NORSOK STANDARD SYSTEM REQUIREMENTS COILED TUBING EQUIPMENT

Transcription

1 NORSOK STANDARD SYSTEM REQUIREMENTS COILED TUBING EQUIPMENT Rev. 1, January 1996

2 Please note that whilst every effort has been made to ensure the accuracy of the NORSOK standards neither OLF nor TBL or any of their members will assume liability for any use thereof.

3 Rev. 1, January 1996 CONTENTS 1 FOREWORD 2 2 SCOPE 2 3 NORMATIVE REFERENCES 2 4 DEFINITIONS AND ABBREVIATIONS Definitions Abbreviations 3 5 FUNCTIONAL REQUIREMENTS General Product/services Equipment/schematic/borderline Process/ambient conditions Performance and operational requirements Maintenance requirements Layout requirements Interface requirements Commissioning requirements 5 ANNEX A COILED TUBING EQUIPMENT REQUIREMENTS 6 ANNEX B WELL CONTROL SYSTEM REQUIREMENTS 8 ANNEX C PRIMARY WELL CONTROL SYSTEM 10 ANNEX D SECONDARY WELL CONTROL EQUIPMENT 11 ANNEX E TERTIARY WELL CONTROL SYSTEM (SAFETY HEAD) 12 ANNEX F COMPUTERISED DATA ACQUISITION SYSTEM (CDA) 13 ANNEX G MINIMUM DOCUMENTATION REQUIRED 14 NORSOK standard Page 1 of 15

4 Rev. 1, January FOREWORD NORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative to add value, reduce cost and lead time and remove 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 are jointly issued by OLF (The Norwegian Oil Industry Association) and TBL (The Federation of Norwegian Engineering Industries). NORSOK standards are administered by NTS (Norwegian Technology Standards Institution). The purpose of this industry standard is to replace the individual oil company specifications for use in existing and future petroleum industry developments, subject to the individual company's review and application. The NORSOK standards make extensive references to international standards. Where relevant, the contents of this standard will be used to provide input to the international standardisation process. Subject to implementation into international standards, this NORSOK standard will be withdrawn. 2 SCOPE This standard describes functional, performance and operational requirements for the coiled tubing equipment. 3 NORMATIVE REFERENCES API RP 16E API RP 53 ASTM A 370 ASTM A 450 ASTM E 18 ASTM E 94 ASTM E ISO ISO NACE MR0175 Design of control systems for drilling well control equipment Recommended practice for blow-out prevention equipment systems for drilling wells Test methods and definitions for mechanical testing of steel products Specification for general requirements for carbon, ferritic alloy, and austenitic alloy steel tubes Test methods for rockwell hardness and rockwell superficial hardness of metallic materials Guide for radiographic testing Hardness conversion tables for metals Formulae and calculation for casing, tubing, drill pipe and line pipe properties Specification for valves, wellhead and christmas tree equipment Sulphide stress cracking resistant metallic materials for oil field equipment 4 DEFINITIONS AND ABBREVIATIONS 4.1 Definitions Normative references Informative references Shall Shall mean normative in the application of NORSOK standards. Shall mean informative in the application of NORSOK standards. Shall is an absolute requirement which shall be followed strictly in order to conform with the standard. NORSOK standard Page 2 of 15

5 Should May Can Rev. 1, January 1996 Should is a recommendation. Alternative solutions having the same functionality and quality are acceptable. May indicates a course of action that is permissible within the limits of the standard (a permission). Requirements are conditional and indicates a possibility open to the user of the standard. The well control system is divided in the following three distinct logic groups, referenced from below the injector to the x-mas tree: Primary well control system designed to enable efficient coiled tubing operation, this is the strippers (stuffing boxes), the coiled tubing body and the dual flapper check valves, alternatively plugged end of the coiled tubing. Secondary well control system designed to meet or exceed requirements for a secondary barrier element as during normal drilling operations. As a minimum it consists of three independent rams; blind/shear, tubing, slip. Connections to this system shall be with metal to metal seal. Tertiary well control system, safety head. A separate independent shear/seal BOP fitted as close as possible to the wellhead with metal to metal seal connections and with an entirely independent closing unit. 4.2 Abbreviations None. 5 FUNCTIONAL REQUIREMENTS 5.1 General The coiled tubing unit and BOP systems shall be capable of handling the work string, well conditions and other work parameters specified by the work program. 5.2 Product/services Typical service performed by a coiled tubing unit: Pumping. Milling/drilling (junk-, scale-, window-, hole-). Clean-out. Lifting. Operate downhole tools (packers, plugs etc.). Fishing. Logging. Perforating. 5.3 Equipment/schematic/borderline The system normally consists of the following main items: Injector head w/control system and frame(s). Hydraulic power system. Coiled tubing reel assembly. Control cabin with data acquisition system. Rig-up equipment. Well control system. NORSOK standard Page 3 of 15

6 Rev. 1, January 1996 Coiled tubing w/ BHA. Fluid/nitrogen pump. 5.4 Process/ambient conditions The well control system with connected valves, hoses and piping shall be designed for the following conditions: Maximum well pressure 345 Bar (5000 psi) Maximum wellhead temperature 121ºC (250ºF) Minimum operating temperature -10ºC (14ºF) Formation fluids H2S CO2 Oil and water based drilling muds Brine Diesel Glycol Acid (inhibited) Cement slurry Nitrogen Well control and pilot hoses and connections shall be capable of withstanding 700ºC for minimum 15 minutes. 5.5 Performance and operational requirements Coiled tubing equipment: Ref. annex A. Well control system: Ref. annex B, C, D and E. 5.6 Maintenance requirements Maintenance program with defined frequencies and work scopes. Re-certification program. Non-conformance system. Documentation system. 5.7 Layout requirements Secure area of CT operations. Escape ways. Locate second (back-up) control panel for secondary well control system away from CT control house in safe area. Locate one control panel for tertiary well control system away from CT control house in safe area. Secure frames and injection head so that rig up can withstand 46 m/s (90 knots) wind. Secure high pressure lines. Sufficient illumination. NORSOK standard Page 4 of 15

7 Rev. 1, January Interface requirements Mechanic, electric, hydraulic and pneumatic connections shall be compatible with the rig or platform connections. 5.9 Commissioning requirements Function testing of all relevant coiled tubing unit components including all accessory equipment shall be performed prior to each job. Function testing and verification of the injector head positive and negative weight indicator system shall be performed prior to each job. Documentation/verification of acceptable rig up versus forces and bending momentums. Documentation/verification that coiled tubing downhole tools, well control systems, frames, injector head and pumps can handle expected work conditions inside set safety factors. NORSOK standard Page 5 of 15

8 Annex A Rev. 1, January 1996 ANNEX A COILED TUBING EQUIPMENT REQUIREMENTS Injector head: Variable gripping force designed to minimise tubing damage and prevent tubing slippage. Hydraulic motor and control system must provide accurate fine movement control in and out of the well. Replaceable gripper blocks. Fail safe system that will stop chains from moving if hydraulic power lost. Weight cells with both positive and negative weights. Hydraulic force control that can be pre-set and adjusted. Displayed in control cabin. Pressure with corresponding load and available hydraulic pressure. Pull capacity 140% of maximum expected work string weight. Snubbing capacity 120% of maximum anticipated snubbing force. Anchored on minimum 4 anchor points or alternative system with equal strength according to design criteria for the system to be used. Injector support frame: Withstand all dynamic, static and bending forces. For non-derrick operation. Anchored on minimum 4 anchor points or alternative system with equal strength according to design criteria for the system to be used. Lifting frame for floaters and semi-submersibles: Withstand maximum anticipated axial load. Contain a work window in which the injector head/stripper/bop can operate isolated from the motion of a floater. Integrated winch for independent handling of the injector, well control equipment and other hook-up equipment. The winch shall be remotely operable from the lifting frames work platform and the rig floor. Work platform at the lift frames' lower part. An injector guide system on the vertical frame members for supporting the injector to the lift frame during operation. Goose neck: Minimum arc radius equal to drum core diameter of the tubing reel. Shaped rollers. Withstand backforce from reel. Guide system to prevent the coiled tubing from sliding off the gooseneck sideways. Hydraulic diesel driven power unit: Capacity to continuously and simultaneously operate coiled tubing injector, reel drive and charging system. Manual ESD system. Overspeed on diesel engine: Gas detector on air inlet with audible/visible alarm. Zone 2 certified diesel engine. NORSOK standard Page 6 of 15

9 Annex A Rev. 1, January 1996 Highest permissible noise level: 90dB at 1m distance. Coiled tubing: Withstand all expected downhole forces. Drifted before each operation. Size of drift ball shall be acceptable for upcoming operation, and be larger than balls for tool operation. For coiled tubing strings with E-line installed or other obstructions, other ovality check shall be performed. Also see annex G. Reel: Fluid manifolds: Inlet and isolation valves, launcher with by-pass, rotary joint and isolation valves, pressure sensing device. String isolation valve upstream reel axle and swivel joint. Minimum core diameter (inches) 48 times coiled tubing outer diameter. Pressure relief valve upstream reel axle and swivel joint and with protection cap. Top end mechanically secured. Level wind system. Hydraulic motor. Drive speed higher than maximum injector speed. Adjustable back-force for preventing excessive pull on goose neck and with fail safe brake to prevent damage to coiled tubing and goose neck. Top termination with qualified high pressure connection. Control cabin: Light for minimum 30 minutes in control cabin if power is lost. Minimum 2 independent escape routes. Pump with diesel/combustion engine: Fluid end and engine designed to handle expected rate and pressure. Manual ESD system. Overspeed on diesel engine: Gas detector on air inlet with audible/visible alarm. Zone 2 certified diesel engine. Highest permissible noise level: 90dB at 1m distance. Depth metering: Fail safe with independent back-up system. Bottom hole assembly: Withstand all expected downhole forces It shall minimum consist of from top and down, end connector and double flapper/back-pressure valves. Double flapper back-pressure valves can be substituted with tested plug. Holding/mixing tank: Clean so as not to cause plugging in coiled tubing and bottom hole assembly. NORSOK standard Page 7 of 15

10 Annex B Rev. 1, January 1996 ANNEX B WELL CONTROL SYSTEM REQUIREMENTS BOPs: Minimum working pressure 345 bar (5000 psi). Minimum nominal bore for secondary and tertiary well control system equal to or greater than X- mas tree bore. Minimum pressure rating on BOP outlet flanges 345 bar (5000 psi). The secondary and tertiary well control system shall be equipped with a panel with alarm for low accumulator pressure, loss of power and low level of control fluid. There shall be separate motion selector valves for each BOP function in control panel. The motion selector valves must be located and arranged so that accidental operation does not occur. All rams to be interchangeable in all ram cavities, with the exception of rams equipped with oversized accumulator or booster for shearing. All types of rams to be capable of centring without damaging relevant pipe/tubing/line/against side loads. Each ram must have an external indicator showing open or closed position. Ram locking system required, to enable manually locking of the rams. There shall be documentary evidence that the pressure capacity of the accumulators are capable of operating the rams according to the design requirements. If alternative connections, they shall be qualified and certified to withstand the required forces and pressure integrity. Metal to metal seal, except for hydraulic quick union type connection between primary and secondary well control systems. This shall have flanged interface to the secondary well control system. Such a quick union shall on the down side have a nominal bore minimum equal to the nominal bore of the secondary well control BOP. Control panel which clearly indicates whether the valves are open or closed. Shear blind capability shall be available when the coiled tubing is unloaded, in tension or in compression. Hook-up valves to well control system: ID 50.8mm (2") nominal bore. Minimum pressure rating 345 bar (5000 psi). Check valves if used shall be of a flapper or cone design. All BOP outlets and inlets shall be with metal to metal seal connections. All BOP outlets and inlets shall be fitted with valves. Valves shall be bi-directional and have metal to metal sealing on the bore. One of the valves to BOP outlet or inlet shall be remotely operated. Valves and connections in primary well control system may be of a threaded design. Threaded connections are permissible only after the second valve away from the well/riser bore. Choke manifold: ID 50.8mm (2") nominal bore. Minimum pressure rating 345 bar (5000 psi). Piping: Minimum interconnecting pipe spools 50.8mm (2"). Minimum interconnecting piping pressure 345 bar (5000 psi). Associated valves and piping etc. to be of compatible size and ratings. NORSOK standard Page 8 of 15

11 Annex B Rev. 1, January 1996 Accumulators: All preventors in the secondary and tertiary well control systems shall be used as basis when calculating accumulator capacity. Sufficient capacity for three operations (close, open, close) plus 25% of the volume of one closing operation for each of the rams. Accumulator capacity shall be calculated according to the following minimum requirements: Sufficient volumetric capacity for three (3) operations (close, open, close) for all rams, plus 25% of the volume of one closing operation for each of the rams. Sufficient pressure capacity to enable cutting the coiled tubing in accordance with the following requirements: Sufficient remaining accumulator pressure to enable cutting of the coiled tubing after having used a volume corresponding to: - Closing and opening of one annular preventer. - Closing, opening and closing of one pipe ram. Alternatively a dedicated shear ram auxiliary pressure system may be installed to meet the minimum requirements for cutting the coiled tubing if the remaining accumulator pressure is insufficient to enable cutting after having performed operations as mentioned above. There shall be documentary evidence that the pressure capacity of the accumulators are capable of operating the rams according to the design requirements. Regulators in the system shall remain unaffected in the event of loss of power. Well control hoses and connections including pilot hoses for well control purpose: Fire resistant, capable of withstanding 700ºC for minimum 15 minutes. Riser: Minimum pressure rating 345 bar (5000 psi). Metal to metal seals. Designed to withstand the most unfavourable combination of expected forces that can be encountered during an operation. NORSOK standard Page 9 of 15

12 Annex C Rev. 1, January 1996 ANNEX C PRIMARY WELL CONTROL SYSTEM External system (strippers): Location: Above secondary well control system. Top stripper to be located at shortest possible distance from the traction chains to minimise buckling potential when snubbing. Design: Minimum working pressure 345 bar (5000 psi). Seal elements on the strippers to fit proper temperature range. Seal elements replaceable with coiled tubing located inside. Wear bushings replaceable with coiled tubing located inside. It shall be possible to remove 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. Strippers shall be a dual system that can be individually and hydraulically controlled from the control cabin. A relief system shall be incorporated if over-pressurisation may occur. Injection port on the strippers for corrosion inhibitor/lubricant injection. Port on the strippers for monitoring wellhead pressure. Pressure in the actuator on the strippers must be maintained regardless of prime mover operation. Backup hand pump or air pump operation. Hydraulic quick union type connection located between primary and secondary well control system. Such a quick union shall on the down side have a nominal bore min. equal to the nominal bore of the secondary well control BOP. There shall be flanged interface to the secondary well control system. If alternative connections, they shall be qualified and certified to withstand the required forces and pressure integrity. Internal system (dual flapper valves or plug and coiled tubing body): Withstand maximum expected collapse and burst pressures. Verified by surface testing. NORSOK standard Page 10 of 15

13 Annex D Rev. 1, January 1996 ANNEX D SECONDARY WELL CONTROL EQUIPMENT Design: Secondary well control system to be operable from control house and from secondary safe location. The system shall be separate from all other hydraulic circuits, i.e., only the BOP stack can take fluid from the storage accumulator. Minimum three independent rams: blind/shear, tubing, slip. Rams to be able to close and open against full working pressure. The maximum pressure the rams can open or close against, with 200 bar (3000 psi) operating pressure, to be stated. Hang off capacity compatible with coiled tubing weight. Equalising valves on the BOP system shall be an integral feature, providing pressure-equalising paths around the blind and the tubing rams. A side connection with metal to metal seal of at least 50.8mm (2") nominal bore is required below the shear rams. During operations, this connection will be closed with two full bore flanged isolating valves. One of the valves shall be remotely operated. Shear/blind rams: The shear/blind rams shall be a combined shearing and blind ram capable of shearing the coiled tubing and any pipe and cable inside the coiled tubing, and sealing the bore with lateral and face seals. The shear/blind ram will be designed to leave sufficient clearance between the top of the coiled tubing in the well/riser and the bottom of the ram to enable maximum circulation rates through the work string left in the well. Tubing rams: Tubing rams are required to close around the coiled tubing and seal off the annular space in the BOP bore. Rams must be installed according to the size of coiled tubing. Slip rams: Slip rams shall be compatible with all ram type BOPs except the shear and shear/seal BOPs. Slip rams are required to grip and hold the coiled tubing. They must be able to prevent up and down movement. Slip rams shall be of a design that minimises or avoids stress marking of the tubing. Annular preventer (if used): The annular preventer shall be able to close and seal off at 345 Bar (5000 psi) pressure on open hole. The annular BOP shall operate (close) on both stationary and running objects. The annular preventer shall be furnished with accumulators as a surge dampener for emergency stripping of coiled tubing. This also requires annular BOP operation pressure to be regulated from the control cabin as well as the remote location. NORSOK standard Page 11 of 15

14 Annex E Rev. 1, January 1996 ANNEX E TERTIARY WELL CONTROL SYSTEM (SAFETY HEAD) Design: Shear action must be possible with the maximum safe working pressure inside the safety head body The control system shall be completely independent and physically separated from the coiled tubing unit. The shear/blind rams shall be a combined shearing and blind ram capable of shearing the coiled tubing and sealing the bore. There shall be documentary evidence that the safety head will shear the intended size/wall thickness of coiled tubing, including any wire or cable or multiple coiled tubing (stacked) inside, and provide sealing effect after shearing. An equalising valve shall be an integral feature, allowing pressure equalising around the seal elements. Rams: Ram actuation on the safety head will be effected by hydraulic pressure applied from one remote control panel. NORSOK standard Page 12 of 15

15 Annex F Rev. 1, January 1996 ANNEX F COMPUTERISED DATA ACQUISITION SYSTEM (CDA) The coiled tubing unit shall be equipped with a CDA system to monitor and record the following parameters: Time and date. Injector load positive and negative weight. Injector hydraulic system pressure. Wellhead pressure. Coiled tubing pressure (circulating pressure). Depth. Running/pulling speed. Pump rate. Number of cycles over gooseneck with corresponding pressure. CDA system to be connected to back-up power supply. There shall as a minimum be backup data acquisition system registering injector load, positive and negative, wellhead pressure and coiled tubing pressure (circulating pressure). NORSOK standard Page 13 of 15

16 Annex G Rev. 1, January 1996 ANNEX G MINIMUM DOCUMENTATION REQUIRED Tubing injector head, well control system, valve arrangements, riser, lubricator, spools, high pressure piping and hoses, high pressure vessels: Name of equipment. Production number. Name of manufacturer and supplier. Description of design and manufacture, indicating safety factor used. Verification of design/strength control. Material certificates and confirmation as to where materials have been used. Welding procedure specifications. Statement of manufacture and inspection signed by manufacturer and surveyor/surveying firm/body. Report from testing including testing conditions, and information on how testing has been carried out 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 Supplier s operation and maintenance specifications, with indication of operational criteria/limitations. Marking of equipment. Updating of items in the case of modification of equipment. Weight and dimensions. Coiled tubing string: Manufactures quality control certificate and documentation: Name of equipment. Production number. Name of manufacturer and supplier. Description of design and manufacture, including safety factors used. Verification of design assumptions with regard to strength, carried out by an independent survey institution. Depending on organisational independence, this function may be taken care of by the manufacturer. Supplier s operation and maintenance specifications, with indication of operational criteria/limitations. Material certificates, including chemical analysis, mechanical strengths (hardness, tensile and yield) and physical dimensions. Inspection report, including non-destructive inspection of coiled tubing body and welds, locations of all imperfections and details of drift ball test. Report from testing including testing conditions, and information on how testing has been carried out. Minimum required is hydrostatic test report. Repair record. Statement of manufacture and inspection signed by manufacturer and surveyor/surveying firm/body. Weld procedure qualifications for welds, including x-rays. Weld log, including bias weld and butt weld locations. (Butt-) welding procedure specifications and inspection/verification specifications. Drying procedure used. NORSOK standard Page 14 of 15

17 Annex G Rev. 1, January 1996 Additional documentation: Log of tubing repairs, including: location of manufacturer's welds, location of section welds/tubing cut off/added/re-used. Reason for repair. Log of OD, ovality and wall thickness testing. Estimated cumulative damage and remaining life time, including evaluation and location of butt/field welds. Operational limits for outside diameter and wall thickness. History log of all previous jobs, including parameters influencing life time. Documentation on receiving-qc of the coiled tubing. Marking of equipment. Updating of items in the case of modification of equipment. Quality audit of the manufacturing process. Pre-job inspection and testing documentation. Downhole tools: Manufactures quality control certificate and documentation: Name of equipment. Production number. Name of manufacturer and supplier. Description of design and manufacture, indicating safety factor used. Verification of design assumptions with regard to strength, carried out by an independent survey institution. Depending on organisational independence, this function may be taken care of by the manufacturer. Material certificates and confirmation as to where materials have been used. Statement of manufacture and inspection signed by manufacturer and surveyor/surveying firm/body. Additional documentation: Receiving-QC of the tool. Marking of equipment. Updating of items in the case of modification of equipment. Quality audit of the maker's manufacturing process. Inspection report. Drawings showing internal parts/functions, overall length, maximum OD, minimum ID and weight. Tool description, function, maximum/minimum parameters. Strength calculations indicating safety margins. Operational manual/operating procedures. Function/operational testing. This does not replace acceptance test offshore before a job. Complete BHA drawings showing; total length, maximum OD, minimum ID, weight, position of tools and threads. Fishing data. NORSOK standard Page 15 of 15