Emerson Exchange 365

by Mike Bacidore

FortisBC serves more than one million customers with natural gas and electricity in British Columbia. Almost two-thirds of FortisBC’s customer base is located in the greater Vancouver area and on Vancouver Island.

“We wanted to show how important [failuer risks] are to the organization, so we created a risk analysis of our transmission assets and prioritized our work,” Loge said. “Risk is the probability of failure multiplied by the consequence of that failure. Because of a lack of redundancy in the pipe, it was a high consequence.”

Ensuring the security of supply was top priority. “We wanted to remove any single point of failure in the station,” Andrew Loge, Manager of Engineerring at FortisBC, explained. “We wanted remote operation and wanted to meet the current design standards for seismic requirements. The station was orginally built in the 1950s and ’60s, but has been upgraded throughout the years.”

Numerous stakeholders, including the operations group, engineering and asset management, gathered together and brainstormed how to meet the objectives, which yielded four viable options.

“First, we looked at operations and maintenance changes—manning the station to monitor operations and increase response times, inspect existing pipe condition and recoat pipe to industry best practices to deter external corrosion,” said Loge. “But, if we found a flaw on a nonredundant piece of pipe, how do we fix it without disrupting service?”

The second option was making station modifications, such as installing new pipe and four new block valves. It still left a small section of inlet piping as a single point of failure.

The third option, an internal station bypass, would remove all single-point-of-failure pipe and valves from the complex. “The bypass would be decoupled from the facility, and it would cost about $8.6 million,” explained Loge.

An external station bypass, the fourth option, would locate a new control station and pipeline externally for 100% redundancy and system resiliency. “It would be completely decoupled and the cost estimate was well above $40 million,” said Loge.

“Options 3 and 4 met all of the objectives we had,” Loge explained. “Then we did a financial analysis. We looked at the project cost and the risk analysis. These two options both had more than 99% reduction in risk, so we decided on the internal station bypass because the cost was $32 million less. Then we went back to our engineering group and explained project objectives.”

At this point Spartan Controls, an Emerson local business partner, was brought in to assist the engineering group with design and execution of the project. “The process needed performance over a wide range of flows,” said Reese Dawes, account manager at Spartan. “Noise was also a consideration because there are local residents and wildlife around the station. Emission standards are becoming very stringent, so environmental concerns needed to be addressed, too.”

One objective was to optimize the real estate. “There was space around the station, but there wasn’t a lot of room to expand,” explained Dawes. “Any solution from a control-valve standpoint needed to be a small envelope. We needed to keep it in a single-valve train. Overpressure protection was critical. FortisBC wanted fail-safe and continued operation, so we needed to go through all the modes.”

The gas supply that feeds into the station from the transmission line is unodorized gas, so at that point it’s all odorized for leak detection.

“We needed accurate control from varying inlet pressures and flows,” said Dawes. “We looked at 30-year projected flow. We also wanted to reduce the differential pressure in the wide-open position across the system.”

For environmental considerations, Fisher low-bleed current-to-pressure transducers and pneumatic positioners were used. “It also became important when we talked about overpressurization strategies,” explained Dawes. “These are large pipelines and releasing into the atmosphere is not safe. We landed on a monitoring device for overpressure protection. The monitor measures the downstream pressure.”

The project team then identified all of the failure methods for components, including loss of instrument air, power, PLC and RTU, instrumentation failure and main valve failure. “We included a redundant power gas backup for loss of air,” Dawes said. “For loss of power, PLC or RTU communication, the centralized gas control center can manipulate these. If any of those were lost, we do have the ability to do local control, which is why we used pneumatic positioners, so we could manually load the system and control it without any electronics.”

The project was completed on time and on budget in December 2015. Single-point-of-failure operation risk was reduced by an estimated $3.4 million/year.