BY SCOTT GOSSARD, BABCOCK & WILCOX
As anyone familiar with the U.S. utility industry can tell you, the power generation business is cyclical. Fuel prices, regulations and capacity needs create periods of peak new-build and plant upgrade activity necessary to meet the demands of the market.
In particular, the demand for power generation from certain fuels is driven by cyclical factors. Coal, natural gas, oil, renewables and other fuels have come in and out of vogue at different times over the years for various reasons, usually driven by costs of a particular fuel or regulations that tend to favor one fuel over another.
Environmental regulations drove the last significant wave of boiler conversions from coal (or heavy oil) to natural gas in the United States. In the early 1990s, utilities and municipal plant owners in the western states responded to more stringent air emissions regulations imposed by state environmental agencies by switching coal and oil plants to natural gas. But relatively high gas prices, coupled with abundant, cheap coal resources made more widespread coal-to-gas conversions impractical in the decade and a half that followed.
|Four coal-fired units at the Ernest C. Gaston Electric Generating Plant near Wilsonville, Alabama, were recently converted to burn natural gas. Photo courtesy: Alabama Power|
However, about five years ago, several factors converged to spur a renaissance in natural gas for power generation, and that renaissance continues through to the present.
A combination of sustained low natural gas prices and more stringent environmental regulations has driven more power providers to seriously examine natural gas as a fuel option for energy generation. Indeed, according to the U.S. Energy Information Administration’s 2014 Annual Energy Outlook, coal currently supplies about 41 percent of the nation’s power versus 27 percent from natural gas. But by 2035, the agency anticipates natural gas will be the primary fuel for electricity generation.
In particular, MATS compliance has forced power producers to take a hard look at the older, less efficient coal plants in their fleets to determine whether adding emissions control equipment is an economical way to bring those plants into compliance, or whether some other option, such as shutting them down and replacing that capacity with highly efficient plants that use alternative fuels like natural gas combined cycle, makes more sense.
Besides adding costly environmental equipment or closing and replacing coal capacity (also a costly proposition), a third avenue exists for a limited number of utility plants. That option is the conversion of a coal boiler to fire natural gas – which may be significantly less expensive than the other choices. Fuel switching is an attractive and economical option for utilities that must maintain a certain generating capacity in their fleet and can’t justify the cost of these other options.
TYPICAL PROFILE OF CTG PLANTS
The most likely candidate for a coal-to-gas conversion are 50-plus year old units, less than 300 megawatts in capacity and generally early generation sub-critical utility boilers – the least efficient, most-costly to operate and with the lowest overall capacity factor in the coal fleet. The majority of these older, inefficient units are located in the eastern United States. Typically, these plants have limited or no air quality control systems already in place, and the cost of adding an AQCS to comply with regulations is prohibitively high. Most plants west of the Mississippi River built in the 1960s or later aren’t as attractive as candidates for fuel switching since they are often larger, more efficient and tend to burn Powder River Basin coal, a cost effective fuel with a more favorable emission profile than the bituminous burned by many eastern plants.
|Two coal-fired generating units at Appalachian Power’s Clinch River Power Plant in Virginia are being converted to burn natural gas. The project is expected to be completed by spring 2016. Photo courtesy: American Electric Power|
Although old, many plants considered for fuel switching still have a decade or more of useful service life providing peaking capacity where and when it is needed. These units are a valuable asset that power producers are not eager to abandon. When a plant is closed, the owner gets no value out of that asset going forward, and, in fact, it may become a costly liability. The legacy costs created by residual coal and oil at the site, on-going maintenance and security, asbestos and other factors can be very high.
So there is significant incentive to keep those assets functioning in some way. If an owner can convert and continue to operate that plant on gas, it allows them to continue to harvest some value from these assets. It also allows the owner to maintain a viable operating permit, which would be lost when a plant is retired.
The converted gas-fired plant is also ideally suited for deep load cycling to meet fluctuations in demand to compliment the remaining coal fleet providing baseload power generation.
Interestingly, MATS compliance and state regulations – not the current push to limit greenhouse gas emissions through regulations like EPA’s proposed Rule 111(d) – have been the primary regulatory factors driving coal to gas conversions.
Utilities specifically looking to limit GHG emissions may consider a coal to gas conversion as a shorter term GHG compliance option in the case of an approaching compliance deadline coupled with an inability to raise the significant capital needed to build a newer high efficiency combined cycle plant.
THE PROS AND CONS OF FUEL SWITCHING AND TECHNICAL CONSIDERATIONS
Since 2010, Babcock & Wilcox Power Generation Group, Inc. has implemented, or soon will be implementing, the conversion of about 2 percent (about 3,000 MW) of its installed U.S. coal boiler base to natural gas. Many more plant owners have at least studied the option. So while this path is clearly not the right one for every plant, a notable percentage have investigated and/or pursued coal to gas conversions.
Every potential project begins with an extensive study phase in which a number of pros and cons must be considered before undertaking a project that could cost several tens of millions of dollars. Typically from study phase to delivery of equipment takes about two-and-a-half years, although some projects have taken four to five years to develop.
|Advanced low NOx burners for gas-fired boilers. Photo courtesy: Babcock & Wilcox|
One of the most basic decisions in a conversion is to determine whether a complete replacement of the plant’s existing coal burners is required or to simply modify them for gas firing. Ultimately, this depends greatly on the age of the equipment and environmental regulations it must meet post conversion.
Due to more stringent environmental permit requirements that often times come with the fuel conversion to gas, more significant modifications may be needed, such as the addition of an overfire air system and/or flue gas recirculation system to reduce nitrogen oxides and carbon monoxide emissions to the new permitted level. By recirculating a portion of the flue gas from the exit of the boiler back into the combustion air stream, the peak flame temperature is reduced along with limiting the availability of oxygen to the fuel, thereby significantly minimizing the formation of NOx. The addition of an overfire air system could be considered for similar benefits. Many applications apply both of these principles to achieve very low emission rates.
Technical issues can greatly impact the viability, performance, cost, and reliability of any steam generating unit firing natural gas when such unit was not originally designed to do so. These issues are very specific to the original design of the boiler, including, but not limited to, its physical geometry, materials of construction, remaining component life, desired operating capacity and boiler steaming conditions required to satisfy the steam turbine-generator set.
Other issues to be considered include the specific characteristics of natural gas versus original design coal fuel; negative plant heat rate impacts associated with natural gas as the primary fuel; impact plant net capacity; boiler geometry and associated impact on emissions reduction potential; identification of specific heat transfer surface shortcomings; and the capacity of existing fans to support requirements of alternate fuel. Since essentially no two boilers are exactly the same, identifying the overall performance impacts following a switch to natural gas requires a very detailed, site specific engineering analysis to determine technical performance impacts and viability of undertaking fuel switch. It is not uncommon to end up with a very complex matrix of options or path forward with respect to project scope, generating capacity, emissions profiles, and operating flexibility.
Depending on the type of coal currently burned in a plant, switching to burn natural gas could result in a notable drop in plant heat rate and loss of efficiency. For example, when switching from bituminous coal to gas, plant operators could see an approximately four percent degradation in efficiency due to the high moisture content of natural gas. A switch from Powder River Basin coal to gas would result in little or no change in plant heat rate. However, the current low price of natural gas may make up for at least some of the cost of this loss of efficiency.
There’s also a significant impact on heat transfer in the boiler from one fuel to the other. In many cases, the original boiler heat transfer surfaces will be inadequate for full natural gas firing. The heat transfer characteristics for natural gas versus coal vary significantly – coal has more radiant heat transfer and gas has more convective heat transfer. Without either modifications to the existing heat transfer surfaces or identification of alternative operating conditions, problems with metallurgy can arise and these components run the risk of becoming unreliable. Alleviating this potential issue requires careful consideration and study across the complete spectrum of load dispatch and cycling scenarios.
Many owners intend to convert plants from coal to gas and use that asset to provide power on-demand through direct sale or sale in the capacity markets. There can be significant financial penalties in the capacity market for a plant not being available to generate power when that capacity is needed. This is an important consideration for older units which may have legacy reliability issues. Working in tandem with the plant owner, the engineer can work to determine the issues and the capital investment required to address those issues. This allows the owner to do a project justification and determine whether the project makes sense to proceed.
Overall, most generating asset owners have opted to take a minimalist approach to more costly boiler pressure part upgrades and address identified concerns through careful monitoring and changes in operating parameters. The extensive engineering analysis on the front end of these fuel conversion projects allows the plant owner to take advantage of these lower cost options.
From a manpower perspective, it takes fewer personnel to operate and maintain a gas-fired plant than it does a coal plant. There are a lot of people involved with unloading and handling of coal used as fuel. Not so with natural gas. Significant manpower is also used in maintaining plants that run on coal due to coal’s inherent erosive and corrosive nature as a fuel.
Overall, switching to gas, even at current gas prices, is generally not an easy choice economic choice considering the capital cost, fuel costs, cycle efficiency, and future regulatory uncertainty.
A WORD ABOUT INFRASTRUCTURE
The most obvious change to a power plant that switches from coal to gas will be the modifications to the fuel handling, storage and distribution equipment. This can be one of the most significant costs in a coal to gas conversion project. In many cases, existing coal plants lack sufficient infrastructure for gas delivery and distribution and it must be constructed.
The plant must receive natural gas via a pipeline spur from a local main transmission line. If a spur does not currently exist, the plant will need to evaluate the costs and activities, including permits and land rights, associated with constructing a new spur.
Large gas pipelines often have to be run in excess of 20 miles from a suitable source, which can be very costly both for the hardware and the regulatory and permitting of a new natural gas corridor. Once inside the plant perimeter, the transmitted gas must regulated (reduced) in pressure, heated, metered, and then conveyed through a piping and valve train system, to the gas burners at the boiler front to the new low emissions gas firing system at the boiler interface. This equipment must be integrated with a complex flame safety, burner management and control system. Some of these systems can be new equipment, while others require modifications to existing plant equipment.
Another issue with gas can be availability of the fuel during peak times of use (cold winter months). It is common for a plant to be required to have a back-up supply of fuel for times when the gas supply is limited. This is especially true for plant operators that sell power to capacity markets, who are subject to penalties if they can’t meet demand for power.
Even light oil is being employed as a back-up fuel choice even though it can be very costly to build on-site storage tanks and to maintain a supply of fuel used very infrequently.
CO-FIRING GAS AND COAL
Early on in the wave of conversions, there were notable examples of plant owners that wanted to add gas firing for its ability to respond rapidly to changes in load demand and its deep cycling capability, but still maintain the ability to fire coal due to its lower cost. In the early 2010s, the U.S. economy was still sluggish, resulting in erratic electricity demand. A plant that could cycle up and down quickly to meet those peaks and valleys in demand and also ramp down at night when demand was reduced would potentially be more profitable.
However, a coal-fired unit generally can only operate as low as 30-35 percent load and still sustain good combustion, restricting the plant’s ability to cycle. Coal plants are also very slow to cycle up to full load – a supercritical boiler can take more than 12 hours to ramp up to load from a cold start. But if a plant were able to switch to gas at low loads and take load down even further and then switch back to coal at higher loads, it could be very advantageous.
Unfortunately, this concept never gained much traction due to potential future emissions ceiling issues. A plant’s emissions profile would decrease when burning gas over time, triggering lower permitted emissions limits thereby severely constraining the unit’s ability to burn coal as time moved forward. Although this strategy had significant value in the shorter term, it was eventually abandoned.
LOOKING TO THE FUTURE
B&W has been one of the most active vendors serving the current wave of coal to gas conversions.
Despite the popularity of the concept, we’ve noted that the majority of plant owners who consider fuel switching ultimately decide not to move forward with this option.
For those that determine that a coal to gas conversion isn’t the right choice, they must decide whether decommissioning and shutting down the plant makes sense, or whether they should reconsider the addition of new emissions control equipment to keep the plant viable.
In one notable case, after extensive efforts looking into a gas conversion, issues with siting a permitting major gas supply line killed the project in the near term. Fortunately, B&W was able to assist a customer with an extensive coal fuel switch study including identification of some cost effective upgrades of existing environmental equipment to comply with current environmental requirements.
Although the expense of moving from a more locally sourced coal to a source much farther away adds to the plant’s fuel costs, this option allowed the unit to continue to provide much needed generation in compliance with all emissions regulations while remaining competitive in the current power markets.
It would appear that the coal to gas conversion market has peaked and is now on the decline.
The deadline for MATS compliance, the primary driver of this market, is upon us now. So most plant operators have already settled on a compliance strategy and are in the process of implementing it.
Scott Gossard is general manager of Service Projects at Babcock & Wilcox Power Generation Group, Inc.