Subsea Connections and Tie-in Methods 

The term “jumper” (or "well jumper") is generally used when referring to connection system to Xmas trees, while “spool” is more used for the connection system between production flowline terminations (ILT/FLET/PLEM) and other subsea structures like Riser Base, GI or WI Xmas trees, manifolds, Multi-Phase Pump (MPP) module or other subsea processing unit (or as a general term for all types of subsea connections).

Figure 5.2 - Horizontal rigid (steel) jumper arrangement

Rigid well jumpers are generally 20m to 30m long for direct tie-in of x-mas trees to flowline or via a manifold system.

Rigid spool pieces could be as long as 100m to 150m to perform flowline tie-ins to riser base structures (USAN, CLOV).

Flexible spool pieces can be as long as 100m to 300m (no specific technical length limitation) to perform tie-in to riser base (GirRi Phase 2, KAOMBO).

Spools and well jumpers are typically either ‘horizontal’ (Section 5.2.2, “Horizontal Tie-In System”) or ‘vertical’ (Section 5.2.3, “Vertical Tie-in System”) and these orientations applied to both spool planes and connector tie-in (or stroking) axis.

Innovative vertical ‘M’ spools and jumpers have been studied (e.g. Pazflor pre-project phase by SEAL Engineering) with the purpose of combining the advantages of the horizontal connection (manifold recovery by connector stroke-out) and ‘compact’ vertical ‘footprint’.

Conventional horizontal spools are either U-shaped or Z-shaped systems, 2D or 3D, as discussed in the following section.

A spool/jumper configuration is called “horizontal” when the spool is positioned in the horizontal plane. The following figure shows a typical horizontal production well jumper, which is deployed and stab into the subsea receptacle structures. S-bends at each end of the jumper enable the jumper to be supported by the seabed soil.

Figure 5.3 - Horizontal Jumper between x-mas tree and manifold (e.g. Girassol, Rosa Lirio, Moho Bilondo)

U versus Z jumper

The two classical configurations for the well jumpers are U-shape (as presented in Figure 5.5, “U-shaped well jumper installation based on supply boat and drilling rig crane (Girassol)”). and Z-shape (as presented in Figure 5.6, “Z-shaped well jumper installation using construction vessel heavy lifted crane (Girassol)”). The following figure presents the U and Z configuration for production well jumpers.

U shaped spools are generally not used for flowline to manifold tie-ins, due to flowline lay pattern and footprint at the manifold/wells cluster area.

Figure 5.4 - Two possible configurations for production well jumpers (top view)

Both of these configurations have been recently used on West Africa deepwater projects. The Girassol experience can be used to illustrate the different aspects of each configuration (see following pictures).

Figure 5.5 - U-shaped well jumper installation based on supply boat and drilling rig crane (Girassol)

Figure 5.6 - Z-shaped well jumper installation using construction vessel heavy lifted crane (Girassol)

It can be seen that for Z-shaped jumpers, the two connectors are stroked in reverse directions (inducing stress in the jumper), while for U-shaped, stroking of the two connectors is in the same direction.

The following figure presents both ‘equivalent’ U and Z shaped injection well jumpers based on Girassol design data and functional requirements. The well jumpers presented are the “minimal well jumper” configuration, which corresponds to the shortest distance between the flowline (in-line tee) and injection Xmas tree, while maintaining sufficient flexibility to withstand the enforced displacements (e.g. thermal expansion, connector tie-in stroke in or stroke out), etc.

Figure 5.7 - U and Z shaped injection well jumpers comparison

It can be seen that the Z-shaped jumper is significantly longer than U-shaped jumper, for the same functional requirements.

Due to spool geometry, special rigging incorporating a spreader beam (Figure 5.6, “Z-shaped well jumper installation using construction vessel heavy lifted crane (Girassol)”) is required to take connector loads without overstressing the jumper. For the Z-shaped jumper, rigging requirements are even more stringent with respect to crane height and lift capacity (Figure 5.5, “U-shaped well jumper installation based on supply boat and drilling rig crane (Girassol)”) and require larger transportation and installation means, i.e. deck space, crane lifting capacities.

Based on the above arguments, U-shaped jumpers are to be generally preferred when compared to Z-shaped jumpers.

A rigid spool/jumper system is called “vertical” when it is positioned in the vertical plane. Vertical spools/jumpers are typically deployed directly and stab onto the subsea structure hub connectors.

Figure 5.8 - Various vertical connection spool/ jumpers, by courtesy of Schlumberger/ Nexen Petroleum (left - Aspen field, GoM) and FMC (right)

Vertical spools are typically designed in free span configuration. It is not necessary to rely on seabed soil support to maintain the spool integrity. This is a benefit (1) as the design does not rely on soil characteristics and bathymetry data and (2) in the case of flowline crossing.

The deck area required for transportation of a vertical system is significantly less than for the equivalent horizontal spool/jumper. It will usually be possible to fit several spools on the transportation vessel deck simultaneously.

For recovery of a xmas tree, the vertical well jumper connections must be broken at both ends, and the well jumper recovered to surface or subsea stored. The other way for well jumper to remain in place when the xmas tree is recovered is to incorporate an additional intermediate connection via the flow base. This solution requires an additional connection (xmas tree to flow base) for each well, which is considered to be an important disadvantage. For recovery of a manifold, all well jumpers and tie-in spools at the well centre must be disconnected and recovered to surface.

The main advantages of a vertical tie-in system in comparison with horizontal systems are as follows:

The main perceive disadvantages of vertical tie-in systems are as follows:

In general terms, the vertical tie-in system offers cost advantages for fabrication, transportation and installation phases, but there are of concern during the operation (and maintenance) phase.

Preliminary designs are available on innovative vertical ‘M’ spools and jumpers, featuring geometry contained in a vertical plane combined with horizontal connection method. The purpose of this alternative is to combine the advantages of the horizontal connectors (e.g. manifold or tree recovery by connector stroke-out) and ‘compact’ footprint, as further illustrated in Figure 5.9, “Vertical ‘M’ shape Spool featuring Horizontal Connector (typical)”.

Figure 5.9 - Vertical ‘M’ shape Spool featuring Horizontal Connector (typical)

Figure 5.10 - Typical drill centre layout with horizontal spools and jumpers

Figure 5.11 - Typical drill centre layout with vertical 'M' jumpers and spools.

Accurate measurements are required before rigid steel jumper fabrication, either on shore or on board the laying vessel (or barge, etc.). These measurements aim to define the relative position of both spool/jumper end future locations (distance and inclination between the two connection points) in order to define its final dimensions and to allow rapid and hazardless installation.

These measurements are generally obtained by acoustic array or occasionally by taut wire metrology (see Section Chapter 7, Hot-Tap Tie-in "Subsea Metrology").

The main phases for a rigid spool/jumper fabrication and installation are described below:

Figure 5.12 - Vertical jumper installation (Stab & hinge over method)

Figure 5.13 - TOTAL Girassol field, rigid steel jumper installation (spreader bar, horizontal connectors)

No diameter or water depth limitations have been identified or to be expected.

The main advantage (see Chapter 6, Advantages & Disadvantages "Advantages and Disadvantages") of the steel jumper is its economical aspect when combined with stringent heat insulation requirement. This point suffices to explain its extensive use in the Gulf of Mexico and West of Africa deepwater developments.

Figure 5.14 - Flexible jumper principle

The principle of this method is to perform the link between two subsea structures (tree and manifold) or between a subsea structure and a flowline end termination (PLEM) by means of a flexible jumper. The distance between the two connection points, and hence the length of the jumper, is conventionally about 20m - 100m (i.e. within most medium size vessel lifting capacity).

