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Definition(s)

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Static bend restrictor

Design scenario where bend restrictor is subjected to static loads only, and where there is no or negligible intermittent contact between bend restrictor elements induced by wave and current environmental loads. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Splice

A termination is normally formed by looping the rope around a spool or similar attachment means, separating the rope into strands or groups of strands, and then tucking these strands back into the rope structure. Source: API RP 2SM Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014. Global Standards Source: API RP 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, July 2014. Global Standards

Splice

Termination normally formed by looping the rope around a spool or similar attachment means, separating the rope into strands or groups or strands, and then tucking these strands back into the rope structure. NOTE Definition taken from API 2SM. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

Splice

Join together component lengths or sub-components to achieve the required production length. Source: API SPEC 17E, Specification for Subsea Umbilicals, Upstream Segment, Fourth Edition, October 2010. Global Standards

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Spacer

Discrete component of which a number in series are used to piggy-back one or more supported pipes to a supporting pipe over a prescribed length. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

Spacer

Fluid containing insoluble weighting materials that is used to separate drilling fluids and cementing slurries. Source: API RP 10B-2, Recommended Practice for Testing Well Cements, First Edition, July 2005 (Reaffirmed: July 2010). Global Standards  

Spacer

Pressure-containing piece of equipment used to connect and provide separation between other pieces of equipment. Source: API SPEC 6A, Specification for Wellhead and Christmas Tree Equipment, Twentieth Edition, October 2010 (Addendum November 2012). Global Standards  

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Snatch load

Sudden load that acts on a slack tether with resulting dynamic amplification up to several times the applied tension. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Setting time

Time required for polymer or composite component to reside in mould before being removed. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Secant modulus

Slope of line drawn through the origin of a stress strain curve and intersecting a point on the stress strain curve corresponding to specified strain. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Seal element

Part of an I/J-tube seal that provides the seal. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Seabed connection

Connection between flexible riser end fitting and riser base. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

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Scouring

Removal or dissolution of parts of the seabed by bottom currents. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

Scour

Removal of seabed material from the foundation due to current and waves. Source: ISO 19905-1:202, Petroleum and natural gas industries – Site-specific assessment of mobile offshore units – Part 1: Jack-ups. Global Standards  

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SWC

Stepwise cracking. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards  

SWC

Step-wise cracking Source: ISO 21457:2010, Petroleum and natural gas industries — Materials selection and corrosion control for oil and gas production systems, First Edition,September 2010. Global Standards

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Sweet service

Service in an H₂S-free (sweet) fluid. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards  

Sweet service

Service conditions at the design pressure which have a H2S content less than that specified by ISO 15156 (all parts). Source: API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008. Global Standards

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Sour Service

Service conditions with H2S content exceeding the minimum specified by NACE MR0175/ISO 15156 at the design pressure. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards

Sour Service

Service in an H₂S-containing (sour) fluid. NOTE In this part of ISO 13628, “sour service” refers to conditions where the H2S content is such that restrictions as specified by ISO 15156 (all parts) apply. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards  

Sour Service

Service conditions with H2S content exceeding the minimum specified by ISO 15156 (all parts) at the design pressure. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global Standards  

Sour Service

Exposure to oilfield environments that contain H2S and can cause cracking of materials by the mechanisms addressed in ISO 15156. NOTE Adapted from ISO 15156-1:2001. Source: API SPEC 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005 (Reaffirmed June 2012). Global Standards  

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Subsea wireline systems

Subsea wireline systems involve the use of subsea pressure control equipment (including a lubricator), attached directly to the top of the subsea tree. Typical subsea wireline systems use a surface-mounted wireline winch/reel on the intervention vessel. Designs also exist for systems involving deployment of the winch at the subsea tree, thus decoupling the vertical movement of the wire from the vessel motion, however such systems have the corresponding features of some loss of “feel” for the wireline operator, as well as additional potential leakpaths and more complex subsea machinery. A key design feature of subsea wireline systems is whether or not hydrocarbon fluids are returned to the intervention vessel during the operations. If hydrocarbons are/can potentially be returned to surface, then the classification requirements for the vessel are much more onerous than for a vessel using a system in which hydrocarbons are not/cannot be returned to the surface. A typical subsea wireline system (i.e. using a surface-mounted wireline winch/reel) consists of the following major components: a tree connector; a lower lubricator assembly consisting of a wireline cutting valve and wireline BOPs, for pressure control of the well in the event of an emergency disconnect; an upper lubricator assembly consisting of a connector, tool trap, lubricator sections, wireline BOPs, stuffing box (for slickline) and a grease injection system (for monoconductor line), for loading and unloading of wireline tools; a surface-mounted wireline winch/reel (fitted with a motion compensation system); a control system, similar to a WOCS as described in A.11.2.3, for controlling the subsea tree and downhole safety valves as well as all the valves and functions contained within the subsea wireline equipment; a handling system for deployment and retrieval of the subsea equipment (usually with guidewires); a supporting ROV spread for observation and operation manual overrides, etc., as required. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Definition(s)

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Subsea reeled-tubing systems

