Electric utilities are always searching for ways to minimize costs, improve availability, and reduce emissions. Recent changes in the price of natural gas have made that fuel economically attractive, and it has the added benefit of reduced air emissions. For utilities with existing coal-fired units, conversion from coal firing to natural gas firing might be an option worth considering.
Why Consider Fuel Switching?
The first step in the process is to identify the forces that drive the decision to convert from coal to gas. The key forces are regulatory (both in terms of emissions and as an offset for a new unit), fuel costs, the age of the plant, and the need for plant output.
Regulatory forces are currently in a state of flux, and there are a wide range of proposed rules and legislative efforts that could have a far-reaching impact on coal-fired operation. Carbon dioxide controls seem to be coming in the near future that will require some additional operating restrictions placed on power plant owners. There also may be other regulatory issues to evaluate, such as New Source Review and offsets for other emissions regulated by state and federal laws.
The price of natural gas has recently become more attractive as a baseload fuel due to additional supply and reduced demand from general industry. There are many different projections of where gas prices might be in the near future, all of which are based on the forces of supply and demand. The current price of natural gas is relatively low and stable compared to previous years.
Utilities should be aware that natural gas prices are much more sensitive than coal prices to short-term changes in supply and demand. While current economic conditions favor natural gas usage, Babcock & Wilcox Power Generation Group Inc. (B&W PGG) strongly advises its customers to evaluate potential price volatility as a key component in the decision-making process.
A plant may be considered for fuel switching based on its age and how close it would be to a possible retirement or major rebuild. The timing for fuel switching may be ideal if the boiler in question is already under consideration for major projects like superheater replacement, burner modifications, air system changes and/or the addition of back-end emissions control equipment.
Utilities must also factor in the future need for electrical power generation—either because of market demand projections or to replace a unit that might be approaching the limit of its useful service.
One of the other key factors to consider is the need for plant output, including a potential for derate and/or increased turn-down capability. A unit’s continued usefulness might involve its ability to operate or be on standby during periods of low load.
As utilities look at their long-term forecasts, plants that operate efficiently and with high availability will play a key role in meeting future demand. Consequently, these plants will need to be evaluated for projects that will extend their useful life. Those projects might be targeted for efficiency improvements with coal as a fuel (such as burner upgrades and emissions control equipment) or as fuel-switch projects that take advantage of the benefits of natural gas.
The first step is to perform an engineering study to help determine the best options for your specific application. Among the many options to consider are:
- Fuel switch with modifications to the existing boiler.
- Fuel switch for the existing boiler and the addition of a gas turbine to the existing boiler cycle, such as adding a simple cycle to the existing system, repowering the hot windbox, or combined cycle repowering.
- New combined cycle plant (elemental review) with retirement of the existing coal plant.
Each option has advantages and disadvantages, including cost and operational considerations. Potential owners should:
- Compare modification costs vs. the capital cost of a new gas turbine.
- Estimate the impact of future changes in fuel prices and the potential risk associated with natural gas price volatility.
- Predict the life expectancy of gas turbines and heat recovery steam generators (HRSG) compared to steam boilers.
- Estimate the acceptable plant derate, if applicable.
Because no two plants are identical, it is important that utilities work with an experienced supplier like B&W PGG to evaluate the best solutions for their needs.
Fuel Switch with Modifications to the Existing Boiler
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. The plant must receive natural gas via a pipeline spur from the local main transmission line. If a spur does not currently exist, the plant will need to evaluate the costs and activities (such as permits and land rights) associated with constructing a new spur. Once inside the plant perimeter, the gas must be metered and piped to the boilers (or to a new gas turbine if applicable), where new gas burners will be required.
If the existing boiler is modified for gas-firing, the convection pass, ducting, and windbox will likely need modifications. The extent of the modifications will be determined by an engineering study that will look at overall furnace absorption, furnace exit gas temperature, and tube bank arrangement/material changes (superheater, reheater, and economizer). Other operational changes like sootblowing schedules, attemperator spray flows, air heater operation, and operation of any back-end emissions control equipment will need to be adjusted for the switch from coal to gas.
A plant study should evaluate the impact of the following technical issues:
- Characterize natural gas versus the original or current fuel.
- Estimate the impact on boiler design and capacity.
- Estimate the impact on cycle efficiency.
- Determine the boiler and environmental equipment modifications required.
- Determine the boiler modifications required: burner modifications; convection pass modifications; and modifications to fans, ductwork, and fluework.
- Establish the acceptable plant derate.
Financial Considerations. Any modification to an existing plant carries considerable cost implications. This is true when upgrading a coal plant with new components for higher efficiency and/or lower emissions. Likewise, there are financial considerations for switching fuel from coal to natural gas. Cost ranges for modifications for the units shown in the table are estimated to be in the range of $50 to $75/kW.
Comparison of prior pulverized coal to natural gas conversion projects. Source: B&W
The unique conditions of each plant will necessitate a detailed study of the potential operational options and their corresponding costs. These costs include only modifications to the boiler island. Excluded are costs related to bringing natural gas supply to the boiler.
Fuel Switch for the Existing Boiler with Addition of a Gas Turbine
The concept of repowering existing power plants is currently viewed as an option to economically meet new demands for improved efficiency, power growth, and stricter environmental regulations.
Partial repowering is the conversion of an existing site to combined cycle where the boiler and steam cycle are retained to the greatest extent possible. There are several major partial repowering alternatives. Many of these alternatives have multiple possible equipment configurations that can be considered, depending on the option. Low gas turbine exhaust oxygen concentrations (as low as 12%) and high exhaust temperatures (exceeding 1,100F) can provide design challenges, depending on the combustion turbine used for this configuration.
Addition of Simple Cycle to the Existing System. This technology uses the existing boiler and steam turbine equipment in essentially its original configuration. In this design, a gas turbine and feedwater heater are added in parallel to the existing boiler. Figure 1 illustrates a typical equipment arrangement for this option. Depending on the specific plant configuration, balance-of-plant (BOP) material and erection services are required to complete this retrofit.
1. Option 1: a simple cycle combustion turbine. In addition, the plant requires recuperative feedwater heater(s) and retains the existing steam turbine (with some extraction ports closed). The chief advantage of this option is the relatively low capital cost, but the plant will have only a modest 2% to 3% efficiency gain. Source: B&W
Hot Windbox Repowering. In this configuration, a gas turbine is added to an existing plant and the exhaust from the turbine is ducted directly to the boiler windbox, where it is used as combustion air for the boiler. The existing air heaters are typically retired, and new stack gas coolers (or partial HRSG) are added in parallel to the feedwater heaters to maximize cycle efficiency. Figure 2 illustrates a typical equipment configuration for this technology.
2. Option 2: hot windbox repowering. This option also requires a new combustion turbine that supplies the combustion air to the existing boiler. The advantages of this approach are a power increase of up to 50%; an efficiency increase of up to 15%; retaining the current equipment and, if desired, the current fuel; and reduced emissions. The disadvantages include installation of a new high-temperature combustion air system, the possible requirement of boiler surface changes and/or a unit derate, and possibly also special high-temperature and low-oxygen burners. Source: B&W
Depending on the specific plant configuration, significant boiler and BOP material and erection services are required to complete these retrofits. This has been the repowering configuration of choice outside of the U.S. Holland, for example, has more than 12 plants designed in this configuration (both retrofit and original). B&W PGG designed two new plants based on this cycle configuration in the early 1960s. Recent improvements in gas turbine technology have made integration of these machines with boilers more challenging than in the past.
Combined Cycle Repowering. In this configuration, a gas turbine is added to an existing plant, and the exhaust from the turbine is ducted to the boiler windbox, where it is used as combustion air for the boiler. This configuration uses a supplemental heat exchanger (or partial HRSG) or mixes ambient air upstream of the boiler to cool the exhaust temperature to levels acceptable to existing windbox materials. The existing air heaters are typically retired, and new stack gas coolers (or partial HRSG) are added in parallel to the feedwater heaters to maximize cycle efficiency.
Figure 3 illustrates a typical equipment configuration for this technology. Depending on the specific plant configuration, significant boiler and BOP material and erection services are required to complete this retrofit.
3. Option 3: combined cycle repowering. The advantages of this option are a power increase of up to 70%; plant efficiency improvement of up to 15%; retaining the current equipment and, if desired, current fuel; and reduced plant emissions. The disadvantages include more complex steam system interface and piping systems, possible boiler surface changes and/or derate, and special low-oxygen burners for the boiler. Source: B&W
Financial Considerations. As this repowering configuration can vary significantly, depending on the goals and constraints of a given system, the cost for such a conversion can span a broad range. The combustion turbine will likely be the largest single component and cost. Estimates of retrofit costs range from $180 to $1,025 per unit kW increase in power.
New Combined Cycle Plant with Retirement of the Existing Coal Plant
A modern, highly efficient combined cycle plant is always a consideration when evaluating a fuel switch from coal to gas, especially when a considerable increase in power generation is needed. The higher capital cost of this option requires a careful analysis of its suitability to the unique needs of each utility.
This article is not intended to review every factor related to switching from coal to natural gas, but it is important for each prospective utility to consider the hidden costs associated with the retirement of a coal plant, including the cost of decommissioning or mothballing, as well as any site remediation costs. Only when all the true costs are identified can the real savings from a fuel switch be fully and properly evaluated.
—McMahon is an engineering supervisor, J.E. Monacelli is an engineering manager, and D.A. Roth is a strategic marketing and integration supervisor for Babcock & Wilcox Power Generation Group Inc. F.J. Binkiewicz Jr., PE; R.J. Kleisley; and D.K. Wong worked for B&W during preparation of this article.