HIC

HIC

Definition(s)

HIC

Hydrogen induced cracking. Source: API 570, Piping Inspection Code: In-service Inspection, Rating, Repair, and Alteration of Piping Systems, Fourth Edition, February 2016, with Addendum May 2017. Global Standards Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global Standards 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  

HIC

Hydrogen-induced cracking. Source: API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008. Global Standards  

HIC

Planar cracking that occurs in carbon and low alloy steels when atomic hydrogen diffuses into the steel and then combines to form molecular hydrogen at trap sites
  • NOTE: Cracking results from the pressurization of trap sites by hydrogen. No externally applied stress is needed for the formation of hydrogen-induced cracks. Trap sites capable of causing HIC are commonly found in steels with high impurity levels that have a high density of planar inclusions and/or regions of anomalous microstructure (e.g. banding) produced by segregation of impurity and alloying elements in the steel. This form of hydrogen-induced cracking is not related to welding.
[ISO 15156-1:2009, definition 3.12] 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
HB

HB

Definition(s)

HB

Brinell hardness. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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
Type 25Cr Duplex

Type 25Cr Duplex

Definition(s)

Type 25Cr duplex

Ferritic/austenitic stainless steel alloys with 40 u PREN u 45. EXAMPLES UNS S32750 and S32760 steels. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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
Type 22Cr Duplex

Type 22Cr Duplex

Definition(s)

Type 22Cr duplex

Ferritic/austenitic stainless steel alloys with 30 u PREN u 40 and Mo u 2,0 % mass fraction. EXAMPLES UNS S31803 and S32205 steels. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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
Type 6Mo

Type 6Mo

Definition(s)

Type 6Mo

Austenitic stainless steel alloys with PREN W 40 and Mo alloying W 6,0 % mass fraction, and nickel alloys with Mo content in the range 6 % mass fraction to 8 % mass fraction. EXAMPLES UNS S31254, N08367 and N08926 alloys. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards  

Type 6Mo

Austenitic stainless steel alloys with PREN W 40 and a nominal Mo alloying content of 6 % mass fraction, and nickel alloys with Mo content in the range 6 % to 8 % mass fraction EXAMPLE UNS S31254; UNS N08367; UNS N08926. 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
Sweet Service

Sweet Service

Definition(s)

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
Sour Service

Sour Service

Definition(s)

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  
Type 316

Type 316

Definition(s)

Type 316

Austenitic stainless steel alloys of type UNS S31600/S31603. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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
PREN

PREN

Definition(s)

PREN

Pitting resistance equivalent number. 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  

PREN (FPREN)

Number, developed to reflect and predict the pitting resistance of a stainless steel, based upon the proportions of Cr, Mo, W and N in the chemical composition of the alloy NOTE 1 For the purposes of this International Standard, FPREN is calculated from Equation (1): FPREN = wCr + 3,3(wMo + 0,5wW) + 16wN (1) where wCr is the percent (mass fraction) of chromium in the alloy; wMo is the percent (mass fraction) of molybdenum in the alloy; wW is the percent (mass fraction) of tungsten in the alloy; wN is the percent (mass fraction) of nitrogen in the alloy. NOTE 2 Adapted from ISO 15156-3:2009, definition 3.10, and ISO 15156-3:2009, 6.3. 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

Pitting resistance equivalent number (PREN)

Number developed to reflect and predict the pitting resistance of a stainless steel, based on the proportions of Cr, Mo, W and N in the chemical composition of the alloy. NOTE This number is based on observed resistance to pitting of CRAs in the presence of chlorides and oxygen, e.g. seawater, and is not directly indicative of the resistance to produced oil and gas environments. FPREW = wCr + 3,3(wMo + 0,5wW) + 16wN where wCr is the mass fraction of chromium in the alloy, expressed as a percentage of the total composition; wMo is the mass fraction of molybdenum in the alloy, expressed as a percentage of the total composition; wW is the mass fraction of tungsten in the alloy, expressed as a percentage of the total composition; wN is the mass fraction of nitrogen in the alloy, expressed as a percentage of the total composition.1 Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards
Pitting Resistance Equivalent Number

Pitting Resistance Equivalent Number

Definition(s)

Pitting Resistance Equivalent Number (FPREN)

