By Luther Kemp
Minnesota Power provides electricity to a 26,000 square mile service area in northeastern Minnesota. It supplies electric power to 16 municipalities, and it provides power and co-generated steam to local industries such as paper mills. It generates electric power with coal, gas, biomass and wind—but the company's major emphasis in recent years has been to increase our use of renewable energy sources such as biomass.
Burning biomass with other fuels such as coal requires a multi-fuel boiler. Operating a multi-fuel boiler can be difficult, particularly in cogeneration (cogen) applications with varying steam demands. Biomass fuel availability is variable and subject to frequent interruption, and Btu content of the fuel varies significantly and quickly. Process steam loads fluctuate, sometimes suddenly. Controlling a multi-fuel boiler in a cogen application is several orders of magnitude more difficult than running a unit with a single fossil fuel.
A highly skilled operator can operate such a facility by watching video cameras focused on the bed and flame and by observing the on-screen outputs of steam flow, pressure, temperature and excess oxygen sensors, along with other process variables.
He or she continuously tweaks the boiler control setpoints in response to changes in the combustion process and other process variables. At times, it's as challenging as driving a car through a snowstorm, and it always requires constant attention. While Minnesota Power has highly skilled operators, this semi-manual mode of operation isn't the optimal way to run a major power and steam-generating unit.
Updating Controls in Duluth
Our M.L. Hibbard Renewable Energy Center power plant in Duluth, Minn., (Figure 1) has a multi-fuel traveling grate boiler that burns both wood waste and coal. The boiler generates steam that feeds two condensing turbines that provide power to the grid and supply steam to the New Page Paper Mill. The plant is working to be able to burn 665,000 tons of biomass per year and 13,000 tons of coal to produce 3,600,000 klb of steam to generate 220,000 mWh of power and supply process steam to the New Page Paper Mill.
The boilers, when owned by the City of Duluth, were primarily used for steam generation for the paper mill and generated electricity only when excess steam was available. Over time, ownership of the boilers was transferred to Minnesota Power, and legislation was enacted that mandated power facilities generate a substantial amount of their power from renewable sources.
We wanted the facility to maximize generation while maintaining the load to the paper mill and to do so in an optimal fashion under automatic control. Although it was a multi-fuel plant, the control system as it was implemented wouldn't support substantially increasing the amount of biofuel without excessive intervention and attention from our operators. It also wouldn't permit us to prioritize the amount of power generated from the plant.
Although the overall plant was controlled by a modern Emerson Process Management DeltaV control system (www.emersonprocess.com/), much of the plant had older control equipment with limited capability. The two boilers were converted to burn wood residue and coal in 1986 and 1987 and have been running virtually unchanged ever since.
Manual intervention by our operators was often required as steam demand varied, as fuel quality varied, and as other conditions changed. The excess oxygen control was inoperative, and at times we had to manage process swings using natural gas as a supplemental fuel because the control system couldn't react fast enough with coal or wood fuel. Boiler warm-up was a cumbersome process that required multiple operators, and the variability between operating shifts was excessive.
In 2010, we decided to upgrade the boiler and its controls. We were planning to burn more wood waste to meet increasing regulatory requirements, and we had to supply steam to the New Page paper mill. The New Page mill would consume about 40% of the steam produced,
As is typical when supplying utilities to an industrial process, we have no control over demand. The mill can increase or decrease its steam demand nearly instantaneously by wide margins, thereby upsetting boiler and steam turbine operations.
Another concern was related to biomass regulations. At the time we began the upgrade project, we did not know what the U.S. Environmental Protection Agency (EPA) or the State of Minnesota would eventually pass in terms of legislation regulating the use of alternate fuels. Therefore, the control system would have to accommodate virtually any mix of wood and coal fuel.
These new developments meant we could no longer count on controlling the boiler with frequent manual intervention. We wanted to achieve maximum steam production from wood, savings in emissions and faster response to upsets. We also wanted to reduce operational problems such excessive ash carryover that was causing a need for frequent boiler cleaning.
The solution was twofold. First, we addressed boiler process issues by installing a new overfire air (OFA) system from Jansen Combustion and Boiler Technologies (www.jansenboiler.com). Jansen's retrofit included new OFA ports, a new duct design with improved measurement locations and new damper actuators with position feedback. The OFA system (Figure 2) improves air delivery to the boiler by getting air to where it is needed for biomass burning and creating a turbulent mixing zone to allow complete burnout.