Integral Flexible-pipe Risers

Integral Flexible-pipe Risers

Definition(s)

Integral flexible-pipe risers

Integral flexible-pipe risers consist of multiple lines which cannot be retrieved individually. The configuration of such risers may range from relatively simple arrangements, such as where several flexible production lines are incorporated within a common outer jacket, through to more complex arrangements, such as IPUs and multibore flexible-pipe risers as described below. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
“Steep Wave” Riser

“Steep Wave” Riser

Definition(s)

“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  
“Lazy Wave” Riser

“Lazy Wave” Riser

Definition(s)

“Lazy 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
“Steep S” Riser

“Steep S” Riser

Definition(s)

“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  
“Lazy S” Riser

“Lazy S” Riser

Definition(s)

“Lazy S” riser

The “lazy S” riser runs in a double catenary configuration from the FPS to the seabed over a mid-water pipe tray supported by a subsurface buoy. The subsurface buoy is kept in position by a chain or cable attached to a deadweight anchor positioned on the seabed. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
“Freehanging” Riser

“Freehanging” Riser

Definition(s)

“Freehanging” riser

The “freehanging” riser runs in a single catenary from the FPS to the seabed. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Dynamic Risers

Dynamic Risers

Definition(s)

Dynamic risers

Production risers tied back to floating structures are inherently more complex than those tied back to fixed structures, since they need to be able to accommodate the motion of the floating structure. For this reason such risers are commonly referred to as dynamic risers. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Riser Base

Riser Base

Definition(s)

Riser base

The combination of a riser support template and the associated piping and connections for the riser and pipeline(s) is also often referred to as a riser base. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Riser bases

Riser bases are used to connect flexible risers to flowlines, and may also be required to support subsea buoy/arch systems (e.g. steep-S configurations). The riser base can be either a gravity structure, a piled structure or a suction/anchor pad. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards  

Riser base

Structure positioned on the seabed, used to provide a structural and pressure-tight connection between a flexible riser and a flowline. NOTE 1 See 4.4.8. NOTE 2 It may be a PLET or a PLEM. 3.1.22. Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global Standards  
Manifold

Manifold

Definition(s)

Manifold

Manifold(s) include connection points for tie-in of the flowline(s) and/or umbilical back to the host facility, as well as connection points for the individual production wells. Manifolds require some type of framework to provide structural support of the various piping and valves, etc. Sometimes this framework and the manifold are incorporated into the towhead of a pipeline bundle, in which case this is commonly referred to as a PLEM. Alternatively, a separately installed template may be provided to support the manifold as described below. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Manifold

A manifold is a system of headers and branched piping that can be used to gather or distribute fluids, as desired. Typically manifolds include valves for controlling the on/off flow of fluids, and may also include other flow control devices (e.g. chokes) if these are not mounted on the individual subsea trees. Manifolds can be used to gather produced fluids and direct selected wells to a well test line, as well as to distribute injected fluids (gas or water) or gaslift gas to individual wells. An alternative to the use of individual valves on each branch line is the use of a multiport selector which can be remotely switched to direct a desired well into a test line for instance, while leaving all other wells flowing into the main production line. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Manifold

Length of pipe with multiple connections for collecting or distributing drilling fluid. Source: API RP 13C, Recommended Practice on Drilling Fluids Processing Systems Evaluation, Upstream Segment, Fourth Edition, December 2010. Global Standards  

Manifold

Piping system for the collection and/or distribution of a fluid to or from multiple flow paths. Source: API STD 521, Pressure-relieving and Depressuring Systems, Sixth Edition, January 2014. Global Standards Source: API STD 521, Pressure-relieving and Depressuring Systems, Fifth Edition, January 2007 (Addendum May 2008). Global Standards  

Manifold

An assemblage of pipe, valves, and fittings by which fluid from one or more sources is selectively directed to various systems or components. Source: API SPEC 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, Upstream Segment, Second Edition, July 2004. Global Standards  

Manifold

A system of pipe and valves that serves to convert separate flows into one flow, to divide one flow into separate parts, or to re route a flow to any one of several possible destinations. Source: IADC UBO / MPD Glossary, December 2011. Global Standards
Direct Vertical Connection Method

Direct Vertical Connection Method

Definition(s)

Direct vertical connection method

In this method (see Figure A.29), the flowline terminates in a hydraulically actuated connector that is landed directly onto a vertical hub located on the subsea structure. All operations are conducted by the sealine installation vessel itself. After being landed, the connector is locked to the hub by applying hydraulic pressure via either an ROV tool or a hydraulic hot-line from the surface. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Deflect-to-connect Method

Deflect-to-connect Method

Definition(s)

Deflect-to-connect method

This method (see Figure A.28) is normally used for a second-end tie-in, where the lay vessel pre-installs buoyancy and chains at predefined locations along the flowline or umbilical. After the end of the flowline or umbilical is installed inside a predefined target area, the tie-in vessel releases the line and surveys it to ensure suitable positioning and buoyancy. The pull-in head on the end of the line is then connected by a wire, routed via the subsea equipment to which the line is to be connected, to a pull-in winch. The line is then deflected so that the pull-in head is positioned in front of the pull-in porch of the subsea structure. The pull-in and connection tools are then used to complete the tie-in, along the same principles as for a normal pull-in. As the line is normally deflected in an empty condition, water-flooding is performed prior to the make-up of the connection. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Direct Lay-away Method

Direct Lay-away Method

Definition(s)

Direct lay-away method

With this method (see Figure A.27), the flowline or umbilical is keel-hauled from the installation vessel/reelship into the moonpool of the vessel installing the subsea tree, and attached to the tree prior to its deployment. Close coordination between the tree-installation vessel and the reelship is obviously required. As the subsea tree is lowered to the seafloor, the reelship pays out the flowline and commences to move away from the tree installation vessel so that the line is not subjected to overbending. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Stab-in and Hinge-over Method

Stab-in and Hinge-over Method

Definition(s)

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  
Pull-in Method

Pull-in Method

Definition(s)

Pull-in method

This method (see Figure A.25) aligns the flowline or umbilical by pulling it toward its connection point using a wire rope(s) fastened to the flowline end (pull-in head, see 3.1.8). Final alignment and positioning typically requires special tools and/or alignment frames. Temporary buoyancy or flexible jumpers can be used to reduce pull-in forces and moments. In diverless situations, the pull-in is conducted through the use of ROTs. These tools are designed with enough power to pull, lift, bend and rotate the line into its final position at the connection point. The same tool can also assist in locking the flowline or umbilical to the connection point and testing the connection. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Spool/jumper Method

Spool/jumper Method

Definition(s)

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  
Integrated Pipeline Umbilical

Integrated Pipeline Umbilical

Definition(s)

Integrated pipeline umbilical

Another form of umbilical is an IPU, consisting of a combination of one or more production and/or injection lines and/or various service lines, hydraulic lines, electrical and/or fibre optic cables, etc. An IPU differs from a traditional multicore umbilical in that it incorporates a relatively large-bore service or production line. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
MCU

MCU

Definition(s)

MCU

Multicore umbilical. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Multicore Umbilical

Multicore Umbilical

Definition(s)

Multicore umbilical

An MCU is a combination of two or more lines (often of different functional types), including hydraulic lines, electrical cables, fibre optic cables and sometimes small-bore service lines (e.g. chemical injection lines). An MCU is typically armoured with steel wire, but is still sufficiently flexible to be deployed from a reel or a carousel on an installation vessel. Depending on manufacturing and/or transport constraints, an MCU may have dry splices in it at various points along its length, which are typically made prior to loadout of the umbilical onto the installation vessel. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Multiphase Flowmeters

Multiphase Flowmeters

Definition(s)

Multiphase flowmeters (MPFM)

MPFMs are in-line meters designed to measure the relative flows of gas, oil and water in a flowline, without requiring prior separation of the phases. However, some MPFMs do require some form of flow conditioning upstream of the meter. Measurements of the flowstream are made by two or more sensors, and the resultant data are processed to yield the individual phase flowrates. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
PCSs

PCSs

Definition(s)

Production control systems (PCSs)

A PCS provides the means to control and monitor the operation of a subsea production or injection facility from a remote location. The PCS consists of both surface and subsea equipment, see Figure A.23. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Production Control Systems

Production Control Systems

Definition(s)

Production control systems (PCSs)

A PCS provides the means to control and monitor the operation of a subsea production or injection facility from a remote location. The PCS consists of both surface and subsea equipment, see Figure A.23. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Submersible Pump

Submersible Pump

Definition(s)

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  
Hydrocarbon/water Separation

Hydrocarbon/water Separation

Definition(s)

Hydrocarbon/water separation

Hydrocarbon/water separation involves removing most or all of the produced water from the well fluids. The produced water can then either be discharged subsea or re-injected into a suitable formation. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Manifold Template

Manifold Template

Definition(s)

Manifold template

A manifold template is a template used to support a centrally located manifold for gathering of produced fluids and/or distribution of injected fluids (see Figure A.21). In this arrangement, individual satellite wells are clustered around the manifold and tied back (to the manifold) using either flexible or rigid pipe. This type of template also includes connection point(s) for tie-in of flowlines or production risers to/from the manifold to the host facility. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Riser Support Template

