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.

Crucially, the new control system would be required to seamlessly integrate with the existing SNS supervisory and automation system. The MOST system was able to meet that requirement because its open-systems architecture allows easy implementation of network communications.

 

Small Footprint
Cabinet space was at a premium, so BP needed to combine IS and non-IS I/O on a single rail, as shown in this picture.

The controller also provides a tight control loop response, generating a control output in response to input data within 100 ms. The controller’s rigorous redundancy model and fault-tolerant Ethernet implementation deliver reliable system operation for both the terminal and the platform.

Smooth Implementation

Using the MOST solution with its integrated approach to I/O, MTL and SIA personnel were able to reduce the system shutdown from a potential 14 days to 11 days for complete replacement. In addition, we were able to reduce the interfaces required by wiring directly to the integrated MOST interfaces.

We were also able to reduce the number and size of delivered components so that parts were assembled on site – eliminating a boat delivery to the platform and thereby reducing the cost and complexity of implementation.

Finally, the robust redundancy of the MOST system allowed us to efficiently swap the controller without a shutdown.

More Reliable Operation Plus Cost Savings

MTL MOST, SIA and our BP team worked together to successfully achieve system implementation well within our timeline – our number one goal. Support and service from SIA and MTL also allowed us to install the system smoothly and quickly.

Since the system installation, the platform’s operational reliability has significantly improved, and we have experienced better control of our process.

We have seen overall cost savings of approximately $150,000 by reducing the timeline for installation and by preventing shutdowns due to dropped communications. These savings allowed us to pay for the new system in less than six months.

Our field management team has been so impressed with the system performance that it approved several more platform control system upgrade projects with MOST and has made it the standard system for all control upgrades anywhere within the SNS. The low cost and ease of installation as seen on the Hyde platform provided us with an opportunity to standardize many systems, thus enabling our offshore instrument technicians to provide a highly competent line of support.

Ian Pinkney is Technical Authority for BP Southern North Sea, Aberdeen, Scotland

 


 

Keys To Successful Implementation

  1. An integrated approach to intrinsic safety  I/O and standard I/O;
  2. The ability to get the functionality of a DCS at the cost of a PLC;
  3. The ability to install and switchover swiftly and seamlessly with redundant operation;
  4. Reliability and durability to eliminate costly shutdowns;
  5. Support, service and willingness of the vendor and the system integrator to listen to us, understand our key goals and work closely with our people to achieve a successful conclusion.
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