Number developed to reflect and predict the pitting resistance of a stainless steel, based on the proportions of Cr, Mo, W and N in the chemical composition of the alloy. NOTE This number is based on observed resistance to pitting of CRAs in the presence of chlorides and oxygen, e.g. seawater, and is not directly indicative of the resistance to produced oil and gas environments. FPREW = wCr + 3,3(wMo + 0,5wW) + 16wN where wCr is the mass fraction of chromium in the alloy, expressed as a percentage of the total composition; wMo is the mass fraction of molybdenum in the alloy, expressed as a percentage of the total composition; wW is the mass fraction of tungsten in the alloy, expressed as a percentage of the total composition; wN is the mass fraction of nitrogen in the alloy, expressed as a percentage of the total composition. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards  

Pitting Resistance Equivalent Number(FPREN)

Number, developed to reflect and predict the pitting resistance of a stainless steel, based upon the proportions of Cr, Mo, W and N in the chemical composition of the alloy NOTE 1 For the purposes of this International Standard, FPREN is calculated from Equation (1): FPREN = wCr + 3,3(wMo + 0,5wW) + 16wN (1) where wCr is the percent (mass fraction) of chromium in the alloy; wMo is the percent (mass fraction) of molybdenum in the alloy; wW is the percent (mass fraction) of tungsten in the alloy; wN is the percent (mass fraction) of nitrogen in the alloy. NOTE 2 Adapted from ISO 15156-3:2009, definition 3.10, and ISO 15156-3:2009, 6.3. 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
Low-alloy Steel

Low-alloy Steel

Definition(s)

Low-alloy steel

Steels containing a total alloying element content of less than 5 % mass fraction, but more than that for carbon steel. EXAMPLES AISI 4130, AISI 8630, ASTM A182 Grade F22[12] are examples of low alloy steels. Source: API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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  

Low-alloy steel

Steel containing less than 5% total alloying elements, but more than specified for carbon steel. Although not generally considered a low alloy steel, steels with less than 11% chromium shall be included in this category. Source: API SPEC 16C, Specification for Choke and Kill Systems, First Edition, January 1993 (Reaffirmed 2001). Global Standards
Carbon Steel

Carbon Steel

Definition(s)

Carbon steel

Alloy of carbon and iron containing up to 2 % mass fraction carbon, up to 1,65 % mass fraction manganese and residual quantities of other elements, except those intentionally added in specific quantities for deoxidation (usually silicon and/or aluminium) NOTE Carbon steels used in the petroleum industry usually contain less than 0,8 % mass fraction carbon. [ISO 15156-1:2009, 3.3] API RP 17A Addendum 1, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, December 2010. Global Standards 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  

Carbon steel

Alloy of carbon and iron containing a maximum of 2 % mass fraction carbon, 1,65 % mass fraction manganese, and residual quantities of other elements, except those intentionally added in specific quantities for deoxidation (usually silicon and/or aluminium). API SPEC 6A, Specification for Wellhead and Christmas Tree Equipment, Twentieth Edition, October 2010 (Addendum November 2012). Global Standard  

Carbon steel

An alloy of carbon and iron containing a maximum of 2% carbon, 1.65% manganese, and residual quantities of other elements, except those intentionally added in specific quantities for deoxidation (usually silicon and/or aluminum). API SPEC 16C, Specification for Choke and Kill Systems, First Edition, January 1993 (Reaffirmed 2001). Global Standards

Joint

Joint

Definition(s)

Joint

Means of connecting two or more components
  • EXAMPLE: Plain pipe to a fitting, or plain pipe to plain pipe.
Source: ISO 14692-1:2017, Petroleum and natural gas industries — Glass-reinforced plastics (GRP) piping — Part 1: Vocabulary, symbols, applications and materials, Second Edition, August 2017. Global Standards

Joint

A section of the structural member including the coupling and guidance devices is called a “joint”; the associated sections of lines are also called joints. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Workover Control System

Workover Control System

Definition(s)

WOCS

The WOCS, also commonly referred to as the installation/workover riser package, provides the means to remotely control/monitor all of the required functions on the C/WO equipment, subsea tree and downhole equipment during the various phases of the C/WO operation. The WOCS usually consists of the following components: pumping unit to provide hydraulic power; main control panel; remote control panel on the drill floor; process shutdown panel near the production test equipment; emergency shutdown panels at main escape routes; umbilical(s) on powered winch(es). Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Rigid-pipe Non-integral Riser