Figure 5.15 - Flexible jumper fitted with vertical connectors (Aspen field, GoM), by courtesy of Nexen Petroleum

Flexible spools/jumpers can be used for vertical or horizontal connection method. The flexible spool installation method depends on the connector type but it can be basically equipped with:

This tie-in method is dependent on ROV operation for all phases from guiding, landing, stroking to connection, tie-in actuation (clamp or collet fingers actuation) and leak tests.

Flexible spool/jumpers are effective means to perform the connection between flowline end termination and subsea structure or between two subsea structures (i.e. tree and manifold).

Flexible spool/jumpers allow to withstand some imprecision in the position of line ends or subsea structures (and the potential flowline thermal expansion); thus there is no drastic requirements concerning subsea metrology (unlike rigid spool/jumpers) and it is sufficient to position pipeline termination head and/or subsea structure within less stringent target boxes.

Flexible spool's diameter and water depth limitation are dictated by the flexible technology. The use of flexible spools for deepwater applications would be limited mainly by economic consideration.

Figure 5.18 - Pull-in principle

The lay down and pull-in method consists in pulling in and connecting a flowline or umbilical, laid down on the seabed in a predetermined target area, to a subsea structure (X-mas tree, manifold, riser base).

This method is effective for both first end and second end extremity connections of flowline to subsea structure. Typical pull-in force expected for such an operation is about 5-10T, depending on the line type and soil conditions (friction coefficient) and a pull-in distance to be limited to less than 50m.

The lay down and pull-in operation can be divided in three main phases:

The lay-down and pull-in method has been extensively used in most oil provinces but mainly for shallow water depth applications (200 - 400 msw). Petrobras has experienced this method with no satisfactory results (i.e. near seabed ROV operation on soft soil).

The ROT based connection systems utilising a surface-operated winch become unsuited as the water depth increases due to the number, lengths and weights of lines running from surface (lifting line, pull-in cable, controlled umbilical, etc.).

For deepwater operation, the ROV-mounted tools (e.g. Flexconnect, RTS) are better suited.

The “lay down and pull-in” method requires good seabed conditions:

This tie-in method is therefore not recommended for deepwater connection in the case of very soft soil conditions (i.e. 5-15kPa) and poor visibility near seabed.

Figure 5.19 - Direct pull-in

The direct pull-in method consists in connecting a flowline or an umbilical to a subsea structure (manifold, tree) by pulling it directly to the tie-in point in order to:

For the pull-in, a cable coming from a surface winch or subsea winch can be used and then the connection is performed by a separated tool.

This method is effective for first end tie-in of umbilical, flexible and relatively small diameter rigid line.

The main phases of a direct pull-in can be described as follows:

The direct pull-in method allows performing the initiation of a flowline without using a PLEM and initiation anchor point as the subsea structure is used as an anchor point. This involves taking the pull-in loads into account for the design of the structure.

This method is very effective for flowline initiation with however two main drawbacks (see Section 6 "Advantages and Disadvantages"):

The “Direct pull-in” method is limited by the design maximum water depth operability of the pull-in tool and has been used on Nork Hydro TOGI for up to 24" rigid sealine.

Figure 5.20 - Deflect to connect principle

This method consists in lifting a defined length of a pipeline (typically 500m – 800m) by means of subsea buoys, deflecting the flowline end near the structure with a vessel or subsea winches and finally pulling the flowline into the subsea structure in order to perform the connection.

The deflect-to-connect method is effective for rigid pipeline tie-in to a subsea structure. The pipeline must have been laid along an off-centred straight line near the subsea structure prior to the deflection (typical distance 100m – 200m).

After the flowline has been laid on the seabed, a typical deflect-to-connect operation can be performed as follows:

As an example, about 15 air bags and 5 transponders were spread along the 400m – 500m of deflected pipeline on the Troll Olje project.

This is done by steps of approximately 10-20m until the pull-in head is in front of the subsea structure; the pipeline curvature is checked at each step by means of transponders and compared to the theoretical values (e.g. the minimum bending radius and line tension must always be controlled to avoid any local buckling).

This method is mainly used to connect large diameter rigid pipeline because of the difficulty to manipulate and connect them with another method. The flowline final curve must also consider the service conditions, in terms of thermal expansion, possible slugs, etc. Besides these technical issues there is no foreseeable limitation for deepwater applications. Several diverless deflect-to-connect operations have been successfully performed including the two 16" ID export lines on Norsk Hydro Troll B project (in 1994) and the two Elf East Frigg 24” bundles (in 1988).

Figure 5.21 - Vertical Stab and Hinge Over principle

This tie-in method is used to initiate flowline or umbilical first extremity by stabbing and latching it (by means of a hinged torpedo) in a receptacle (i.e. funnel) mounted on the subsea structure foundation (manifold support structure MSS, XT Permanent Guide Base PGB, PLEM). The connection is performed after the laying operation by means of an ROV-mounted connection tool (see Section 4.4, “ROV-mounted Connection Systems”).

During the flowline (vertical) initiation its first extremity is lowered and latched to the subsea structure by the stab and hinge over method (Figure 5.21, “Vertical Stab and Hinge Over principle”):

This tie-in method is effective for rigid, flexible and umbilical lines but attention must be paid to the rigid line stabbing and initiation loads. A minimum flexibility of the line is required during the stab step of the method, particularly if no heave compensator is used.

This method is probably the most cost effective solution to perform the first end initiation and tie-in for deepwater applications. No water depth limitation is expected (i.e. the only limiting factor is the connection tool maximum water depth operability).

The only limitation is with large diameter rigid pipeline due to potential high load on the subsea structure during the stabbing and hinge-over phases, although passive heave compensated tensioners would annihilate this limitation.

This method has for example been used to connect 6" flowlines and umbilical to manifold on the Shell's Mensa field (1620m); hydraulic connectors powered by ROV via an ROV interface panel were used.

This method, developed by Petrobras, was used up to 1992 and was then replaced by the vertical stab and hinge-over connection method (see Section 5.7).

Figure 5.22 - Lay-away principle, (by courtesy of Petrobras)

The lay-away and lay-to surface tie-in method is effective to connect first or second end of a flexible and umbilical lines to a subsea tree.

This method consists in performing the connection between the lines and the X-mas tree on-board a drilling rig prior to the lowering of the assembly.

The lay-to or lay-away methods, which have been primarily developed by Petrobras to improve existing pull-in methods, can be described as follows.

The lay-away tie-in procedure can be divided in five main phases:

The lay-to operation uses the same methodology:

The main advantages of this method (see Section Chapter 6, Advantages & Disadvantages "Advantages and Disadvantages") are clearly to allow the connection and all tests to be performed in surface.

The lay-away method was a standard for diverless connections in Campos Basin up to 1992 where some 57 lay-away operations, including 36 guideline-less operations, have been successfully conducted in water depths ranging from 280m to 1030m. Then the vertical subsea connection system (see Section Section 5.11, “Hybrid Steel Pipe & Flextail”) was developed to overcome its drawbacks (mainly the obligation of the presence of both drilling rig and laying vessel and also the fact that only connections to subsea trees are possible).

Figure 5.23 - Hybrid steel pipe and flextail principle

This method consists in integrating a pre-determined length of flexible pipe (spur line, flextail) to a rigid flowline end(s), thereby allowing handling more easily the extremities during the tie-in phase.

The methodology can be considered similar to the flexible jumper method, as a flexible line is used to perform the connection between a rigid flowline and a subsea structure, but the ‘flextail’ and the rigid flowline are connected together in surface, simplifying this part of the tie-in operation and allowing to perform external connection leak tests prior to the lowering of the hybrid pipe.

This method has been used mainly by Technip for Petrobras (Roncador) in Brazil.

The flextail is used to perform the connection between a rigid pipeline and a subsea structure. It can be installed as per one of the following methods:

An hybrid steel pipe and flextail can be used with the following restraints: