Recommended Practice for Subsea Pumping Well Intervention Systems API RECOMMENDED PRACTICE 17G2 FIRST EDITION, JANUARY 2016 WORKING DRAFT 1

Transcription

1 Recommended Practice for Subsea Pumping Well Intervention Systems API RECOMMENDED PRACTICE 17G2 FIRST EDITION, JANUARY 2016 WORKING DRAFT 1

2 Special Notes API publications necessarily address problems of a general nature. With respect to particular circumstances, local, state, and federal laws and regulations should be reviewed. Neither API nor any of API's employees, subcontractors, consultants, committees, or other assignees makes any warranty or representation, either express or implied, with respect to the accuracy, completeness, or usefulness of the information contained herein, or assumes any liability or responsibility for any use, or the results of such use, of any information or process disclosed in this publication. Neither API nor any of API's employees, subcontractors, consultants, or other assignees represent that use of this publication would not infringe upon privately owned rights. API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any authorities having jurisdiction with which this publication may conflict. API publications are published to facilitate the broad availability of proven, sound engineering and operating practices. These publications are not intended to obviate the need for applying sound engineering judgment regarding when and where these publications should be utilized. The formulation and publication of API publications is not intended in any way to inhibit anyone from using any other practices. Any manufacturer marking equipment or materials in conformance with the marking requirements of an API standard is solely responsible for complying with all the applicable requirements of that standard. API does not represent, warrant, or guarantee that such products do in fact conform to the applicable API standard. All rights reserved. No part of this work may be reproduced, translated, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise, without prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L Street, NW, Washington, DC Copyright 2016 American Petroleum Institute

3 API Foreword Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent. Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent. Shall: As used in a standard, shall denotes a minimum requirement in order to conform to the specification. Should: As used in a standard, should denotes a recommendation or that which is advised but not required in order to conform to the specification. This document was produced under API standardization procedures that ensure appropriate notification and participation in the developmental process and is designated as an API standard. Questions concerning the interpretation of the content of this publication or comments and questions concerning the procedures under which this publication was developed should be directed in writing to the Director of Standards, American Petroleum Institute, 1220 L Street, NW, Washington, DC Requests for permission to reproduce or translate all or any part of the material published herein should also be addressed to the director. Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least every five years. A one-time extension of up to two years may be added to this review cycle. Status of the publication can be ascertained from the API Standards Department, telephone (202) A catalog of API publications and materials is published annually by API, 1220 L Street, NW, Washington, DC Suggested revisions are invited and should be submitted to the Standards Department, API, 1220 L Street, NW, Washington, DC 20005, standards@api.org.

4 Table of Contents [To Be Completed Prior to Publication]

5 Introduction This recommended practice is a supplementary document to API 17G and pertains to subsea pumping well intervention systems. The purpose of a subsea pumping well intervention system is to pump fluid into or out of a subsea well. Pumping operations into or out of a flow line/pipe line or a subsea storage unit will not be addressed due to barrier philosophy differences. This document does not cover flow backs even though it is understood that the system is to be designed and operated in the presence of residual hydrocarbons in small quantity but not a full flow back scenario. Subsea pumping systems typically involve a spooled fluid conduit with the fluid conduit not being rigidly attached to the subsea well similar to a top tensioned intervention riser system. No tooling is conveyed through the fluid conduit, therefore, the mode of operation for these subsea pumping well intervention systems is considered to be riserless. Commonly used fluid conduits typically consist of internally welded coil tubing, composite lines, umbilical lines, and other spooled products but can included jointed pipe. A subsea pumping well intervention system consists of a group of components and equipment packages that could comprise a standalone system or may supplement part of the permanent installed subsea system infrastructure operated together as a system. The whole of the system needs to meet all the requirements of API 17G as modified or amended by this document. The development of this document is based on input from API Subcommittee 17 (Subsea Production Systems) technical experts. The technical revisions have been made in order to accommodate the needs of industry and to move this specification to a higher level of service to the petroleum and natural gas industry. This document is not intended to inhibit a manufacturer from offering, or the purchaser from accepting, alternative equipment or engineering solutions for a specific application. This may be particularly applicable where there is innovative or developing technology.

6 1 Scope This recommended practice states the requirements and gives recommendations for the performance, design, analysis, materials, fabrication, inspection, testing, welding, marking, handling, storing, shipment, purchase, operation, and recertification of subsea pumping well intervention systems deployed from a mobile offshore work unit such as a Multi-Purpose Vessel. The work unit is assumed to be classified to handle low flashpoint liquids, minor amounts of gas, well effluent, and the chemicals pumped into or out of the well. This document contains the system level requirements and recommendations, and where not found elsewhere the information that applies to individual components. To the greatest extent possible, this document points the reader to the API document that is applicable to each system component or subsystem. This information is applicable to all new subsea pumping intervention systems and existing equipment pieced together to form a system. This is not a standalone document. It is to be used in conjunction with the API 17G parent document. Subsea pumping well intervention systems satisfy the requirements of API 17G as modified by this document. This recommended practice is intended to serve as a common reference for designers, manufacturers, and operators/users, thereby reducing the need for end user specifications. This RP also eliminates the need for interpretation of the applicability of requirements given by other codes and standards for permanent installed equipment. The section and subsection numbering in this document corresponds to the section and subsections in API 17G. Specific equipment covered by this recommended practice is as follows: Flying Leads Vertical Fluid Conduits Jumpers Fluid Conduit Connectors Subsea Safety Module Control Systems Disconnect Systems Associated equipment not covered by this recommended practice is listed below: 1

7 Subsea Pumps Subsea Process Packages Work Units used to Execute Work in the Field Winching, Spooling, Tensioners, Injector Heads, or other Equipment to deploy Fluid Conduits 2 Normative References The following referenced documents are supplemental to the documents sited in API 17G. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies. API Specification 5ST, Specification for Coiled Tubing, 2010 API Recommended Practice 17A, Design and Operation of Subsea Production Systems General Requirements and Recommendations API Recommended Practice 17B, Recommended Practice for Flexible Pipe, 2014 API Specification 17D, Design and Operation of Subsea Production Systems Subsea Wellhead and Tree Equipment, 2011 API Recommended Practice17G, Recommended Practice for Completion/Workover Risers, 2006 API Recommended Practice 17H, Remotely Operated Tools and Interfaces on Subsea Production Sustems API Specification 17J, Specification for Unbonded Flexible Pipe, 2014 API Specification17K, Specification for Bonded Flexible Pipe API Specification 17L1, Specification for Flexible Pipe Ancillary Equipment API Recommended Practice 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment API Recommended Practice 5C7, Recommended Practice for Coiled Tubing Operations in Oil and Gas Well Services ASME B31.3, Process Piping ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 2

8 BS EN 14359, Gas-loaded Accumulators for Fluid Power Applications DNV-OS-C501, Composite Components DNV Standard for Certification 2.7-3, Portable Offshore Units ISO 10945, Hydraulic Fluid Power-Gas-loaded Accumulators-Dimensions of Gas Ports NORSOK D002, Well Intervention Equipment, Terms, Definitions, Abbreviated Terms and Symbols 3.1 Terms and Definitions For the purposes of this document, the following terms, definitions, abbreviations and symbols apply in addition to the terms defined in API 17G as applicable control system That which includes the primary control system, backup control system, ESD and disconnect control system. NOTE These systems are a group of components, equipment packages, and/or part of the permanent infrastructure that provide all the control functions required to operate the Subsea Pumping Well Intervention System in its entirety downline Lines in the water column that perform various purposes other than to convey fluid NOTE Downlines may be used to convey or suspend loads (crane or winch wires, synthetic rope), operate ROV s or support divers (ROV or diving bell umbilicals), send utilities or control subsea equipment emergency quick disconnect system Group of components, equipment packages, and or part of the permanent installed subsea system infrastructure that provide the ability to close the barrier valves and disconnect the Intervention Vessel from the subsea equipment packages at any angle of incident downline(s) fluid conduit That which connects various system packages to allow for the flow of fluid between the various equipment packages and the tree system; typically consisting of collapse resistant hose, steel coil tubing, or jointed pipe NOTE There are four groups of fluid conduits: Deck Fluid Conduits used to connect the various equipment on the deck of the intervention vessel. 3

9 Vertical Fluid Conduits, these are the conduits in the vertical water column Flying Leads, these connect the vertical conduits to the equipment located on the seafloor and provides the heave compensation capability to the system. Jumpers, these provide the connection between equipment packages located on the seafloor fluid conduit connectors That which connects the various fluid conduits to the various equipment packages and the well NOTE A fluid conduit connector may also provide a structural connection that supports loads from one or more equipment packages high cycle fatigue Accumulated material structural damage induced by successive, alternating, low amplitude, high frequency plastic strains intervention fluid storage That which holds the intervention fluid upstream of the pump package NOTE The storage may be located on a surface vessel or subsea low cycle fatigue Accumulated material structural damage induced by successive alternating, high amplitude, low frequency plastic strains process package That which includes the facilities that temporarily store, handle, separate, and or dispose native well and/or intervention fluids NOTE 1 The process package is limited to the discharge or energized fluid side of the pumping system and not the control side or suction side. NOTE 2 Equipment such as separators, de-gassers, water polishers, transfer pumps, etc. are examples of equipment found in process packages pumping manifold That which contains the necessary piping and valves needed to direct the flow NOTE The Subsea Pumping Well Intervention System could contain a surface pumping manifold, a subsea pumping manifold or both. 4

