21st Century System Controls Heat for the Business and Homes of Fairbanks
The first facility in Alaska to utilize PlantWeb field-based architecture goes online, on time, and on budget.

Some said it couldn't be done! There were those who advised that it was too soon to implement a fieldbus based system in a critical control application such as power generation! Wagers were even made in my own plant that we couldn't automate our main boiler, Chena No. 5 (200 Kpph), and bring it online in time to meet our
contractual power obligations to the grid. Engineers at one con-sulting firm advised our general manager that I had "radical ideas
that could be leading the company into dangerous waters."

The City of Fairbanks decided in 1997 to divest its municipally
owned utilities. Aurora Energy, L.L.C., a subsidiary of Usibelli Coal
Mine Inc., took ownership of the District Heat and Electrical Co-generation utility on January 7, 1998.

Fairbanks has extreme weather conditions; winter temperatures often drop to -40º F and colder with periods as cold as -70º F in recent memory. Hooking a business or residence to the hot water
system requires a small heat exchanger on-site. One the size of your home PC is more than enough to heat a 2000 sq. ft. home. Having reliable heat free of the maintenance headaches of a fur-nace
is an attractive alternative. This makes the investment in a central heat utility potentially profitable. An opportunity existed, but this plant had been neglected and was in serious disrepair. I
felt if we were ever to make a profit, an up-to-date combustion control system was necessary, and Gerald England, General Manager of Aurora Energy, agreed. As the control systems engineer, it was my responsibility to develop a new system to replace our antiquated pneumatic controls, and I devoted a year and a half to the project.

The plan was to bring our coal-fired steam generating plant into the 21st Century before the Millenium by installing the first boiler control system in Alaska to rely on the FOUNDATION ™ Fieldbus protocol.
This standard network protocol for industrial control operates at 31.25 KBPS and implements control digitally.

Why Fieldbus?
There was never a doubt that the new automation system should utilize smart field instrumentation and the fieldbus protocol. Providing a digital signal from point of measurement to point of final control assures a higher degree of accuracy and is immune to noise problems attributed to analog systems. The fieldbus instru-mentation yields information an order of magnitude more than weever received from the old pneumatic and analog devices without the noise problems associated with analog transmissions. This
information is easily integrated into non-control data systems, such as spreadsheets, which can be used for plant optimization. We are also planning on integrating device health information, such as con-trol
valve cycle accumulation, into a maintenance database for intelligent predictive maintenance work order generation.

I call the resulting automation solution an "optimization system," because it provides the information needed to maximize boiler ouput and increase the efficiency of heat transfer and distribution. We knew that a digital system would not solve all our problems, but it gives us the means to solve problems. As we learn to use the data now at our disposal, we'll do a better job of recognizing the condition of operating equipment and diagnosing internal problems. As an example, we installed fieldbus-temperature transmitters on the inlet and outlet of each heat exchanger (e.g. H.P. feedwater, deaerator, drum, furnace inlet and outlet) and are presently per-forming Boiler Heat Cycle Studies to develop setpoints that will give us the highest efficiency.

In considering fieldbus, we had to weigh the potential benefits against the risk of unforeseen delays during installation and startup of this cutting-edge technology. Plenty of people were willing to bet that our main boiler would remain cold until at least November, but management had faith in our judgement. As a matter of record, the boiler was online on the deadline, largely because the digital instrumentation was commissioned in just a few days! This was due to the ease of commissioning fieldbus devices. One at a time, each device was placed on a segment. The system recognized the device and displayed the serial number. It was then a matter of clicking on the serial number of the non-commissioned device and dropping it on a pre-configured file with the device Tag as its name.The device transducer scale and the corresponding system scalar information was entered and downloaded, and the loop was com-missioned!

Getting The Right System
Our specifications called for a fieldbus-based automation system, including more than 110 fieldbus-compatible transmitters and 36 FIELDVUE valve positioners. Several companies were given an opportunity to bid, but the really serious interest came from Fisher-Rosemount, Austin, Texas, and its consulting engineering sub-sidiary,
PC&E of St. Louis, Missouri.

Based on our requirements, PC&E designed a solution utilizing the PlantWeb field-based automation architecture. This replaces classic DCS "hub" architecture with a more flexible and powerful net-work
using the fieldbus protocol. Our project included:

• Intelligent field devices, including temperature and pressure
• transmitters, vortex meters, and FIELDVUE digital valve controllers
• DeltaV ™ automation system, a high capacity PC-based system mcombining the look and feel of a Microsoft Windows-based operating system with the security, interactive displays, and nformation accessibility of distributed control
  
• Pre-configured boiler control strategy based on the Fisher-Rosemount Performance Solutions Division Boiler Control Package, modified as needed for Aurora Energy
  
• Asset Management Solutions (AMS) software utilizing field-based information to streamline such routine maintenance tasks as configuration, calibration, and problem diagnosis while documentingmaintenance activities.

Bid requests went out in July 1998, the contract for the Fisher-Rosemount design was awarded in September, and engineering work began almost immediately. The first on-site construction began in June 1999, before the boiler was shut down on July 3 for its regular overhaul.

The installation itself was fairly simple. All pneumatics were removed, and a large number of temperature measurement instruments were installed to give us a better chance of measuring and calculating boiler efficiency in the future. There are 16 fieldbus nodes handling more than 100 compatible transmitters and digital
valve controllers. Some analog and discrete I/Os are still connected directly to the DeltaV system.

In the DeltaV cabinet, M5 controllers provide 12 megabytes of free memory and 47 percent free time, so the system has plenty of capacity for future additions.

Making everything work together was a concern, even though we had assurances from top Fisher-Rosemount officials that everything would be up and running on schedule. As it turned out, the startup was so fast and smooth that we now wonder what all the fuss was about. In a matter of days, the entire system was totally checked out, and the boiler was producing steam.

According to Gerry England, "The project came in on-budget and was completed on schedule. The plant has operated continuously since going online in mid-August with no interruptions due to the new automation system."

PC&E's design allowed quick checkout of the installation. Using a junction-box star configuration and fieldbus, we were able to complete the commissioning (as described previously) in record time with no wiring errors. In fact, there were zero problems with the fieldbus communications. Aurora Energy now has a very clean control system that can easily be maintained. Upgrading the remaining non-fieldbus devices will also be easy to do without additional wiring.

PC&E provided project management and implementation services in Fairbanks. The independent representative of Fisher-Rosemount, PCE Pacific, Inc., Seattle, Washington, supplied the control system hardware, transmitters, training, and ongoing support during the installation and startup phases. Price Ahtna JV of
Anchorage, Alaska, performed installation.

There's little doubt that the new combustion management software in the DeltaV system is giving us tighter control over boiler operation than ever before, although it's difficult to document because we had no effective way to calculate burner efficiency previously.

We do have evidence of improved glycol heater operation stemming from new information supplied by the smart instrumentation. The glycol heaters were serious problems in the past because their operation could not be stabilized, causing a ripple effect throughout the process. By analyzing data from various new transmitters, we
recognized that fluctuations in hotwell levels and low pressure feedwater heaters were causing fluctuations in pressure to the de-superheater valve that controlled the steam temperature to the glycol heaters. This information enabled us to retune certain loops, and these auxiliaries have been stabilized for improved operation.

In the future, we'll be able to act on other optimization opportunities using the AMS asset management software with its vast capacity to organize data from the field and to pinpoint operational irregularities. Those efforts had to wait, however, because of more pressing issues.

As the daylight hours began to shorten noticeably, two additional projects needed to be tied in with PlantWeb before winter. Both are related to Aurora Energy's district heating system expansion, which is intended to increase cash flow and improve profitability.

One project was the addition of new heat exchangers and variable frequency driven pumps in the plant. The control system was designed totally in-house and implemented with construction services provided by Price Ahtna. It features third party fieldbus devices (SMAR) incorporated into the PlantWeb architecture.

A much larger project is the $3 million expansion of service to homes and businesses in Fairbanks. This involved constructing a new hot water loop of approximately 13,000 lineal feet. In a vault located across town from the steam generating plant are three heat exchangers and three variable frequency drive pumps. They will be controlled remotely from the DeltaV system in our plant.

The installation is unique in that the I/O in the main cabinet is totally serial (i.e. FOUNDATION Fieldbus, Allen Bradley DF-1, and Modbus). This was done to achieve the high degree I/O distribution necessary to accommodate the small amount of space available in the vault and the need for separate I/O channels for each exchanger and drive. Completing the project in October was essential because a large number of customers depend on us for heat with a high degree of reliability. The conceptual design for this control system was performed in-house with detail design and cabinets provided by PCE Pacific and installation services provided by Price Ahtna.

With those challenges behind us, we expect to spend more time this winter optimizing combustion so we can begin to realize more of the benefits of digital control. This involves doing the mass balance and boiler efficiency studies as stated above. We'll also be imple-menting the AMS asset management system to improve ongoing
maintenance throughout the plant, concentrating our personnel where they are most needed to prevent downtime and maximize equipment operation. Next year, we may add three older, smaller boilers on the old side of the plant to the automation system and bring our ash conveying and coal conveying systems into the
DeltaV via OPC (OLE for Process Control).

We've proved that FOUNDATION Fieldbus and the Fisher-Rosemount PlantWeb architecture with DeltaV and AMS works. Now, we're going to use this resource to get the most out of our investment by squeezing more steam and more power out of this old plant. Don't bet against us!

By
Robert S. Mulford
Control Systems Engineer
Aurora Energy, L.L.C., Fairbanks, Alaska