Glossary
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Multibore Hybrid Risers
Definition(s)
Multibore hybrid risers
Multibore hybrid risers provide multiple flowpaths from the seabed to an FPS by a combination of a buoyant free-standing rigid-pipe riser (also commonly known as a riser tower) from a subsea riser base to a shallow water depth, plus flexible pipes in a double free-hanging catenary shape connecting from the top of the rigidpipe riser to the FPS. These types of system typically also incorporate all of the small-bore service lines (e.g. gaslift, chemical injection, etc.) in the riser towers, while the control system functions (hydraulic, electrical and/or fibre optic) are usually part of a separate free-hanging umbilical suspended from the FPS, thus avoiding additional connections in these critical lines. The riser tower may also be insulated to address flow-assurance issues associated with temperature losses, such as hydrate and wax formation. The rigid portion of the riser is typically of construction similar to a multibore top tensioned rigid-pipe riser, as described in the following subclause. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsCompletion/workover (C/WO) Riser Systems
Definition(s)
Completion/workover (C/WO) riser systems
C/WO riser systems are used for the initial installation of the subsea completion equipment and during major well workovers. These systems typically require the use of a mobile offshore drilling vessel equipped with fullwellbore-diameter pressure control equipment. The two basic components of these systems are the C/WO riser and the WOCS, as described below. The completion and workover risers may in fact be a common system [typically known just as the completion/workover (C/WO) riser], with specific items added or removed to suit the task being performed. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsCompletion/Workover Riser (C/WO riser)
Temporary riser used for completion or workover operations. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global StandardsCompletion Riser
Definition(s)
Completion riser
A completion riser is a riser that is designed to be run through the drilling marine riser and subsea BOP stack, and is used for the installation and recovery of the downhole tubing and tubing hanger in a subsea well. Since the completion riser is run inside a drilling marine riser, it is not exposed to environmental forces such as wind, waves and current. A completion riser typically consists of the following (see Figure A.32): TH running tool; TH orientation device (unless this is included in the design of the TH itself, as can be done for example if a subsea HXT is used, or if a TH spool is used with a VXT); a means of sealing off against the riser inside the BOP stack for pressure-testing and well control; a subsea test tree for well control during an emergency disconnect; retainer valve(s) to retain the fluid contents of the riser during an emergency disconnect; intermediate riser joints; lubricator valve(s) to isolate the riser during loading/unloading of long wireline toolstrings; a surface tree for pressure control of the wellbore and to provide a connection point for a surface wireline lubricator system; a means of tensioning the riser, so that it does not buckle under its own weight. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsCompletion Riser
Temporary riser that is designed to run inside a BOP and drilling riser to allow for well completion. NOTE Completion operations are performed within the drilling riser. A completion riser can also be used for open-sea workover operations. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global StandardsWorkover Riser
Definition(s)
Workover Riser
A workover riser is a riser that provides a conduit from the upper connection on the subsea tree to the surface, and which allows the passage of wireline tools into the wellbore. A workover riser is not run inside a drilling marine riser and therefore it shall be able to withstand the applied environmental forces, i.e. wind, waves and currents. A workover riser is typically used during installation/recovery of a subsea VXT, and during wellbore re-entries which require fullbore access but do not include retrieval of the tubing. A workover riser typically consists of the following (see Figure A.33): the tree running tool; a wireline coiled-tubing BOP, capable of gripping, cutting and sealing coiled tubing and wire; an emergency-disconnect package capable of high-angle release; retainer valve(s) to retain the fluid contents of the riser during an emergency disconnect; a stress joint to absorb the higher riser bending stresses at the point of fixation to the LWRP; intermediate riser joints; lubricator valve(s) to isolate the riser during loading/unloading of long wireline toolstrings; a surface tree for pressure control of the wellbore and to provide a connection point for a surface wireline lubricator system; a means of tensioning the riser, so that it does not buckle under its own weight. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsWorkover Riser
Jointed riser that provides a conduit from the subsea tree upper connection to the surface and allows for the passage of tools during workover operations of limited duration, and can be retrieved in severe environmental conditions. NOTE Historically, workover operations have normally been performed in open sea (i.e. for vertical tree systems), but can be performed inside a drilling riser, provided sufficient barrier elements are available. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global StandardsNon-integral Riser
Definition(s)
Non-integral riser
Non-integral risers are made up of independent strings. These risers are typically based on either a single string of drillpipe (for which minimal access to the annulus is required), or one or more strings of production tubing, clamped together at various points along their length as they are run, similar to a downhole dual completion string. In either case, the workover control functions are supplied via an umbilical which is secured to the riser at various points, as it is run. Integral risers consist of “prefabricated” joints/assemblies in which the multiple pipe strings are terminated at either end in dual-bore connections, thus simplifying the handling and make-up operations. In cases where high tensile and/or bending loads on the riser are anticipated, an integral riser may also include an outer structural housing to provide additional strength. In this case the hydraulic and/or electrical control lines may also be incorporated into the prefabricated joints, however this approach obviously introduces a significant number of additional connections (and therefore potential failure points) into the workover control system circuits. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsNon-integral Riser
Riser which is made up of independent production and annulus strings or bores. NOTE This type of riser is normally run with joints slightly staggered to allow conventional tubing or drill pipe-handling tools to be used for make-up of joints. Clamping the tubular members as they are assembled provides ease of handling and some structural stiffening. A non-integral C/WO riser can be grouped into two types: a drill pipe riser and a tubing riser. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global StandardsLight Well Intervention Systems
Definition(s)
Light well intervention systems
Subsea LWI systems can be defined as those systems which provide some form of direct access to the wellbore, without requiring the use of an offshore drilling unit or a standard drilling marine riser. A wide variety of such systems have been developed, including conventional rigid workover risers, subsea wireline systems and reeled tubing systems as described in the following subclauses. Other subsea LWI systems are also feasible and may be deployed in the future, e.g. flexible riser systems. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsRigid Workover Risers
Definition(s)
Rigid workover risers
The most conventional LWI system involves the use of a standard rigid workover riser system (as described in A.11.2), deployed from either a semi-submersible/monohull vessel, e.g. a dive-support vessel or light well construction vessel. A rigid workover riser system allows conventional wireline and coiled/reeled tubing techniques to be used for downhole intervention/service work. Workover riser systems designed for intervention on wells fitted with subsea HXTs require the use of large-bore components [e.g. a 476 mm (18 3/4 in) tree connector, large-bore valves and a large-bore riser] in order to interface with the top of the HXT and to be able to retrieve the largebore plug installed in the TH and possibly in the internal tree cap. While this system provides maximum operational flexibility in terms of the work that can be performed downhole, it also has the greatest requirements in terms of vessel size, stationkeeping ability, deck space, variable deckload, riser system handling equipment, etc. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsSubsea Wireline Systems
Definition(s)
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 StandardsSubsea Reeled-tubing Systems
Definition(s)
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 StandardsThrough-flowline System Intervention
Definition(s)
Through-flowline system intervention
TFL servicing can be used in subsea wells to perform various well-servicing operations, including: setting and retrieving flow control devices such as plugs (downhole and wellhead), static chokes, gaslift valves and inserting subsurface safety valves; gathering bottomhole pressure and temperature information via the use of temporary downhole gauges; acidizing, bailing, drifting, fishing, perforating, sandwashing, wax cutting, well killing, etc. TFL servicing involves shutting in the target well and then pumping the required tools through a flowline/service line from the host facility to the subsea completion and thence downhole. Once the tools are pumped into position, the required functions are actuated by means of application of differential pressure to shear a pin, shift a sleeve, etc. Upon completion of the required task the TFL toolstring is pumped back to the host facility through the flowline/service line. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsWax Appearance Temperature
Definition(s)
Wax appearance temperature
The wax appearance temperature (WAT, also commonly known as the cloud point) is the temperature at which the first wax crystals form as the crude is cooled, while the pour point is the temperature below which the crude will no longer flow. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsFlexible Pipe
Definition(s)
Flexible pipe
Flexible pipe is characterized by a composite construction of layers of different materials, which allows large amplitude deflections without adverse effects on the pipe. This product may be delivered in one continuous length or joined together with connectors. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsFlexible pipe
Assembly of a pipe body and end fittings where the pipe body is composed of a composite of layered materials that form a pressure-containing conduit and the pipe structure allows large deflections without a significant increase in bending stresses. NOTE Normally the pipe body is built up as a composite structure composed of metallic and polymer layers. The term “pipe” is used in this document as a generic term for flexible pipe. Source: API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008. Global StandardsSubsea Processing Systems
Definition(s)
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 StandardsSubsea Production System
Definition(s)
Subsea production system
The complete subsea production system comprises several subsystems necessary to produce hydrocarbons from one or more subsea wells and transfer them to a given processing facility located offshore (fixed, floating or subsea) or onshore, or to inject water/gas through subsea wells. Subsea production systems can range in complexity from a single satellite well with a flowline linked to a fixed platform, to several wells on a template producing and transferring via subsea processing facilities to a fixed or floating facility, or directly to an onshore installation. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsSubsea production system
“Subsea production system” means equipment and structures that are located on or below or buried in the seafloor for the production of oil or gas from, or for the injection of fluids into, a field under an offshore production site, and includes production risers, flow lines and associated production control systems (système de production sous-marin). Source: Canada Oil and Gas Installations Regulations, SOR/96-111, Canada, current to May 1, 2014. Regulations Source: Canada Oil and Gas Diving Regulations, SOR/88-600, February 2013. Regulations Source: Nova Scotia Offshore Certificate of Fitness Regulations, SOR/95-187, Canada, current to May 31, 2012. Regulations Source: Nova Scotia Offshore Petroleum Installations Regulations, SOR/95-191, Canada, current to May 31, 2012. RegulationsSubsea production system
Subsea production system In these Regulations, “drilling installation”, “drilling rig”, “drilling unit”, “drill site”, “installation”, “production installation”, “production operation”, “production site” and “subsea production system” have the same meaning as in subsection 2(1) of the Canada Oil and Gas Installations Regulations. Source: Canada Oil and Gas Drilling and Production Regulations, SOR/2009-315, February 2013. Regulations Source: Nova Scotia Offshore Petroleum Drilling and Production Regulations, SOR/2009-317, Canada, current to May 31, 2012. RegulationsSand Control
Definition(s)
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 StandardsSand Management
Definition(s)
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 StandardsSlugging
Definition(s)
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 StandardsNormal Slugging
Definition(s)
Hydrodynamic slugging
Hydrodynamic slugging (also known as normal slugging) usually occurs at moderate gas and liquid velocities. As the relative velocity of the gas moving over the liquid increases, the liquid tends to form waves until at some point the height of the waves bridges to the top of the pipe and a slug is formed. Such slugs are often generated at or near the inlet point of the system, and can grow or shrink in length downstream of their formation point, due to changes in the inclination angle and/or compressibility effects. The length of hydrodynamic slugs is principally a function of the flowline diameter (but typically they are relatively short, being in the order of 20 to 40 pipe diameters in length) and hence the use of two smaller-diameter flowlines in place of one bigger line can assist in controlling this type of slugging. It should be noted, however, that these short high-frequency slugs can also merge into longer low-frequency slugs due to terrain/other effects. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsHydrodynamic Slugging
Definition(s)
Hydrodynamic slugging
Hydrodynamic slugging (also known as normal slugging) usually occurs at moderate gas and liquid velocities. As the relative velocity of the gas moving over the liquid increases, the liquid tends to form waves until at some point the height of the waves bridges to the top of the pipe and a slug is formed. Such slugs are often generated at or near the inlet point of the system, and can grow or shrink in length downstream of their formation point, due to changes in the inclination angle and/or compressibility effects. The length of hydrodynamic slugs is principally a function of the flowline diameter (but typically they are relatively short, being in the order of 20 to 40 pipe diameters in length) and hence the use of two smaller-diameter flowlines in place of one bigger line can assist in controlling this type of slugging. It should be noted, however, that these short high-frequency slugs can also merge into longer low-frequency slugs due to terrain/other effects. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsTerrain Slugging
Definition(s)
Terrain slugging
Terrain slugging is caused by the accumulation of significant amounts of liquid in low points along the line. Once the liquid bridges to the top of the pipe, the gas trapped upstream of the liquid slug starts to be compressed, until it reaches a pressure sufficient to overcome the hydrostatic head of the liquid and a chaotic blowout expansion will then occur. As the slug then moves through an uphill section of the line, liquid is shed from its rear and runs back down the slope to the low point, while at the same time stratified liquid is scooped up in front of the slug and added to its front. If insufficient liquid is available to be scooped up in front of the slug to replace that lost at the rear, then the slug will collapse before it reaches the next high point in the line. In systems with a steady liquid inflow, the amount of liquid in the line eventually accumulates to the point where terrain induced slugs successfully emerge from the system. Due to gravity effects, terrain slugging is worse in downward-sloping lines. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsRiser Slugging
Definition(s)
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 StandardsSevere Slugging
Definition(s)
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 StandardsOperational Slugging
Definition(s)
Operational slugging
Operational slugging can be defined as slugging that is due to deliberate changes in the operation of the system, such as pigging, start-up, blowdown and changes in rate. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsPassive Barrier
Definition(s)
Passive barrier
Passive barriers are typically “permanent” barriers that are not actuated or routinely disturbed once they are in place, such as the following: cement (and competent underground strata); downhole packers (including seal-bore extensions); downhole components, such as mandrels and valves for gaslift and chemical injection; subsea wellheads (including wellhead gaskets); casing and tubing strings (including hangers and seal assemblies); subsea tree bodies and valve blocks (including interfacing gaskets); pipeline systems (including jumpers, connector bodies, gaskets and pipe); tree and manifold piping; pressure-sealing caps (including gaskets).1Source(s)
1. API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards