Subsea Manifold Components
Subsea manifold valves are mounted within the piping system to control the production and injection fluids. The reliability of subsea manifolds is strongly dependent on subsea valves because the flow is directly through them. In a diverless subsea manifold, these valves are hydraulically actuated, on/off types and are used to direct the flow to the manifold production header or to the manifold test header and they are also used in chemical injection lines. In the manifolds designed to allow the passing of pigs, valves are used to provide the connection between the main headers.
One of the main design requirements of the subsea system is that all remotely controlled valves should be located within retrievable manifold frames or modules. The selection and location of the valves on the manifolds is of prime importance. Design specifications of valve type, size, pressure rating, and actuator function are required prior to detailing manifold layouts. Every type of valve has its strengths and weaknesses. For some applications, a ball valve provides a number of benefits over an API 6A gate valve that would potentially make it the best choice. Some of the features to consider are size, weight, height, speed of operation, seal wear, weldability, depth sensitivity, ROV intervention, fluid displacement during operation, and low-pressure sealing.
Gate valves or ball valves are two typical valves used in the manifolds. Gate valves have a long history of use in subsea blowout preventer (BOP) stacks, trees, and manifolds and are considered relatively reliable devices because both the valve and the valve actuators have been through extensive development with proven field use and design improvements.
At that time, pipeline gate valves were the standard valves used in liquid pipelines. Even today, gate valves are frequently specified for liquid pipelines, and ball valves are specified for gas pipelines. When gas wells were completed in the Gulf of Mexico in the 1960s, ball valves were installed in pipelines both as isolation valves and as terminal valves to tie in lateral lines from future wells and platforms. In the late 1970s, ball valves were installed in the North Sea and encountered problems due to the more challenging conditions of the sea. Later, ball valves were installed in subsea projects as emergency shutdown (ESD) valves to prevent gas in a pipeline from flowing back to a platform in the event of a major leak.
Size and Pressure
Manifold valves are usually required to carry the same pressure rating as Christmas tree valves in terms of the possible failure of the choke or valves on the tree. Normally, ball valves can more easily accommodate the size, whereas gate valves are more suited for the pressure. When people think of deepwater valve applications, API 6A gate valves typically come to mind because the first ventures into subsea at any depth have been exploration drilling. Typical BOP chokes and kill stack valves are 3 1/16-in. (0.078m), 10,000- or 15,000-psi API 6A gate valves. For the API 6A gate valves, size is a real challenge, while the increasing need for 10-ksi ball valves has been the biggest development effort for ball valves.
Gate valves are preferred for all smaller sizes in which they are available, and ball valves are preferred for sizes 10 in. (0.25m) and larger. Size has revealed another anomaly in subsea manifolds for all valves. Specifications are calling for 5000- or 10,000-psi valves that meet API 6A or 17D requirements in pipeline sizes that do not exist in either specification. A 5 1/8-in. (0.13m) or 6 3/8-in. (0.16m) 6A valve size defines the bore, but pipe size is defined by the outside diameter. A manifold specification calling for 8-in. (0.20m), 10,000-psi valves will likely be met with a valve having a 6 3/8–in. (0.16m) bore. The pipe grade and wall thickness must be known to properly select the valves.
The choke is a kind of valve used to control the flow of the well by adjusting the downstream pressure in a production manifold or upstream pressure in an injection manifold to allow commingled production/injection. For diverless subsea manifolds, hydraulic-actuated variable chokes are used. These chokes can be residents at the manifold or installed at retrievable modules.
Subsea valves are normally actuated by means of a direct control system or electrohydraulicmultiplexed system.The use of one type or another depends on the distance of the subsea manifold to the host platform and the number of functions to be controlled. A multiplexed control system provides a quick response tovalve actuation and greatly reduces the number of umbilicals needed. The control system has a significant impact on the acquisition cost of a subsea manifold, especially the multiplexed control system. The impact on maintenance costs is also considerable because an unexpected failure can lead to an interruption of the well’s production.
The main objective of the subsea module is to house components with a high failure probability in a place that permits the recovery of all components either by divers, ROVs, or a specific running tool, thus saving time during maintenance operations. One important aspect to be considered in subsea manifold modularization is any increase in cost, weight, and equipment complexity. Modularization increases equipment availability, but it also increases the number of connections, which in turn increases the chances of leakage. Therefore, it is essential for a highly reliable seal component to be used in these modules and retrievable cartridges.
The overall weight of the manifold is dependent on the piping configuration adopted. Normally only functional requirements are established by operators, so manufacturers are not given the arrangement to be adopted, , which leaves the design team relatively free to design the piping system. The use of flanged components or welded ones is basically dependent on manufacturers’ criteria and must be considered in the analysis of a manifold’s designed lifetime.
A template is a subsea structure on the seabed that provides guidance for drilling or other equipment. It is also the structural framework that supports other equipment, such as manifolds, risers, wellheads, drilling and completion equipment, and pipeline pull-in and connection equipment. The structure should be designed to withstand any loads, such as from thermal expansion of the wellheads and the pipelines. Production from the templates may flow to floating production systems, platforms, shore, or other remote facilities. The template is typically used to group several subsea wells at a single seabed location. Templates may be of a unitized or modular design. Typical templates are described next. Actual templates may combine features of more than one of these types.
A modular template is one that is installed as one unit or as modules assembled around a base structure, such as a well.
A manifold template is one that is used to support a manifold for produced or injected fluids. Wells would not be drilled through such a template, but may be located near it or in the vicinity of the template.
Well Spacer/Tie-Back Template
A multiwell template that is used as a drilling guide to predrill wells prior to installing a surface facility is referred to as a well space/tie-back template. The wells are typically tied back to the surface facility during completion. If subsea trees are to be installed on the template, it should provide proper mechanical guidance for positioning of the trees and sufficient room for all installation and intervention operations.
A riser-support template supports a marine production riser or loading terminal and serves to react to loads on the riser throughout its service life. This type of template may also include a pipeline connection capability.Templates designed to provide underwater wellhead support should incorporate a well bay and associated structure capable of withstanding drilling loads. The design should provide sufficient rigidity to maintain required spatial tolerances between components when under deflection.
Design loads may also include weight from surface casings due to inadequate cementing and drilling riser loads caused by vessel offsets. The template should withstand pipeline installation forces, snag loads, and any loads induced by thermal expansion. If the template cannot be practically designed for pipeline snag loads, a protective breakaway deviceshould be considered. The template should provide a sufficiently strong foundation to be able to transfer design loads into the seabed. The template should be capable of withstanding the applicable loads due to the use of maintenance equipment.
In seismically active regions, the effects of earthquakes on the template should be considered. The design should allow for thermal expansion loads of elements heated by the produced fluid stream. The possibility of accidental snagging of the structure by trawling equipment, anchors, or other foreign objects, and the resultant loading, should be considered. The structural shape and strength should be designed to accommodate the maximum snag load without damaging critical components.
If the template is to be recovered at the end of the project, a recovery method should be considered. During installation and retrieval of the template, the vertical center of buoyancy should be maintained well above the center of gravity. Placement of any sacrificial anodes should be considered, avoiding areas subjected to accumulation of drill cuttings.
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