Rigid-pipe Non-integral Riser

Definition(s)

Rigid-pipe non-integral riser

The lines in a non-integral riser can be run and retrieved separately from each other and from the main structural member. A non-integral riser includes a tensioned central structural member which may carry fluids or perform other functions besides providing structural support and guidance to lines. The structural member is fitted with support/guidance devices to locate and laterally guide individual lines. The two ends of the structural member are fitted with the two halves of a coupling. A section of the structural member including the coupling and guidance devices is called a “joint”; the associated sections of lines are also called joints. The two ends of each line joint are fitted with mechanical/pressure couplings, typically threaded box and pin, independent of the central pipe coupling. Other lines are installed individually after the structural member is installed and tensioned. They are retrieved individually before the structural member is retrieved. This design has the advantages of simplicity and of permitting the retrieval of a single line (e.g. for repair/replacement) without requiring the shut-in and retrieval of the whole system. It has the disadvantage of being slow to run or retrieve. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Riser Joint

Riser Joint

Definition(s)

Riser Joint

One section of the riser string having the main tube fitted with a box and pin coupling, choke, kill, and auxiliary lines (optional), and brackets, clamps, thrust collars, and buoyancy modules, as applicable.

Source: API Specification 16Q, Design, Selection, Operation, and Maintenance of Marine Drilling Riser Systems, Second Edition, April 2017. Global Standards

Riser Joint

Joint consisting of a tubular member(s) with riser connectors at the ends. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards

Riser Joint

A section of the production riser, consisting of the structural member, lines and coupling, is collectively called a “riser joint”. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Riser Joint

A section of riser main tube having ends fitted with a box and pin and including choke, kill and (optional) auxiliary lines and their support brackets. Source: API RP 16Q, Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems, First Edition, November 1993 (Reaffirmed August 2001). Global Standards  Source: ISO 13624-1:2009, Petroleum and natural gas industries – Drilling and production equipment – Part 1:Design and operation of marine drilling riser equipment. Global Standards  

Riser Joint

Joint consisting of a tubular member(s) midsection, with riser connectors at the ends. NOTE Riser joints are typically provided in 9,14 m to 15,24 m (30 ft to 50 ft) lengths. Shorter joints, pup joints, can also be provided to ensure proper space-out while running the subsea tree, tubing hanger, or during workover operations. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global Standards  

Riser Joint

A section of riser pipe having ends fitted with a box and a pin, typically including integral choke, kill and auxiliary lines. Source: ISO 13624-1:2009, Petroleum and natural gas industries – Drilling and production equipment – Part 1:Design and operation of marine drilling riser equipment. Global Standards
Rigid-pipe Integral Riser

Rigid-pipe Integral Riser

Definition(s)

Rigid-pipe integral riser

The lines of a rigid-pipe integral riser cannot be retrieved separately. An integral riser with external lines includes a central structural member which can carry fluids or perform other functions in addition to providing structural support to the lines by means of external brackets. An integral riser with internal lines may support these lines at intermediate points along the joint to prevent line buckling. On either integral riser type, the ends of the structural member are fitted with couplings. A section of the production riser, consisting of the structural member, lines and coupling, is collectively called a “riser joint”. When two joints of integral riser are connected, the coupling causes the simultaneous connection of all of the lines with full design-pressure capacity. Integral risers are compact and simple to run, however they require system shut in and retrieval for repair/replacement. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Multibore Hybrid Risers

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 Standards
Completion/workover (C/WO) Riser Systems

Completion/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 Standards  

Completion/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 Standards
Completion Riser

Completion 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 Standards  

Completion 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 Standards
Workover Riser

Workover 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 Standards  

Workover 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 Standards
Non-integral Riser

Non-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 Standards  

Non-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 Standards
Light Well Intervention Systems

Light 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 Standards
Rigid Workover Risers

Rigid 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 Standards  
Subsea Wireline Systems

Subsea 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 Standards  
Subsea Reeled-tubing Systems

Subsea 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 Standards  
Through-flowline System Intervention

Through-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 Standards  
Wax Appearance Temperature

Wax 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 Standards  
Flexible Pipe

Flexible 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 Standards  

Flexible 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 Standards
Subsea Processing Systems

Subsea 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 Standards