10 pumping package That which provides the motive force to the fluid. NOTE This package may be either located on the intervention vessel, subsea, or both subsea equipment package One or more unitized equipment packages can be designed that is deployed subsea that contains one or more of the following components: pumping package fluid storage fluid conduits process package fluid conduit connectors pumping manifold subsea Safety Module control system components disconnect system flexible fluid conduit interfaces to the permanent installed subsea system infrastructure subsea safety module Group of components installed between the fluid conduit connector and tree and/or permanent infrastructure access point that provides some or all of the barrier device(s) necessary to protect against uncontrolled flow to the subsea environment 3.2 Abbreviated Terms For the purposes of this document, the following abbreviations and symbols apply in addition to the terms defined in API-17G as applicable. AMV ASV annulus master valve annulus swab valve 5

11 EDS EQD ESD FMECA HAZID HAZOP IWOCS MAOP ML MSL OCTG PCV PMV PSD PSV PWV ROV RP RWP SCSSV SPWIS SSM VFC XOV XT emergency disconnect sequence emergency quick disconnect emergency shutdown failure mode, effects and criticality analysis hazard identification hazard and operability study Intervention and workover control system maximum allowable operating pressure mud line mean sea level oil country tubular goods production choke valve production master valve process shut down production swab valve production wing valve remotely operated vehicle recommended practice rated working pressure surface controlled subsea safety valve subsea pumping well intervention system subsea safety module vertical fluid conduits crossover valve Christmas tree 6

12 4 System Requirements 4.1 Purpose General Section 4 specifies system requirements for subsea pumping intervention systems. For subsea pumping intervention operations the main modes of operation covered within the scope of this recommended practice are: Surface to Seafloor Fluid Conveyance Mode Seafloor Fluid Conveyance Mode Both modes are used to either introduce or remove limited inventories of fluid from the wellbore. Both modes are not intended to be used for flowback or well clean-up, typically removing no more fluid in an operation than is contained in a fluid conduit suspended in the water column. The mode of operation and the type of operation to be performed are dependent on the type of subsea tree and barrier elements included in the subsea pumping intervention system, A typical arrangement for Surface to Seafloor Fluid Conveyance Mode of operation is illustrated in Figure 1. A typical arrangement for Seafloor Fluid Conveyance Mode is illustrated in Figure Surface to Seafloor Fluid Conveyance Mode In this mode, one or more Pumping Packages are located on the intervention vessel. One or more vertical fluid conduits are deployed from the intervention vessel through the water column to convey the fluid to the subsea well on the seafloor. Flying leads connect the vertical fluid conduit to the Subsea Safety Module which is located on a seafloor structure or landed on the subsea tree. One or more of the vertical fluid conduits can be used to convey fluid from the Subsea Safety Module to the Process Package and/or Fluid Storage Package located on the intervention vessel. The Fluid Storage Packages may be located on the intervention vessel or a separate vessel that transfers the fluid to the intervention vessel. A Subsea Pump Package may be incorporated into this system to boost the pumping pressure. It would be located between a Disconnect Package the Subsea Safety Module Seafloor Fluid Conveyance Mode In this mode, no fluid is conveyed between the intervention vessel and the subsea infrastructure. The Fluid Storage and Pumping Packages are located on the sea floor and connected to the tree. Control of these packages is via umbilical back to the intervention vessel. 7

13 Surface to Seafloor Conveyance mode VESSEL SUBSEA ROV ML Intervention Fluid Storage System 2. Pumping Package 3. Pumping Manifolds 4. Interconnect Piping 5. Process Package 6. Vertical Fluid Conduits 7. Disconnect System 8. Retainer Valves 9. Subsea Safety Module 10. Barrier Elements 11. Check Valve (Optional) 12. Tree Connection Interface 13. Subsea Tree 14. SCSSV Figure 1 Typical SPWIS for Surface to Seafloor Fluid Conveyance Mode 8

14 Figure 2 Typical SPWIS for Seafloor Fluid Conveyance Mode 9

15 Equipment must resist external loads and pressure loads and accommodate tools for necessary operations. In Surface to Seafloor Fluid Conveyance mode, equipment may be exposed to ocean environmental loads such as hydrodynamic loads from waves and current in addition to vessel motions. 4.2 System Design The purpose of system design is to ensure that subsea pumping well intervention systems and its components shall be designed, manufactured, fabricated, operated and maintained such as to be suited for its intended use, throughout its intended life, as specified by end user. System design shall be based on the requirements given in the design basis and in the system definition. The system design shall as a minimum be documented in terms of the following: a) system drawings; b) component design specifications; c) material selection; d) global analysis of fluid conduit system and equipment suspended in the water column as per Clause6; e) subsea safety module system analysis including emergency shutdown and disconnect response times f) Testing and verification plan NOTE Systems design is the process of defining the architecture, components, modules, interfaces, and data for a system to satisfy specified requirements. 4.3 Risk Assessment Quantitative and qualitative risk analysis may be conducted to provide an estimation of the overall risk to health and safety, environment and assets and typically includes the following: a) HAZID; b) HAZOP; c) FMECA; d) assessment of probabilities of failure events; e) accident developments; 10

16 f) consequences assessment. NOTE Legislation in some countries requires risk analysis to be performed, at least at an overall level to identify critical scenarios that might jeopardize the safety and reliability of the subsea pumping intervention system. 4.4 System Functional Requirements A subsea pumping intervention system shall fulfill the following requirements as appropriate: A subsea pumping intervention system shall fulfill the following requirements as appropriate: allow passage of fluid through the single or multiple bores of the subsea tree from the pumping package and/or to the process package provide a conduit to contain all fluids for the application and permit their circulation to and from the wellbore 4.5 Design Principles The overall system design shall be fail-safe. The system shall be designed to ensure that no single failure will cause an unacceptable risk to personnel safety, the environment and to loss of financial assets. The possibility of common cause failures shall be identified and measures shall be implemented to minimize their probability of occurrence. For all operations, the system design shall account for the worst case expected scenario. This requirement applies, both locally (i.e. subsea pumping intervention system and its barrier elements) and globally (i.e., vertical or horizontal tree, wellhead, conductor, etc.). 4.6 Operational Principles The subsea pumping intervention system shall be operated in accordance with the requirements specified in API 17G, Section 4.15 and the guidance given in API 17G, Annex B. As far as practical, all activities associated with the subsea pumping intervention system shall be conducted in such a manner that single failures shall not lead to an unacceptable risk to personnel safety, the environment and to loss of financial assets. This applies both to operational errors and to failure of equipment used directly in operations, as well as equipment used for auxiliary functions. The operation of the subsea pumping intervention systems shall be limited by the weakest component in the system. NOTE This requirement is applicable to component rated working pressure, fluid conduit design pressure, design temperature class and allowable external loads. 11

17 4.7 Safety Strategy The developed safety strategy shall be used in the design and operation of subsea pumping intervention systems, in particular: a) The safety strategy should review the existing hardware and hardware being put in place to assure there is sufficient independence between protection layers (barriers) to the extent that the safety integrity of the protection layer (barrier) is not compromised by another nor a potential single point failures cause a cascade of successive failures. b) The safety strategy shall be used to guide the design of the control system for the safety functions within the subsea pumping intervention system. The safety strategy for subsea pumping intervention systems, shall as a minimum address. PSD (stop pumping operations) ESD (close barrier valves and rams) EQD (close barrier valves, including the environmental barrier retaining fluid in the conduit, and full disconnect from subsea packages) Periodic testing to demonstrate the safety functions availability as suggested by API 17G, Table J.4. c) Systems using coiled tubing shall have a fatigue management system including records of use. 4.8 Barrier Requirements For all operations, a barrier philosophy shall be established and implemented to meet the regulatory requirements under which the subsea pumping intervention system shall be operating. As a minimum the system shall have the following: At least two independent and testable barriers between the reservoir and the environment shall be to be used to prevent unintentional flow from the well. These barriers may be located in the subsea safety module or in the subsea tree. Both barriers cannot be disabled by a single point failure of a piece of the intervention system The barriers shall not be compromised upon disconnect of any attachments. The barrier elements located on the Subsea Safety Module must have ROV or diver over ride capability. 12

18 Additional assurances are required when a well barrier envelope extends beyond the mechanical interfaces installed directly on the well. The user must demonstrate that the design, testing, operation, and risk of damaging any system components between the well and the remote located well barrier device have been mitigated and is fit for purpose. No barrier elements located downstream (i.e. in the direction of flow from the well bore) from the Subsea Safety Module are considered barriers unless they are testable and remain connected to the subsea architecture upon disconnect of the fluid conduits and/or any other attachments System must contain a retainer valve to retain fluid in the vertical fluid conduit upon disconnect. Testable Isolation valves should be located on the surface vessel between the vertical fluid conduit and the surface process and pumping systems. 4.9 Regulations, Codes and Standards The subsea pumping intervention system shall comply with the applicable regulatory requirements for the regions in which the system will be operated. User/operator shall specify the regulatory jurisdictions in which the system is intended to operate. The subsea pumping intervention system equipment included in the scope of API 17G2 shall be designed, manufactured, and tested in accordance with the references, codes and standards specified in API 17G (see Table 1). Components which are outside the scope of this recommended practice, and have an influence on the design, manufacture, test and operation of the subsea pumping intervention system shall be accounted for to ensure overall system safety. In particular, equipment supplied in accordance with component standards (e.g. API 6A, API 14A, API 16ST, API 17D and API 17K) are designed and qualified for designated sizes and rated working pressures only (i.e. pressure based design). For subsea pumping intervention system applications, it is normal industry practice to ensure that the load combinations determined in API 17G (i.e. normal, extreme and accidental loading conditions) do not exceed the rated capacity (i.e. normal capacity) of pressure based designed equipment. NOTE References to Section and Annexes given in Table 1 are references to sections and annexes in API 17G. 5 Functional Requirements 5.1 Purpose Section 5 specifies the functional requirements for the individual types of equipment included in a SPWIS (see Figure 3 and Figure 4). Each equipment type is defined in terms of its function and system interfaces. 13

19 Subsea pumping intervention System Components Intervention Fluid Storage System Pumping Package Pumping Manifold Interconnecting Piping Fluid Conduit - Rigid Fluid Conduit - Flexible Fluid Conduit Spooled Fluid Conduit - Segmented Fluid Conduit Carbon Steel Fluid Conduit Composite Table 1 Equipment References, Codes and Standards Functional Requirements Design Requirements Materials and Manufacturing Requirements Component Qualification Testing System Integration Testing Section 5 Section 6 Section 7 Section 8 Section 8 Section 5 Section 6 Section 7 Section 8 Section 8 Section 5 Section 6 Section 7 Section 8 Section 8 Section 5 Section 6 Section 7 Section 8 Section 8 Section 5 Section 6 Section 7 Section 5 Section 6 Section 7 Section 5 Section 6 Section 7 Section 5 Section 6 Section 7 Section 5 Section 6 Section 7 Section 5 Section 6 Section 7 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Section 8 Downlines Section 5 Section 6 Section 7 Section 8 Section 8 IWOCS Section 5 Section 6 Section 7 Section 8 Section 8 Process Package Section 5 Section 6 Section 7 Section 8 Section 8 Subsea safety module barriers Disconnect System Section 5 Section 6 Section 7 Section 8 Annex L Section 8 Annex L Section 5 Section 6 Section 7 Section 8 Section Common Requirements In addition to the requirements listed in API 17G, Section 5.2, the following requirements are common to all equipment in the subsea pumping well intervention system: a) The system shall be maintainable. All parts of the system intended for maintenance shall be capable of being safely dismantled. Trapped volumes with potential pressure shall be have a means to be safely evacuated; 14

20 Figure 3 Typical SPWIS for Surface to Seafloor Fluid Conveyance Mode 15

21 Figure 4 Typical SPWIS for Seafloor to Surface Fluid Conveyance Mode 16

22 b) The system must function as designed when in use with all chemicals and hydrocarbons that system is intended to be used; c) The system shall be able to apply closure to a minimum of two testable barriers between the reservoir and the environment in both normal and emergency operating conditions. d) The system shall be able to disconnect from the well and/or subsea infrastructure access location in both normal and emergency operating conditions e) All equipment that can be subject to pressure differential (i.e., from hydrostatic head or internal pressure greater than ambient) shall be fully functional at rated pressures as designated in 17G; f) During installation, normal operation, or emergency operation no portion of the system shall transmit undue forces to the subsea architecture / well control package; g) System should allow full functionality of barrier elements from the work unit to allow pressure and/or function testing or maintenance. 5.3 Subsea Safety Module (SSM) Functions of the Subsea Safety Module (see Figure 5, Figure 6 and Figure 7) are to serve as the manifold between the subsea conduit system and the subsea tree / wellbore access point; and may provide a place to locate barrier devices to isolate the well bore from the environment. A SSM may typically include the following components: a) tree interface connector b) connector adapter c) ROV/Diver interfaces d) control system e) disconnect system EQD f) barrier valve(s) g) releasable fluid conduit connectors The SSM may be configured as a single unit or as a sectioned unit and may be equipped with an upper re-entry spool interface with the EQD or other connector. A sectioned unit is one in which barrier devices, attachment interfaces for controls or fluid conduits, and/or piping may be physical located in more than one structure. 17

23 Figure 5 Subsea Safety Module Interfaced with Vertical Tree Configuration 18

24 Figure 6 Subsea Safety Module on Skid Interfaced with Vertical Tree Configuration 19

25 Figure 7 Subsea Safety Module Interfaced with Tree Choke Configuration Functional Requirements: Function of the primary structure is to adequately support the elements of the entire SSM including the tree interface connector, adapters, and subsea conduit connector system during all phases of operation including deployment, operation, and recovery; SSM barrier valves should have a means to indicate valve position observable by ROV/diver. 20

26 5.4 Subsea Control System General The function of the subsea control system is to provide control of all functions of the system in both normal operations and emergency operations. The subsea control system should perform in a manner which is efficient, safe, and protects personnel, ROV, subsea assets, the work unit, and the environment. Functional Requirements: The Subsea Well Pumping System can be operated by the work unit or jointly with Host providing some control functions with the exception of barrier devices. The work unit shall have direct control such that a PSD, ESD, and/or an EQD function of the system can be implemented at any time. The ability of the work unit to initiate an EQD by two separate means must be incorporated in the SPWIS with one means not requiring human intervention Barrier valve closure and disconnect functions shall have ROV or diver override capability. The SWPIS shall be able to close at least one barrier and disconnect from the well in the event of any EQD control system component failure. The SWPIS control system shall have Deadman and Auto Shut In capability Primary and Back-up Control Systems for Normal and EQD Operations The following types of control systems are suitable for normal and EQD operations: IWOCs systems as per API 17G, Annex M ROV mechanical driven system ROV hydraulic driven system acoustic controlled subsea hydraulic system tree production control system proximity based mechanical / Hydraulic System. combination of the above 21

27 5.4.3 Acoustic Control Systems Acoustic signal transmission may be used as a means for operating the SWPIS control system. The acoustic control system includes a surface electronics package, subsea electronic package and a subsea electro-hydraulic package. Functional Requirements: The acoustic control system should be designed such that the electric control system functions can be tested without actuation of the EDS functions. Hydraulic components and piping systems should have a rated working pressure at least equal to the rated working pressure of the control system. The acoustic control electronic system should utilize security command signal coding to prevent operation by other equipment in close proximity. A frequency management plan shall be used to avoid interference with other equipment on and in the vicinity of the work unit. Water depth and slant range capacity shall meet operational parameters. Two (2) actions shall be required to initiate the function(s) (i.e., actuate the arm function and actuate the close control function). Subsea battery power to operate the acoustic control system shall be capable of sustaining operation for the anticipated time of deployment. A low battery alarm shall be provided. The entire acoustic control system must be able to be tested on deck. 5.5 Fluid Conduit Connectors The focus of this section pertains to the connector system that provides the interface between the SSM, the subsea vertical conduit, and control umbilical if used. The function of the subsea connector is to provide a subsea releasable connection Functional Requirements: Must be releasable from the SSM at all expected angles of release; Once the subsea connector is released from the SSM it must prevent the contents of the subsea conduit to leak to the environment at the net hydrostatic pressure; The subsea connector must be compatible with all chemicals that will be pumped through the system; 22

28 The subsea conduit connectors shall perform to the standards set in API 17G, Section and Section ; 5.6 Emergency Quick Disconnect (EQD) System The EQD is to prevent the transmission of unacceptable loads to the subsea safety module. The EQD performs this function by disconnecting the vessel from the subsea equipment modules. Functional Requirements: The EQD will close barrier valves and disconnect the fluid conduits and all control umbilicals when triggered by the subsea control system. The EQD command will also be given to the system autonomously in the event of vessel drive off / drift off when used on a dynamic positioned work unit; The EQD system must close the barrier valves within 45 seconds of initiation of the EQD command and must disconnect all fluid conduits and umbilical lines prior to imposing significant loads on the subsea equipment packages. The EQD shall provide reliable unlock and release from the subsea safety module under the highest applied design bending moment and maximum design down line angle created by vessel offset and environmental conditions up to the accidental condition (i.e., loss of vessel station keeping); Upon command, the EQD will sequence the closure of the disconnecting the fluid conduits or umbilical connectors; barrier valves prior to In the event of an emergency disconnect it must be possible to depressurize and flush the system safely; If accumulators are used, there shall be a method to monitor accumulator pressure and charge the system. 5.7 Subsea Pumping Equipment Functional Requirements: Subsea pumping equipment are pump systems that are located subsea and are typically used to pump from the sea floor to the surface or into subsea temporary infrastructure. Subsea pumping equipment shall conform to the common requirements of 5.3. Subsea pumping control systems should be incorporated in to the EQD philosophy to prevent continued pumping after an EQD event. 23

29 Subsea pumping equipment shall not impose loads to the SSM or to existing well interface in the event of work unit drive / drift off. If the subsea pumping equipment is connected to a surface work unit by vertical fluid conduit, control umbilical, or power umbilical and can be damaged by vessel drive / drift off then it must incorporate the same EQD functionality as the SSM. If the subsea pumping equipment is electrically powered and an EQD is incorporated, then the control system should shut down all electrical power to the subsea pumping equipment prior to the release of the electrical umbilical. If electrically powered, the system must be intrinsically safe to divers, surface personnel, and ROV. 5.8 Subsea Intervention Fluid Storage For this section subsea fluid storage equipment is considered to be a temporary tank or reservoir that is located on the sea floor or in the water column. Functional Requirements: Subsea fluid storage equipment should be designed with an appropriate structure and foundation that can adequately support the combined weight of the package and intended contents at full capacity; Subsea fluid storage equipment shall be pressure balanced with ambient pressure during deployment and recovery; Subsea fluid storage equipment must be compatible with all chemicals or hydrocarbons anticipated in its use; Subsea fluid storage equipment must have two functional methods to alleviate net differential hydrostatic pressure at any point in the water column or on deck; Subsea fluid storage equipment must have a means in which to fill or de-inventory the system; Subsea fluid storage equipment must be able to be flushed and cleaned internally without risk to personnel or the environment; Subsea fluid storage equipment must have a method to isolate the contents subsea and on the surface. Subsea fluid storage equipment isolation valves must be able to be controlled subsea; 24

30 If the subsea fluid storage equipment is connected to a surface work unit by vertical fluid conduits, control umbilical, or power umbilical and can be damaged by vessel drive / drift off then it must incorporate the same EQD functionality as the SSM. 5.9 Vertical Fluid Conduits This section refers to fluid conduit connecting a surface vessel to the SSM, subsea pumping equipment, or subsea fluid storage equipment. Vertical fluid conduits allow fluids to be safely pumped from the surface equipment the SSM. They are exposed to both internal pressure and external pressure. Internal pressure can be as high as the equipment maximum allowable test pressure, while external pressure can approach the ambient seawater pressure at the maximum reach of the conduit. Vertical fluid conduits may be comprised of jointed pipe; semi-ridged products such as carbon steel coil tubing, composite coiled tubing; bonded products, or various hoses. Vertical fluid conduits may be made up of different types of materials to fit environmental factors such as vessel movement or depth, and other job requirements. Typically subsea conduits incorporate a flexible flying lead to aid in ease of handling subsea or to absorb vessel movement. Functional Requirements: VFC must conform to the common functional requirements found in API 17G, Section 5.3 The VFC must be self-supporting in the water column when suspended from a work platform. This may be accomplished by the use of integral or external strength members Vertical Conduit Deployment and Recovery System Subsea conduit deployment and recovery systems primary function is to safely deploy, recover, and interface the subsea conduit to the surface pumping to processing system. Due to the environment and constraints these systems operate in consideration to the functional requirements should be considered. Functional Requirements: Must be able to recover with conduit filled with heaviest fluid used. Must contain the conduit at all times in the event of loss of tension control. Must maintain the conduit within the allowable minimum bend radius; 25

31 Reel process piping and components, which include swivels, valves, instrumentation must meet or exceed the MAOP of the conduit. System shall be designed to withstand the dynamic forces induced by vessel motion. Particular consideration should be given to the point of over boarding of the conduit. Consideration should be given to an isolation philosophy that will allow repair of sealing components that could fail during operations, i.e. fluid swivels, seals, etc. Operator controls shall be in a safe location that is removed from potential hazards such as; high pressure leaks and parting of the conduit. Deployment and recovery system should have appropriate equipment or device(s) to allow proper management of conduit fatigue and deployment length Flying Leads Flying leads connect the vertical conduits to the equipment located on the seafloor. Typically they consist of single or multiple hoses with a single connector at each end. Functionally they enable a diver or ROV to manipulate a lighter and more flexible conduit than the vertical conduit when connecting to the SSM. The flying lead also provides heave compensation capability to the conduit system and allows the vessel a certain amount of maneuvering capability. Functional Requirements: Must be rated for the maximum anticipated pressure to be encountered during the specific intervention task. Collapse rating should be considered when the flying lead may be subjected to sub-ambient conditions. Must be compatible with all chemicals or hydrocarbons anticipated in its use; 5.12 Jumpers Jumpers are the fluid conduits between the various subsea equipment packages. Functional Requirements Must be rated for maximum pressure of the entire system Must be capable of handling max flow rate of the system Must be pressure tested with entire system prior to initial operations 26

32 The jumper between the SSM and the Tree must be protected from over-pull from vessel drive off situation 6 Design Requirements 6.1 General This clause specifies requirements for design of Subsea Pumping Well Intervention Systems and associated components. Requirements include, but are not limited to: a) structural design of components; b) determination of component capacities; c) determination of loads; d) load effect analysis; e) code check, interference check, fatigue check; f) determination of operating limitations This clause covers pressure containing, pressure controlling, and load-bearing components. This clause requires that determination of component capacities shall comply with materials and fabrication requirements in Section 7. The section departs from the format of the previous sections in that it does not follow the section numbering of the parent document. 6.2 Design Principles The unique configuration of Subsea Pumping Well Intervention Systems require analysis and design techniques that differ from those contained in API 17G, however the requirements in sections 6.1 through 6.4 and the methods for the analysis and design of system components that are similar in nature, should use be used. The following requirements shall be included in the system design of SWIPS: Means shall be incorporated to ensure excessive loads are not transmitted into the Subsea safety module that may compromise the structural and/or pressure containment integrity of the Subsea safety module or permanent subsea equipment such as the subsea tree or wellhead. 27

33 There shall be at least one component, located between Fluid Conduits and the Subsea safety module that is the weakest in tension and/or bending and limits the transfer of excessive loads into the Subsea safety module, permanently installed subsea equipment and any other mechanical attachments Fluid conduits shall not be able to transmit loads to fluid conduit connectors that exceed the structural load limit of the connector. 6.3 Global System Analysis General The subsea pumping intervention system is characterized by smaller bore conduit and a more weather-sensitive multi-service vessel as compared to a typical top tensioned intervention riser covered in API 17G. The following system analyses are recommended for pumping intervention systems: Global Hydraulic Analysis Global hydraulic analysis is performed to verify the pumping system has the ability to deliver the required flow rate. The analysis provides the system hydraulic profile, aka, flow rate versus pressure loss relationship along the fluid injection path from upstream chemical source tanks to downstream tree injection point Global Riser Analysis Global riser analysis is performed to establish the behavior of the vertical fluid conduit and downlines. The analysis is used to provide the following data: Tension load in the vertical conduit and flying leads, and loads imposed on the subsea safety module versus vessel offset. Loads for the assessment of the weak link Clashing conditions between the vertical fluid conduit and the downlines. Bend radius vs vessel offsets for the vertical conduit and the flying leads Harmonic loads due to vessel heave during deployment and while connected subsea Fatigue cycles on the hot spot at the deployment sheave or tensioner 28

34 Global riser analysis and fatigue analysis methodology and load cases are similar to those as specified by API 17G Computational Fluid Dynamics Computational fluid dynamics is performed to evaluate impact of transient flow on the equipment. The analysis provides the fluid characteristic and particle trajectory profile and the impact on the subsea equipment wall. Based on the time-variant stress function, any water hammer effects are better understood and the erosion rate of equipment can be calculated. 6.4 Component Design Requirements General Design requirements for the following components are covered in this section. Components not listed should adhere to the design requirements of API 17G. vertical fluid conduits flying leads jumpers fluid conduit connectors rigid piping subsea control tubing and fittings isolation / well control valves accumulator and pressure vessels pad-eyes and lifting devices ROV interfaces subsea equipment foundations and mud mats connectors other that fluid connectors retainer valves 29

35 6.4.2 Vertical Fluid Conduits General This clause defines design requirements for vertical fluid conduits used to convey pumped fluids from a vessel to the subsea safety module. The types of conduits typically used are: metallic coiled tubing rigid conduit such as OCTG (drill pipe) composite coiled tubing unbonded flexible pipe thermoplastic hose Metallic Coiled Tubing General The requirements described in the following subsections are applicable for the following system configuration: The reeled coiled tubing is deployed over a sheave, gooseneck/injector head type device. The coiled tubing extends from the vessel to an elevation above the mud line. A clump weight is attached to the bottom of the coiled tubing to limit the system s dynamic response during installation and straighten the coiled tubing as it passes over the sheave. The bottom of the coiled tubing is connected to the subsea safety module via a slack flying lead assembly. The flying lead provides the heave compensation mechanism for the system General Design Requirements The following design requirements apply: a) Coiled tubing shall conform to API 5ST, where applicable b) Suspended coil tubing has very limited axial compressive capacity. Deployment systems and interfaces to the Subsea Safety Module or other equipment shall ensure that axial compressive loads are not applied to the suspended coil tubing. 30

36 c) It is recommended that shipping, handling and deployment apparatus (Figure 8) for coiled tubing limit the minimum bend radius of the coiled tubing to 48 times the coil tubing outside diameter in accordance with NORSOK D002, Section 7.2. Smaller diameter ratios may be used if justified. Apparatus may include product reels, sheaves, tubing injectors, deployment chutes and bend restrictors/limiters. Figure 8 Example Shipping, Handling and Deployment Apparatus Strength Design Requirements The coiled tubing is highly stressed where it exits the deployment equipment. Spooling and unspooling of coiled tubing can result in a reduction of the yield strength up to 10% due to the Bauschinger Effect (per the note in API 5ST, Section ). As such, coiled tubing yield stress provided by the manufacturer shall be reduced by a factor of 10%. This reduction may be lessened or eliminated based on material testing of samples that have been subjected to reeling strains equivalent to at least 50% of the high stress fatigue limit of the coil material. Ovalization of the cross section and thinning of the tubing wall can result from multiple phenomena. These effect need to be considered when evaluating the ultimate strength of the coil cross section. Two methods of estimating the strength of the coiled tubing cross section at the point where it leaves the sheave or injector head are presented below. The loads used in these methods should include both the static and dynamic loads on the coil. 31

37 Additionally, the end user may use other methods to qualify the strength of a coiled tubing string by providing alternate calculations supported by material testing. Method 1 Working Limit Curve This method determines the combined effect of Pressure and Tension loading. The effect of localized bending induced by deployment apparatus is not included in the equations; however, the minimum coiled tubing bend radius must comply with bullet (c) in the general design requirements to apply the method to the system. It is assumed that compliance with bullet (c) in the general design requirements allows bending to be ignored. The global strength check is based upon pressure differential, axial tension, and yield strength. This global strength assessment is based upon the works outlined in the paper, Coiled-Tubing Pressure and Tension Limits, written by K.R. Newman and D. Schlumberger presented at Offshore Europe Conference in September of The equations used to perform the global strength analysis are given below: 2 4 P (Eq. 1) i (Eq. 2) 2 TA P (2 3 1) 1 (Eq. 3) o A T A 2 2 A A 2 P 1) P 1 ( ) (Eq. 4) ( o o y 2 T A r r {Eq. 5) r r 2 o 2 o 2 i 2 i Where, T A is axial tension r is the coiled tubing radius σ y is the yield strength P is pressure 32