Intrinsic Safety Supports North Sea Retrofit

Efficient use of intrinsic safety enables quick retrofit.

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By Ian Pinkney

BP is the biggest operator and largest oil producer in the North Sea, producing both oil and gas from a number of different offshore locations. BP has been involved in the North Sea since the mid-1960s when oil and gas exploration and production began. In 1970, BP discovered the two-billion-barrel Forties oilfield, confirming the North Sea as a globally significant oil and gas province. Our terminals at Dimlington and Easington in England process gas from the Southern North Sea (SNS) fields. The terminals’ maximum handling capacity is approximately 300 million cubic feet of gas per day.

BP Exploration was looking to replace an obsolete DCS used at the BP gas import terminal and on the BP Hyde platform. The Hyde field is located in the SNS and was the first gas field in this area to be developed using horizontal wells. Production from the Hyde field and from the NW West Sole field is processed and metered at the surface facilities on the Hyde platform. After processing, gas is then flowed into the West Sole system via a 12.5-km, 14-inch pipeline.

The existing DCS at the normally unmanned installation (NUI) on the Hyde platform was old and had several problems, most critically, its tendency to drop communications between the platform and the terminal frequently. This caused shutdowns and required a platform system re-set at considerable cost and inconvenience, as intervention was required via helicopter and resulted in substantial lost production revenue.
Finding a suitable replacement for the DCS involved facing a number of stiff challenges – the ability to find and implement the replacement system within a very tight timeframe being the most significant. BP’s total project completion schedule was eight weeks from start to finish.

The system would need to include approximately 450 I/O points and would need both intrinsically safe (IS) and non-IS interfaces. In addition, the system needed to overcome the dropped communications problems. The communications architecture would require the ability to handle both Ethernet and microwave signals under very tight bandwidth/speed constraints.

Why IS?

It is BP SNS policy to use IS whenever new control loops are added due to maintenance factors. Although we were not replacing any loops at the Hyde platform DCS replacement, the I/O had to be like for like.
Maintenance factors favoring IS include the ability to modify and maintain I/O without removing power from the installation or risking the loss of control of the process. 

BP investigated explosion-proof enclosures as an alternative to IS and rejected that option because the enclosures are expensive, heavy and difficult to work on. We also found that maintenance of equipment under power is much more difficult with explosion-proof enclosures. 

When maintenance is required, our procedures require us to get a permit issued and to de-classify the area to assure it is not hazardous before work can begin. When this is not possible, the equipment and possibly the entire process has to be shut down before maintenance can be performed, and shut downs are obviously something we really want to avoid. 

Meeting Our IS Challenges

BP worked with its approved systems integrator, Systems Integration & Automation (SIA). SIA in turn recommended a MOST control solution from MTL. SIA had been evaluating the technology for a year. After review, it seemed that the MOST process control system would solve our challenges and provide a number of important benefits.


BP Hyde platfom
This map shows the location of the BP Hyde platform in the North Sea, east of Easington, U.K., with associated pipeline links. The Hyde platform control system was upgraded for this project.

The system could be mounted directly in the control/equipment room. The system included integrated IS and standard I/O. The ability of a single controller to interface to both IS and non-IS I/O is particularly useful in this application because it dramatically reduces the overall cost and best utilizes limited cabinet space. 

NUI Platforms are built with very limited spare capacity, and fitting in a new control system without first removing the old one requires a solution that has a very small form factor. MTL MOST provided this solution by integrating the field terminations, IS isolators and I/O cards into one unit. Furthermore, the combining of IS and non-IS units on a single control platform backplane prevented the need to have multiple backplanes systems and cabinets with unnecessary spare capacity.

A single MOST Control platform can interface to both non-IS and IS I/O through the use of a railbus isolator that connects the non-IS and IS sections of the system. The railbus isolator provides the internal communications bus for the IS modules and limits the energy available to the IS interface section of the system.  It also provides the required physical separation of 50 mm (two inches) between non-IS and IS circuits.

The MTL MOST system IS I/O modules cost more than their non-IS I/O modules, but are significantly less expensive than the alternative solution of non-IS I/O modules and external IS interfaces. The MOST system IS I/O typically has 8 or 16 channels per module, the same as their non-IS I/O modules.

Other Control System Benefits

In addition to accommodating IS, the MOST I/O approach would allow for a last-minute changeover from the existing system to the new system, thereby minimizing downtime. The MOST system would also provide the robust redundancy we required for our platform application.

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