Riser Support Template

Definition(s)

Riser support template

A riser support template is a simple template which supports a production riser or loading terminal, and which serves to react to loads on the riser throughout its service life (see Figure A.20). This type of template can be integrated with other types of template, e.g. a manifold template or a multiwell manifold template. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Well Spacer/tie-back Template

Well Spacer/tie-back Template

Definition(s)

Well spacer/tie-back template

A well spacer/tie-back template is a multiwell template used as a drilling guide to predrill wells at a single seabed location. Often this type of template is used prior to installing a surface facility above the template to which the wells are subsequently tied back (see Figure A.19). The wells can also be completed using subsea trees and individual production risers from each subsea tree, tied back to a floating or fixed host facility located above the template. Alternatively, a manifold may be subsequently landed on the template, thus effectively converting this system into a multiwell manifold template, as described further below. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  
Mudline Casing Suspension Systems

Mudline Casing Suspension Systems

Definition(s)

Mudline casing suspension systems

Mudline casing suspension systems were originally designed to be installed by bottom supported drilling rigs (jack-ups) in shallow water applications with surface wellheads, although they are now also often used in deepwater applications with tension leg platforms. These systems provide a suspension point near the mudline to support the mass of casing strings within the wellbore. Typically the conductor and casing strings with their respective annuli are tied back to the surface, where they are terminated using conventional surface wellhead equipment. However, wells drilled with conventional mudline casing suspension systems can also be completed with a subsea tree, provided proper adaptation for the subsea completion is made. In general, subsea completions based on conventional mudline suspension equipment are best suited to shallow-water applications, where structural strength/robustness is not a major issue. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards
Horizontal Tree

Horizontal Tree

Definition(s)

Horizontal tree

In horizontal subsea tree systems, the tree is installed on the wellhead and then the tubing hanger is installed inside the tree. The tubing hanger forms the connection between the production/injection tubing and the tree. Figure A.14 shows a typical configuration with a production guidebase as part of the stack-up. This is to allow tree retrieval without disturbing the flowline and umbilical. Clearly, with the reduced likelihood of having to retrieve the tree, there is less need for a base and, in certain circumstances, the production guidebase may be integrated with the XT spool. This saves a running operation, but at the expense of reducing system flexibility, i.e.: restricts installation of the flowline and umbilical until after the XT is installed; disturbs the flowline and umbilicals if the XT ever has to be recovered. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Horizontal tree

Subsea tree with production and annulus bore valves located external to the tree, where the tubing hanger or dummy tubing hanger is installed after the tree. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global Standards  

Horizontal tree

A system of valves installed on a subsea wellhead that has a master valve in the horizontal outlet from the vertical bore rather than in the vertical bore. Source: API RP 96, Deepwater Well Design and Construction, First Edition, March 2013. Global Standards  

Horizontal tree

Tree that does not have a production master valve in the vertical bore but in the horizontal outlets to the side. Source: API SPEC 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Upstream Segment, Second Edition May 2011 (Errata September 2011). Global Standards
Vertical Tree

Vertical Tree

Definition(s)

Vertical Tree

Vertical trees (VXT) typically have one or two production bores and one annulus bore running vertically through their entire length (as shown in Figure A.3). These bores permit the passage of plugs and tools down through the XT and into the TH or completion string. The vertical bores pass through a series of gate valves (production valves) used to isolate the vertical bores at differing levels. Two or more horizontal bores intersect the vertical bores to permit the passage of fluids into or out of the well, and each has an isolation gate valve (wing valves) to allow flow shut-off. Cross-over valves are usually incorporated to allow communication between the production and annulus bores. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards  

Vertical Tree

Subsea tree with either multiple or concentric bores and production valves located in the vertical bore of the tree, where the tubing hanger is installed before the tree. Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global Standards  

Vertical Tree

Subsea tree with the master valve in the vertical bore of the tree below the side outlet. Source: API RP 96, Deepwater Well Design and Construction, First Edition, March 2013. Global Standards  

Vertical Tree

Tree with the master valve in the vertical bore of the tree below the side outlet. Source: API SPEC 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Upstream Segment, Second Edition May 2011 (Errata September 2011). Global Standards    
Concentric Trees

Concentric Trees

Definition(s)

Concentric trees

Concentric trees are configured with their valves very much like those of the VXT design, but with the distinct difference being that the production bore is located concentrically within the tree and the annulus located off-centre (see Figure A.11). The inherent feature of the design allows access only through the centrally located production bore for TH plug setting, and consequently other means are used for accessing the annulus, such as a flexible pipe run along the side of the completion/workover riser. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards