

� A work window may be utilized between the lower stripper and the coiled tubing BOP. The window's 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 union type.

7.4 Prevention of multiple strings through the BOP There shall be at least two independent technical measures to prevent the accumulation of multiple strings of severed coiled tubing through the BOP and safety head in�the�event�of�a�compression�failure�of�the�work string�below�the�stripper. Such measures can for instance be based on drive load limitations, weight indicator shut down system or a physical restriction above the BOP.

7.5 Injector head

7.5.1 General

The injector head shall be sized for the simulated loads and for the specific coiled tubing size. The maximum pull load should not exceed 80 % of the injector head pull capacity. The injector head shall have sufficient pushing (snub) capacity to overcome the maximum expected load.

Contingency measures (e.g. change of fluids in wellbore, mechanical friction reducers etc.) to reduce the pulling force required for coiled tubing string removal from wellbore may be considered.

7.5.2 Base structure and outer frame

The injector head base structure shall be designed to withstand the maximum pull and push force of the injector. The base structure should be equipped with drip trays and drains.

The outer frame structure shall provide a base for the tubing guide arch (goose neck) 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 securing and stabilizing the structure and frame.

7.5.3 Drive chain system The drive chain system shall be capable of handling the maximum weight of the work string with minimum damage to the coiled tubing string.

The drive chain shall be field replaceable or equipped with replaceable gripper blocks..

7.5.4 Traction system

The traction force shall be adjustable from the control cabin and be capable of generating sufficient friction to push or pull the work string at maximum rated loads without slippage or damage to the work string. P

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The traction system shall have a fail-safe device preventing loss of traction

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.

7.5.5 Tension system The chain tension system should be adjustable from the control cabin and be capable of applying tension to the injector chain sufficiently to avoid damage to bearings and the coiled tubing work string.

The tension system should be provided with an accumulator system at the injector head.

7.5.6 Drive system

The 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 drive system shall be capable of pushing or pulling the maximum rated load at a speed of 10 m/min.

The system shall be fail-safe and stop the chains from moving if power is lost.

Charts showing the relationship between the injector drive force and the load shall be provided.

Provisions shall be made for drive lockout when the reel brake or remote tubing clamp system is engaged.

7.5.7 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 power is lost.

7.5.8 Weight indicator

Dual electronic strain gauge is to be used under CT operations. This weight indicator system shall be capable of measuring all tensile and compressive forces (positive and negative weights) in the work string above the stripper.

Two weight measurements shall be available:

� Actual weight below injector head. � Differential weigh that can be zeroed as needed. This can be used to monitor the forces

acting on the BHA.

The weight indicator shall be protected against any transport and storage damage.

Provisions shall be made for easy replacement of the weight indicator in the field and a back-up weight indicator system shall be provided.

7.5.9 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.

7.6 Tubing guide arch

7.6.1 Mounting and support system Provisions shall be made for easy installation and removal of the tubing guide arch (gooseneck) on top of the injector head.

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22 NORSOK standard

The tubing guide arch and support base shall be designed to withstand the forces imposed by the back-tension from the reel. The vessel movement will on floating facilities generate additional forces that have to be accounted for. A weak point may be built in to the tubing guide arch system for operations on floating facilities.

Provisions shall be made for safe access of all the top rollers of the tubing guide arch.

7.6.2 Guide arch size (radius)

The minimum bending radius should be 48 times greater than the work string diameter. Other sizes tubing guide arch radius may be used if the fatigue life of the work string is rated accordingly. Reference is made to the recommendations provided in API RP 16ST.

7.6.3 Guiding system

The tubing guide arch shall be provided with shaped rollers or a similar system for guiding the work string into the injector. A system to prevent the work string from sliding off sideways shall also be included.

Provisions shall allow the work string to enter the tubing guide arch tangential to the curve of the tubing guide arch.

Provisions shall allow the work string to enter or exit the tubing guide arch from the angle made by spooling the work string across the width of the reel. The tubing guide arch shall support the side loads.

7.7 Injector support frame and tower

Injector support frames and towers are designed to be utilized on fixed platforms and jack-up rigs.

The injector frame system shall be designed to withstand the expected dynamic, static and bending forces it will be subjected to during operations. The operational limits for the system shall be clearly identified to enable operation within these limits.

Provisions shall be made for moving the injector 3 ways (up and down and sideways in north-south and east-west directions). Work platforms to access relevant working areas shall be provided. Provisions shall be made for anchoring personnel safety harness at suitable areas.

Provisions shall be made for handling BHA in compliance with lifting requirements, and make/break using torque machine.

Provisions shall be made for anchoring at minimum four anchor points or alternative system with at least equal strength and reliability, according to design criteria for the system to be used.

When using multiple intersections, such as stacking of tower modules, provisions shall be made for an intersection anchoring system at all corners with equal strength according to design criteria for the system to be used.

7.8 Injector tension frame

Coiled tubing tension frames are designed to be utilized on-board floating facilities.

The tension 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 tension frame shall have an integrated lifting system for independent handling of the injector, well control equipment and other hook-up equipment. The winch to lift the injector head shall not be pneumatically powered. The lifting system shall be remotely operable from a safe working area away from moving parts and hanging loads. It shall be capable of lifting the injector head with a speed that is higher than the vertical motion of the floating facility. The load capacity shall minimum be 30 % above the weight of the injector head assembly above the quick connector plus the weight of the heaviest anticipated BHA and the forces required to open/unlatch the quick connector.

The tension frame should have an integrated man rider winch that is remotely operable from the work platforms in the lifting frame and/or from the rig floor.

The tension frame should have a horizontal travel arrangement for the injector to enable changing the BHA without suspending the injector by a winch or lower it to the ground. P

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Work platform(s) to access relevant working areas shall be provided.

The tension frame shall have a system to guide and prevent horizontal movement of the injector during operations.

Provisions shall be made for handling BHA in compliance with lifting requirements, and make/break using torque machine.

Provisions shall be made for anchoring personnel safety harness at suitable areas.

7.9 Coiled tubing work string

Coiled tubing work strings shall be manufactured, inspected and tested according to API 5ST.

A fatigue prediction model shall be used to estimate the remaining bend-cycle fatigue life.

A tubing force calculation shall be performed for each operation to confirm suitability of the selected work string. The work string shall not exceed more than 80 % of the manufacturer's specified yield strength as new.

The work string shall be leak tested and drifted prior to each mobilisation. Work string with e-line installed may be drifted if applicable.

The work string 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 (continuously inspected) shall as a minimum include wall thickness, surface condition, outside diameter, corrosion, ovality and ballooning.

If the work string has been quality checked (continuously inspected) and not mobilized offshore, the quality check is valid for six months if stored under proper condition. The inspection prior to mobilisation may be omitted if the work string is continuously inspected during the operation. Inspection records shall be kept as part of work string records.

A system for care, maintenance and periodic inspections of used coiled tubing pipe shall be in place. API RP 5C8 may be referenced for such systems.

7.10 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 work string 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 work string filled with fluid.

The reel drive system shall be variable, adjusted and controlled from the control cabin.

The coiled tubing reel core diameter should be 48 times the coiled tubing diameter.

The level wind system shall be designed to withstand the bending and side load forces from the work string. A guiding system with an override function shall be provided for proper spooling of the work string on and off the reel drum.

The coiled tubing reel shall have a reel brake system that automatically engages with loss of power. This system shall have provisions for manual override when operating on floating facilities.

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 shall be installed to be activated in the event of drive gear or chain failure. This could either be a capillary brake system or an additional drive motor with internal brake.

The coiled tubing reel shall be equipped with a depth counter.

The coiled tubing reel shall have a pig and ball launcher system by-pass and an isolation valve between the launcher and work string end termination. The launcher system shall have an internal diameter equal to or greater than the internal diameter of the work string.

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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.

7.11 Control cabin

The following controls and monitoring equipment shall as a minimum be available from the control cabin:

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); � speed indicator; � 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; � circulation pressure; � reel back tension pressure; � reel brake pressure.

c) power package: � normal stop control; � ESD control; � engine throttle control; � priority supply pressure.

d) stripper: � upper and lower stripper control; � upper and lower stripper pressure.

e) BOP: � blind ram control; � shear ram control; � slip ram control; � pipe ram control; � accumulator pressure; � control pressure; � ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

f) safety head:

� ram control;

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� ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

Adjustment of the operating limits for maximum pull and push forces to the injector head shall be available. These shall be protected from adjustment during normal operating conditions.

7.12 Data acquisition The coiled tubing unit shall be equipped with a data acquisition system to display and record operational parameters. The sampling rate shall be sufficient to record relevant parameter variations. A system for analysing the recorded data shall be available at the location.


� time and date; � weight (positive and negative weight); � injector drive pressure supply pressure; � wellhead pressure; � circulation pressure; � depth; � speed; � pump rate (unless recorded at the pump unit); � required data for updating the work string fatigue model.

7.13 BHA

7.13.1 General

The BHA shall be designed to withstand all expected downhole forces and conditions.

It shall as a minimum consist of the following:

� tubing end-connector; � two check valves.

A circulation sub with burst disc and sufficient flow area is required if a ball operated release sub is to be run below the check valves. Four check valves shall be available at location.

All parts of a BHA that will be exposed for hydraulic forces and/or rotation shall be inspected and a verification report shall be issued prior to any offshore mobilization. The report shall as a minimum state that the part is approved and suitable for the planned operation.

7.13.2 End-connector

The end-connector provides the interface between the work string and the rest of the BHA. It is a barrier element and shall have a rated working pressure 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 able to withstand all forces (tension, compression and torsion) that it may be subjected to from the BHA and the work string.

7.13.3 Check valves

The check valves are a barrier element that prevents well fluids from entering the coiled tubing and shall have a rated working pressure equal to the maximum operating pressure. The check valve connections shall have dual seals that can withstand both internal and external pressure. Provisions shall be made for pumping balls and darts through the check valves.

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8 Wireline

8.1 General The wireline unit with associated systems shall be capable of handling the BHA, well conditions and other work parameters specified by the work program. This section describes the minimum functional requirements for a wireline unit with associated equipment.

The well intervention system for wireline consists typically of the following main items:

� well control equipment; � wireline winch; � control cabin; � data acquisition system; � pressure test pump; � wellhead pump; � logging container (for logging and well tractor); � clamps; � sheaves; � wireline mast (crane); � transport and storage racks; � BHA (mechanical and electrical tool strings).

8.2 Pressure control head

The pressure control head shall be able to create both a static and dynamic seal around the cable. The seals of the pressure control head shall be designed for the maximum anticipated operating pressure and temperature and suit the work string in use.

The pressure control head shall be controllable from at least two positions. One of these shall be inside the control cabin.

The pressure control head is a stuffing box for cables with a slick/smooth surface and a grease injection head for braided cables.

The number of grease inlets and flow tubes shall be evaluated based on the maximum anticipated operating pressure, cable size and well fluids.

The grease injection skid shall have more than one grease pump and facilitate a grease tank. It shall be possible to change from one grease pump to another without reducing the injection pressure. The grease injection capacity shall exceed 0,75 l/min per pump at the maximum anticipated operating pressure.

A line wiper shall be installed to reduce grease spill from cable.

The pressure control stack shall include a device to stop hydrocarbon leaks in the absence of any cable.

A tool catcher or tool trap should be included to prevent the BHA from falling back into the well should the cable accidentally be pulled out of the cable head or rope socket.

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8.3 BOP

Connections below the wireline BOP and the safety head may have elastomer seals.

The wireline BOP shall close around the cable and seal off the annular space in the bore.

A single slickline ram is used for cables with a slick/smooth surface.

Dual wireline rams are used for braided cables. The upper ram is designed to seal against pressure from below and the lower to seal against pressure from above. Grease injection shall be provided between the two rams to provide and sustain a complete seal. The grease injection capacity shall exceed 0,75 l/min at the maximum anticipated operating pressure and shall be supplied from a designated pump.

A shear/seal ram (that may be designated as the safety head) may be incorporated into the same body/unit as the BOP.

Outlets and inlets:

� Outlets and inlets on the BOP and below shall be fitted with either two bi-directional valves or be blocked.

� The inner valve, closest to the wellbore, shall be flanged. This inner valve shall not be used as a working valve. Threaded connections can be used downstream of the first valve, away from the well and riser bore.

� One valve shall be remotely operated. � A check valve shall be included if both valves are manually operated.

8.4 Wireline unit

8.4.1 General

A wireline unit shall have the following performance with respect to speed, pull, acceleration and wire size:

Cable size Creep speed [m/min]

(outer diameter)

Full speed [m/min]

(inner diameter)

Max pull [kg] (outer diameter)

Acceleration [m/s2]

(outer diameter)

< 3/16" < 5 > 150 > 1500 > 2

� 3/16" � 7/32"

< 2 > 80 > 3000 > 1

> 7/32" < 0,5 > 60 > 5000 > 0,5

The wireline unit shall have an automatic shut-down function to prevent excessive wire tension.

8.4.2 Brake A wireline unit shall have a brake which is independent of its drive system. The brake shall have a holding capacity equal to the maximum pull. The drive system shall be capable of controlling the load until the brake can be activated.

8.4.3 Tension indicator

Two tension readings shall be available:

� Actual tension in the string. � Differential tension that can be zeroed as needed. This can be used to monitor the forces

acting on the BHA.

There shall be at least two independent tension sensors. The tension indicator system shall have a measurement accuracy better than ± 0,5 % of full scale.

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8.4.4 Depth counter system

Two independent depth counters shall be provided. At least one of them shall have an measurement accuracy of ± 0,03 %.

8.5 Control cabin The following controls and monitoring equipment shall as a minimum be available in the control cabin:

a) wireline unit: � in hole- and out of hole control; � high/low gear or displacement control (if applicable); � depth counter; � tension indicator; � speed indicator; � level wind override (right and left) control; � level wind rise and lower control (if applicable); � brake controls.

b) pressure control head: � wellhead pressure; � regulation of the pressure control head.

c) BOP: � wireline ram control; � grease injection control (if applicable); � accumulator pressure; � control pressure; � ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

d) safety head:

� ram control; � ram status; � alarms for low accumulator pressure, loss of power supply and low level of control fluid.

It shall be possible to adjust the maximum available pull force of the winch.

8.6 Data acquisition

The wireline unit shall be equipped with a data acquisition system to display and record operational parameters. The sampling rate shall be sufficient to record relevant parameter variations. A system for analysing the recorded data shall be available at the location.


� time; � depth; � tension; � speed.

8.7 Clamps

Wireline clamps are designed for securing and pulling during normal wireline operations. They are neither certified nor suited for lifting.

Fishing clamps are designed for securing and pulling the wireline during fishing operations. They shall be certified as lifting equipment. All locking devices for the fishing clamps shall have a double safety feature.

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8.8 Sheave wheels

Sheave wheels and their hang off points shall have a load rating greater or equal to twice the breaking strength of the cable in use.

The diameter of sheave wheels should be in accordance with the manufacturer’s recommendations.

8.9 Pressure test pump They shall have a pressure recorder included on the pump and equipped with a liquid tank.

Pressure pumps shall have the following capacities related to required working pressure:

Pump pressure 1 kpsi 5 kpsi 10 kpsi 15 kpsi

Minimum pump rate 30 l/min 3 l/min 1,0 l/min 0,5 l/min

8.10 Wellhead pump

Wellhead pumps are used to have local exclusive control over the hydraulic master valve (HMV) and / or the downhole safety valve (DHSV) during well intervention.

A wellhead pump should have two separate pumps in the unit/skid.

Each pump shall include the following functions:

� pressure gauge;

� pressure relied valve to protect the connected system and pump for overpressure;

� adjustable output.

The pumps shall have a rated working pressure as required for the operation.

Wellhead pumps should be located along the most likely escape route for the operational personnel.

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D-002 Well Intervention Equipment

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Transcript of D-002 Well Intervention Equipment