Multiport flow selector optimises oil and gas production testing

January 23rd, 2013, Published in Articles: EngineerIT

by Chautanya Shah, Emerson Process Management; Prathesh Selvaraj and Paul Schafbuch, Valve Automation, USA

Using multiport flow selectors (MPFS) in oil and gas applications improves production testing and reservoir management. MPFSs facilitate cost-effective and compact selection and diversion of fluids from individual wells for testing, without disrupting the production from all other wells.

Fig. 1: Piping network with seven
wells and dual manifold.

Fig. 2: Simplified piping
with a multiport flow selector.

Testing of constituent flows is a crucial part of the production process. Oil, water, brine, condensate, gas, and other fluids must be monitored and measured regularly. Historically, wells were connected to a complex piping network. One manifold connects all wells to production. A second manifold connects the well selected for testing to a shared multi-phase flow meter or separator plus single phase flow meter set.

While this conventional approach uses common valves, actuators, and piping components, it is more expensive and electrically complex than a multiport system.

Conventional approach

Fig. 1 illustrates a typical well test manifold. During normal operation, all the wells are connected to the common production and test lines. For instance, if well 1 needs to be tested, close valve “B” and open valve “C”. The flow of well 1 is then directed to the test facility while all other wells would continue to the production line. Regardless of the test technology, individual well flow must be diverted for testing. Typical onshore oil and gas production has wells scattered over a large area, such that it is not practical to manually open and close the manifold on/off valves. The oil field may be in remote deserts, deep jungles, or in sub-zero environments, such that local 24 x 7 human intervention means additional infrastructure. Any scattered network of wells requires high investment during the green field stage of the project capital expenses (CAPEX) and more maintenance operating expenses (OPEX) during the operation stage. The initial CAPEX and future OPEX has a positive correlation with the spread and accessibility of the field. Consequently, the flow diversion is usually automated.

Fig. 3. Actual MPFS in an offshore field.

In offshore fields, it is important for platform equipment to be as light and small as practical so that the platform is less costly to construct, operate, and maintain. Developers are continually looking for technologies that make offshore platforms more economical and require minimum human intervention. Compared with onshore fields, manual operations on remote platforms are more expensive.

Using a multiport flow selector

A comparison of Fig. 1 and 2 shows how the complex network of piping can be minimised by using a multiport flow selector (MPFS). As illustrated in Fig. 2 many elements like valves, control points and wiring of the conventional system can be reduced / eliminated by implementing the MPFS system. MPFS directs multiple wells to a single production flow stream and one well into the test system at the same time.

Design

A MPFS typically has eight inlet and two outlet connections.

Inlets: out of eight inlets it is recommended to connect seven to the wells, the eighth connection is generally used as a parking location and/or observation port for the selector plug. This allows for an observation port for temporary maintenance, and flushing and allows production of all seven wells if the test system is offline. The internal plug diverts one well’s fluid stream to the test port at a time. The plug is rotated to align with the well inlet to be tested.

Outlets – MPFS: Test outlet connects to the test system and the group outlet carries the flow of all other wells together to the production header.

Normally the pressure drop across a MPFS is very low, as the flow streams are only diverted, not restricted. In some applications, flow velocity will limit the maximum flow or maximum number of connected wells, but this condition is not different from using the conventional dual manifold system.

 

Conventional

MPFS

Complex piping arrangement / valves / actuators and controls

Simple piping arrangement with minimum valves

Large number of leak points risking production downtime

Reduced leak points

Occupies more space and much higher weight

Compact system, reduced space and weight

Prone to human error

Reduced / minimum human error

Expensive

Economical

 

Table 1: Comparison between MPFS amd a
conventional manifold system.

 

Operation

An electrical actuator with electronic controls enables easy control and monitoring of a MPFS. Whenever well testing is to be performed, operators can simply issue a remote command to position the diverter plug to the desired well inlet. This reduces the chances of manual error in the field which may lead to production downtime and untoward incidents.

Operation can be done remotely and locally as an MPFS actuator supports numerous communication protocols.

The actuator’s display shows which well is under test at any given time. Built-in diagnostics also make sure that issues like control error, motor overload, and power loss are understood and addressed more precisely.

MPFS provides an additional advantage in sour oil and gas fields. When high nickel-chromium internal cladding is required, the simplified piping and fewer valves result in a much lower cladding cost.

Conclusion

In a nutshell, the MPFS system compares quite favourably with the conventional manifold system, as detailed in Table 1.

Well test systems that use MPFS have significant advantages in construction and operations compared with traditional conventional manifold system. A single MPFS commonly replaces 14 valves and actuators and significantly reduces piping and wiring. These benefits are larger in offshore and sour field production.

With MPFS, well flow is inherently not interrupted when switching lines for testing. Automation is simplified with a single MPFS actuator. Operations and maintenance work hours are reduced, along with the risks related to health, safety, and environmental standards.

Contact Mark Tapson, Emerson Process Management,
mark.tapson@emerson.com

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