Subsea coiled/reeled-tubing systems are similar to subsea wireline systems in that they also involve the use of subsea pressure-control equipment (including a lubricator), attached directly to the top of the subsea tree, while the reel is mounted on the intervention vessel. The configuration of a subsea reeled-tubing system is very similar to that for a subsea wireline system, and in fact one system could be configured to be able to handle both reeled tubing and wireline operations. A typical subsea reeled-tubing system consists of the following major components: a tree connector; a lower lubricator assembly, consisting of a series of various blind/shear and pipe BOPs for pressure control of the well in the event of an emergency disconnect; an upper lubricator assembly, consisting of a connector, crossover spool (to accommodate the length of the various downhole tools), tubing ram BOP, tubing stuffing box (to retain well pressure), injector assembly (to control movement of the tubing in and out of the well), tubing stripper (to prevent seawater entering the injector assembly), tubing cutter/crimper (to cut and crimp the tubing in an emergency disconnect situation) and a flexible tubing guide (to ensure the tubing is not accidentally crimped at the point where it enters the injection assembly); a surface-mounted tubing reel; a control system, similar to a WOCS as described in A.11.2.3, for controlling the subsea tree and downhole safety valves as well as all the valves and functions contained within the subsea reeled-tubing equipment; a handling system, for deployment and retrieval of the subsea equipment (usually with guidewires); a supporting ROV spread, for observation and operation manual overrides, etc., as required. Unlike a subsea wireline system, which requires motion compensation of the wire in order to maintain accurate depth control of the downhole tools, the reeled-tubing system controls the depth of the tools using the subsea injector assembly and therefore this control is decoupled from the motion of the intervention vessel, i.e. motion compensation of the tubing is not required. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Subsea processing (SSP) systems

In general, SSP encompasses all separation and pressure-boosting operations that are performed subsea, whether downhole or on the seabed. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Sand control

Sand control involves the use of specialized methods/equipment downhole to prevent sand from being produced in the wellbore. Such methods/equipment include: chemical consolidation; screens, slotted liners and filters; inside casing and open-hole gravel packs; propped fracturing, including use of resin coated sand. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Sand management

An alternative to the use of sand control is sand management, which involves the use of measures to minimize, monitor and manage sand production within allowable limits throughout the field life, without relying on downhole sand-control equipment/methods. While this approach has the advantages of low capital cost and allowing maximization of production rates, it does rely heavily on the predictions of how much sand is likely to be produced over the life of the well. It also requires ongoing monitoring of the sand production from each well and management of the attendant risks. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Slugging

Of all the different flow regimes, the one typically of most interest in multiphase subsea production systems is slug flow. Slug flow involves the intermittant production of liquid slugs and gas bubbles, some of which can be hundreds of metres long, and can lead to severe fluctuations in pressures and flowrates throughout the production system if not properly predicted and managed. Such dramatic fluctuations can cause: equipment damage, due to vibration, impact loads and/or enhanced corrosion; large disturbances in the separation facilities, resulting in poor separation of phases; large and rapidly varying compressor loads, resulting in inefficient compressor operations and unwanted flaring; frequent shutdowns and/or adoption of restrictive operating practices, both of which can result in a significant loss of revenue. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Severe or riser slugging

At the ultimate lowpoint (i.e. the riser base), terrain slugging can often be so dramatic that it is also known as severe or riser slugging. Severe slugging occurs when liquid accumulates at the riser base for an extended period of time under certain flow conditions, particularly if there is a downward slope in the line at the riser base and the flowrate is low. Severe slugging is a significant problem particularly in deepwater production systems, and hence has received an enormous amount of attention, both from an analytical viewpoint and also with respect to proposed solutions. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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“Steep wave” riser

The “lazy wave” and “steep wave” riser designs use an appropriate distribution of small buoyancy modules along a section of the riser to replace the pipe tray and subsurface buoy. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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“Steep S” riser

The “steep S” riser is similar to the “lazy S” except that the lower section of the flexible pipe between the buoy and the riser base is used as a tension member. The riser base replaces the deadweight anchor. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Stab-in and hinge-over method

This method (see Figure A.26) involves vertically lowering the flowline or umbilical end to the seabed and locking it to a subsea structure. The lay vessel then moves off location, laying the line to its installed configuration. As the vessel moves away the line will hinge over and be stroked into its final position, prior to the connection being made using a mechanical or hydraulic connector. If installing rigid pipe, the lay vessel may need to be equipped with motion (heave) compensation devices to reduce the chances for buckling or overtensioning the pipe once it is locked to the subsea structure. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Spool/jumper method

The spool/jumper method (see Figure A.24) uses a spool/jumper to bridge the distance (gap) between the end of the flowline and its connection point on the subsea facility, e.g. a subsea tree, PGB, manifold or riser base. This method is also often employed to link adjacent subsea facilities, e.g. a subsea tree to a nearby subsea manifold. Spools and jumpers can be used in both horizontal and vertical connection configurations, and may be made up using either diver-assisted or diverless techniques. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Submersible pump

Downhole submersible pumps are basically multistage progressing cavity pumps driven either by an electric motor or a hydraulic turbine. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Subsea system engineering

Subsea system engineering is an interdisciplinary approach which covers the complete system, from the reservoir to the processing facilities on the host (inclusive), with consideration of the requirements of all phases of the development, including engineering, procurement, construction, testing, installation, commissioning, operation, workover/maintenance and abandonment. The system engineering process consists of a management part and a technical part. An evaluation of the need for application of the various system engineering processes should be performed for each specific field development, based upon the characteristics of the development. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Signal on power

Separate electrical cables may also be required for transmission of control signals/data in an electrohydraulic PCS. Alternatively, the control signals/data may be superimposed on the power output, commonly referred to as “signal on power”. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Subsea control module or control pod

A subsea control module (colloquially referred to as a “control pod”) is normally mounted directly on the facility to be controlled, such as a subsea tree/manifold, on a base from which it can be removed for maintenance if necessary. The control pod is the interface between the control lines, supplying hydraulic and electric power and signals from the host facility, and the subsea equipment to be monitored and controlled. The control pod contains pilot valves powered by hydraulic fluid, electric power or both, that is supplied from the host facility. The pod also contains electronic components that are used for control, communications and data-gathering. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

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Subsea tree system

The equipment required to complete a subsea well for production or injection purposes includes a tubing hanger and a tree, often referred to in combination as the “subsea tree system”. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards