Energy Issues

 

Paper of the Year: A Case Study on Coal to Natural Gas Fuel Switch

Note: The following paper was selected “2012 Paper of the Year” for the fossil technologies track at POWER-GEN International 2012.

Story by:

Brian Reinhart, P.E. – Presenter
Alap Shah
Mark Dittus
Una Nowling
Bob Slettehaugh
Black & Veatch
December 12, 2012

INTRODUCTION

In the United States, natural gas prices have fallen in recent years because of the stagnant economy, weakened demand for electricity and increased shale gas production supply. This has led to a reduction in coal-fired electricity generation, with some of the coal-fired generation being replaced by natural gas-fired generation. Low natural gas prices and static coal prices have created a business opportunity for power producers to switch from coal-fired to underutilized natural gas-fired power plants. In addition, increasingly stringent environmental regulations will require many coal-fired units to be retired or to be retrofit with emissions control equipment for continued operation on coal. This paper explores several technically feasible options available in the current market.

The selection of the most advantageous option is influenced by factors such as performance, capital cost, operating cost, fuel flexibility and emissions control requirements. Other factors to consider are ease of integration with the existing plant, the possibility of reusing existing balance-of-plant equipment, operating flexibility, operations and maintenance costs, and technical risk mitigation. Often, the characteristics of the coal-fired unit dictate the most advantageous generation option. The vintage, size, site characteristics and emissions control equipment currently in place can define which option is the most cost-effective and capable of aligning with the current business model.

The case study presented is based on a subcritical pulverized coal-fired unit with a nominal gross output of 250 megawatts (MW). The unit was commissioned in the late 1970s. Emissions control is limited to a cold-side electrostatic precipitator (ESP), and heat rejection is by a wet mechanical-draft cooling tower. The unit was constructed on a two-unit site with limited space available between the boiler and the stack. The site layout included future expansion of a third unit, so space is available adjacent to the subject unit. Over the last few years, dispatch of the unit has declined because of low natural gas prices relative to coal prices in the region. The unit currently operates during intermediate and peak demand periods and has an annual capacity factor of about 45 percent. The nearest large natural gas pipeline is approximately 60 miles from the site. A new supply line to the site would traverse rural land. Transmission is not constrained in the area; sufficient margin exists for increased electrical export.

Options considered for the case study include the following:

  • Option 1a – Full Conversion to Natural Gas Only. Natural gas would be used to fire the existing boilers. The major plant equipment such as the boiler, steam turbine and heaters would still be used; however, this conversion option may require modifications to the unit.
  • Option 1b – Conversion to Coal with Natural Gas Co-Firing. Coal would be retained as the primary fuel and co-fired with natural gas. As with Option 1, major equipment would be reused. In addition, emissions control equipment retrofits would likely be required to comply with air regulations for coal-fired generating units.
  • Option 1c – Emissions Control Equipment Retrofit. Emissions control equipment would be added to the existing coal-fired generation unit to reduce emissions.
  • Option 2a – Repowering Steam Turbine in a Combined Cycle. The existing steam turbine would be repowered as part of a combined cycle configuration. Repowering would consist of using new combustion turbine/heat recovery steam generator (HRSG) train(s) with the steam turbine.
  • Option 2b – Replace with New Combined Cycle. A new natural gas-fired combined cycle configuration block would replace the existing unit. Existing infrastructure, such as water/wastewater supply and treatment, transmission and buildings, may be reused.

POTENTIAL OPTIONS

Five potential options are presented. Option 1a, Option 1b and Option 1c all entail continued use of the case study unit’s boiler. Each of these options retains approximately the same net output. Option 2a and Option 2b both entail retirement of the case study unit’s boiler. Each of these options has a net output nearly three times the size of the existing unit. Replacing a small unit with a much larger unit might not be feasible for some owners.

Option 1a – Full Conversion to Natural Gas Only
The unit being evaluated in this case study would be able to maintain gross output without modification or replacement of the forced draft fans and boiler heat transfer surfaces. Main steam and reheat steam conditions would be maintained. Therefore, steam turbine output and heat rate would remain unchanged. This will not always be the case. Refer to the following paragraphs for potential modifications required to minimize unit performance impacts. Coal handling and processing equipment and the primary air fans would be removed from service, which would reduce auxiliary load. However, boiler efficiency would be reduced because of an increase in latent heat losses. A summary of performance impacts associated with converting the case study unit from coal to natural gas is presented in Table 1.

Option 1a, along with three other options presented, would require natural gas. The cost of bringing natural gas to the site is potentially significant. The cost to tie into an existing major gas pipeline, construction of a new pipeline to the site, installation of a revenue metering station and associated rights-of-way can be anywhere from several hundred thousand dollars to more than $1 million per linear mile of pipeline to the site. In addition, options involving the addition of combustion turbines would require elevated natural gas pressure, ranging from approximately 400 to nearly 1,000 pounds per square inch at the combustion turbine interface, depending on the model. Unless the site has ready access to a high-pressure (HP) natural gas pipeline, natural gas compressors would be required.

Natural gas supply lines to the burner levels are a potential explosion hazard and would require careful consideration of pipeline routing and electrical equipment design. Areas around potential leak points would be classified as hazardous areas. Equipment and systems within these areas would need to be designed to function safely.

Conversion to natural gas could be as simple as installing a gas nozzle on an existing coal burner and tying into the existing natural gas supply system, or the conversion could be more complex, requiring the installation of completely new burners, boiler modifications, boiler auxiliary equipment modifications or replacements, and entirely new off-site and on-site natural gas supply systems.

In order to maintain unit capacity, modifications might be required when converting from coal to natural gas including modification or replacement of existing forced draft fans, air heater modifications, and superheat and reheat surface modifications. The degree of the required modifications would depend on the unit being considered. Control system modifications would be required to incorporate natural gas into the plant’s operating system. The modifications include updating or replacing the existing burner management system with a system that incorporates the new natural gas valve trains and instrumentation.

Since natural gas has only trace amounts of ash, slagging and fouling would not occur. This lack of slagging and fouling may have a hidden risk of leading to more heat transfer problems in the boiler; coal-fired boilers are designed with a default assumption of a certain amount of slag and reflective ash coating their surfaces. In addition, some boilers have been modified over time to better accommodate coal-based slagging levels (such as adding heat transfer surface in the upper furnace), which might lead to heat transfer imbalances in the unit. Where they exist, these imbalances could normally be corrected with heat transfer surface changes, use of refractory overlays to shield tubes or by careful attention to the gas burner placement and heat distribution within the boiler.

Gross output of the unit may be affected if the forced draft fans are unable to maintain adequate combustion air to the boiler or if heat transfer from the combustion flame to the boiler surfaces is altered enough to affect flow through the boiler. Turbine output and heat rate are generally not affected unless boiler heat transfer is so strongly impacted that the target main steam or reheat steam conditions cannot be met. Some small Rankine steam cycle benefits might be realized if the unit could reduce superheat steam attemperation and reduce or cease operation of steam soot blowers, air preheat coils and flue gas desulfurization (FGD) reheat coils. Auxiliary electric load requirements would be reduced as a result of removing the coal handling system and pulverizers from service and shutting down or bypassing emissions control equipment. Natural gas hydrogen content is drastically higher than that of coal. Therefore, latent heat losses tend to be higher. The boiler efficiency would generally be decreased, depending on the type of coal currently being fired in the unit.

Converting a unit from coal to natural gas generally increases unit availability. This is because a switch to natural gas tends to alleviate the following four fuel-related problem areas most likely to cause forced unit derates:

  • Pulverizer capacity limitations/failures.
  • Fan flow capacity limitations. While forced draft fan duty could increase, induced draft (ID) fan duty would decrease.
  • Excessive stack emissions rates.
  • Boiler slagging and fouling.

Any option involving the complete conversion from coal to natural gas would likely reduce staff requirements at the plant, since coal yard personnel and some emissions control and maintenance staff would no longer be needed.

Option 1b – Conversion to Coal with Natural Gas Co-Firing
In addition to replacing oil-fired warm-up guns with natural gas-fired guns, the unit being evaluated in this case study would need to be retrofitted with emissions control equipment to comply with Mercury and Air Toxics Standards (MATS) for mercury, hydrogen chloride (HCl) and particulate matter (PM). Issues associated with other air emissions regulations, such as the currently vacated Cross-State Air Pollution Rule (CSAPR), Regional Haze Rule/Best Available Retrofit Technology (BART), National Ambient Air Quality Standards (NAAQS) and greenhouse gases (GHGs), are not considered in this example.

Emissions control retrofits for the case study unit would consist of powdered activated carbon (PAC) injection (alternatively referred to as activated carbon injection [ACI]) for mercury control and semi-dry flue gas desulfurization (SDFGD) and fabric filter combination for HCl and PM control. The existing cold-side ESP would be demolished and removed from service. The additional pressure loss associated with addition of an SDFGD and replacement of an ESP with fabric filter would necessitate the addition of ID booster fans. A summary of performance impacts associated with converting the case study unit from coal to coal with natural gas co-firing is presented in Table 2.

Retrofitting a coal-fired boiler to co-fire natural gas could be as simple as replacing the existing oil-fired ignitors with new natural gas-fired Class 1 ignitors. This modification typically allows for a maximum gas firing capability of 10 to 20 percent. If the unit is equipped with oil-fired warm-up guns, these can be replaced with natural gas-fired guns to increase the potential natural gas capability to approximately 30 to 50 percent. If a higher level of natural gas co-firing is required, natural gas firing capability would need to be incorporated into the main burner system. Potential modifications include installation of gas rings around the existing coal burners, installation of gas spuds in the annulus or center of the burner, or other means to allow for inserting natural gas into the existing burner.

Typically, the most cost-intensive option for coal and natural gas co-firing is either the addition of full-sized natural gas burners or the replacement of coal burners with natural gas or dual-fuel burners. Often, the largest risk associated with co-firing is poor natural gas burner placement, which could result in excessive temperatures or incomplete combustion in certain areas.

Modifications to the boiler and boiler auxiliary equipment are often minimal or not required. Control system modifications would be required to incorporate additional burners and natural gas into the plant’s operating system. As long as the burner management system is of a newer vintage, the existing system can be modified and reused. Updates to the combustion control system would also be required.

A disadvantage of coal and natural gas co-firing is that the converted unit would still be considered a coal-fired unit from a regulatory perspective. In addition, displacing only a portion of coal with natural gas generally would not, by itself, be sufficient to meet air regulations. For example, in most cases, a combination of natural gas co-firing and emissions control equipment retrofits would be required to ensure compliance with the MATS for existing coal-fired electric generating units.

Option 1c – Emissions Control Equipment Retrofit
The selection of emissions control equipment is project-dependent, and the compliance solutions vary widely. For the purpose of this case study, the unit being evaluated would need to be retrofitted with emissions control equipment to comply with MATS for mercury, HCl and PM.

Emissions control retrofits for the case study would consist of PAC injection, SDFGD, fabric filter and ID booster fans. The existing cold-side ESP would be demolished and removed from service. A summary of performance impacts associated with retrofitting the case study unit with emissions control equipment is presented in Table 3.

Some potential issues to consider when retrofitting an existing coal-fired unit with emissions control equipment include the following:

  • Switch from ash sales revenue to ash disposal cost (particularly with PAC injection).
  • Increased fly ash production. 
  • Replacement or addition of flue gas fans.
  • Flue gas duct and boiler stiffening.
  • Increased truck traffic.
  • Increased operating and maintenance expenses and staffing.
  • Additional effluent concerns (particularly with wet flue gas desulfurization [WFGD]).
  • Increased auxiliary electric loads.

Option 2a – Repowering Steam Turbine in a Combined Cycle
For the case study, the 2-on-1 combined cycle block configuration consisting of the existing steam turbine receiving steam from two combustion turbine/HRSG trains is assumed to produce a gross output of approximately 600 MW on an average day without the use of supplemental HRSG duct firing. The existing condenser and wet mechanical-draft cooling tower would continue to reject heat from the steam cycle. A summary of performance impacts associated with repowering the case study unit’s steam turbine in a combined cycle configuration is presented in Table 4.

Reusing a portion of an existing coal-fired unit by replacing the boiler with natural gas-fired combustion turbine/HRSG train(s) as the steam source for an existing steam turbine generator in a combined cycle block configuration has the potential for modest life cycle cost savings compared to using a new combined cycle block because some of the major equipment and common systems from the existing coal-fired unit may be reused in the combined cycle configuration. In addition, efficiency would be much higher than converting a coal-fired boiler to natural gas. However, the modest life cycle cost savings are often not enough to offset the unit outage requirements and associated project risk when compared to a new combined cycle.

A reused steam turbine would likely experience a derate from nameplate capacity. A coal unit’s Rankine cycle converts fuel into heat through steam in a boiler. Typically, all of the steam sent from the boiler to the steam turbine is first sent at high pressure and temperature to the HP turbine admission. As the steam travels from the first stage of the HP turbine to the last stage of the low-pressure (LP) turbine, the mass flow decreases, so that the LP turbine receives only a portion of the flow the HP turbine passes.

In a combined cycle block configuration where the HRSG produces steam by using the waste heat from the combustion turbine exhaust, steam is sent to the steam turbine, often at two or more pressures, and the condensate is heated in the HRSG itself. Going from the HP turbine to the LP turbine, steam mass flow increases, which is the opposite of a traditional coal unit’s Rankine cycle. As a result, the repowered steam turbine is much more back-end loaded than it was originally designed and is usually unable to meet its original nameplate capacity. Typically, the derate is approximately 10 to 20 percent of original nameplate capacity. However, the addition of combustion turbine generators would more than make up for the steam turbine generator derate, resulting in a major overall increase in plant output.

The attractiveness of this option will depend on the extent to which existing facilities and systems can be reused. Candidate facilities for reuse include the control room, administration building, maintenance building, water sample laboratory, turbine hall and site security. Candidate systems for reuse include water supply and treatment, wastewater, chemical feed, compressed air, condenser, condensate system, fire water supply, auxiliary power and plant communications. In addition to inside-the-fence plant savings, ready access to transportation, transmission and water could result in substantial cost savings. The three most critical considerations for this option are as follows:

  • Existing means of heat rejection. Facilities with closed loop heat rejection systems that are based on either a cooling tower or air-cooled condenser are ideal candidates for consideration.
  • Space availability for combustion turbine/HRSG trains and associated equipment. The need for significant demolition of existing facilities would add cost and could result in increased outage time/generation losses during construction.
  • Current site electrical export capacity. Replacing a small unit with a unit nearly three times the size might not be possible without transmission interconnection upgrades. The capacity increase could make this option difficult to adopt for many owners with smaller fleets or assets within transmission-constrained regions, which are strategically distributed to meet local demand.

Option 2b – Replace with New Combined Cycle
The option considered for this case study consists of two F-class natural gas combustion turbine/HRSG trains supplying steam to a reheat steam turbine generator in a 2-on-1 combined cycle block configuration constructed at the site of the case study coal-fired unit. Heat rejection would be accomplished by a new wet mechanical-draft cooling tower.

A summary of performance differences between the existing coal-fired unit and the new combined cycle unit is presented in Table 5.

Replacing an existing coal unit with a combined cycle is often the most capital intensive, but also the most efficient, means of switching from coal to natural gas. In addition to being the most efficient of the options presented, a combined cycle could be designed to offer a greater degree of generation flexibility.

The largest and most economical combined cycle block configurations comprise F-class, G class, H-class and J-class combustion turbines; triple pressure HRSGs; and reheat steam turbines. These combined cycle blocks range from a nominal rating of 300 MW-net to more than 1,200 MW-net.
The replacement of an existing coal unit with a combined cycle would require the owner to consider what to do with the retired unit. Leaving a unit in place would require periodic maintenance and security measures. Demolishing the unit would require careful planning and may involve additional cost, depending on the complexity of decommissioning and the value of the salvaged materials.

CASE STUDY FINDINGS

The characteristics of the particular coal-fired unit being considered dictate the most advantageous generation option. The size, vintage, site characteristics and emissions control equipment currently in place can define which option is the most cost-effective and capable of aligning with the current business model. High-level levelized bus bar cost estimates, presented on a U.S. cents per kilowatt-hour (¢/kWh) basis, were developed for the options considered for the case study. The options were compared with annual capacity factors (CFs) ranging from 30 to 90 percent. Figure 1 presents a comparison of the five options for a planned service life of 30 years. Some utilities have considered short-term solutions for “bridging the gap” in the near term to postpone large expenditures. The five options were also compared for a planned service life of 10 years (Figure 2). For both comparisons, two natural gas price scenarios were evaluated. Delivered fuel prices considered for the case study are presented in Table 6.
 
 





SUMMARY

Natural gas prices have fallen in recent years because of the stagnant economy, weakened demand for electricity and increased shale gas production supply. Low natural gas prices and static coal prices have created a business opportunity for power producers to switch from coal-fired to underutilized natural gas-fired power plants. In addition, increasingly stringent environmental regulations will require many coal-fired units to be retired or to be retrofit with emissions control equipment for continued operation on coal. This case study explored five technically feasible options available in the current market for a late 1970s vintage subcritical pulverized coal-fired unit with a nominal gross output of 250 MW.

The five options considered were compared with CFs ranging from 30 to 90 percent. Two natural gas price scenarios (low and high natural gas) and two planned service lives (30 and 10 year) were considered. A summary of options that are expected to be the most cost-effective for the case study 250 MW coal-fired unit is presented in Table 7.

Full conversion to natural gas is only cost-effective with limited planned service hours because high natural gas consumption rates make this option not cost-effective when compared to the more efficient natural gas-fired and coal-fired options presented. Full conversion to natural gas might be advantageous for short-term applications or in instances where installed capacity is needed to meet reserves.

For the case study, conversion to coal and natural gas co-firing is not the most cost-effective option. Displacing coal with natural gas results in incremental nonfuel operations and maintenance cost savings because of reduced emissions control reagent consumption. However, the capital cost required for supply of the natural gas, combined with the capital cost for emissions control equipment additions and the higher cost of natural gas compared to coal, negates these savings.

Retrofitting the unit with emissions control equipment is one of the lowest cost options with high natural gas prices and is a moderate cost option for low natural gas prices. Future coal prices are expected to be relatively stable, so the perceived fuel risk associated with this option tends to be less than for natural gas-fired options. However, the uncertainty risk associated with this option is regulatory-driven. Air-related and coal combustion residuals-related environmental regulations could potentially threaten the future of coal-fired units, making continued operation cost prohibitive.

Combined cycle-based options are cost competitive with lower natural gas prices. High efficiency means that natural gas-fired combined cycle units are less sensitive to natural gas price fluctuations when compared to full conversion of a coal-fired unit to natural gas. However, the capacity increase could make this option difficult to adopt for many owners with smaller fleets or assets within transmission-constrained regions, which are strategically distributed to meet local demand.

The examples presented are indicative only and are not representative of all situations. Owners and operators must consider other factors that cannot be easily represented in this paper. Factors such as the need to maintain fuel flexibility and stability, unit demand, siting costs, impacts to other fleet units and capital expenditure limitations will play a large role in the decision-making process for evaluating the future of coal units.



  Subject Matter Experts:
  Brian Reinhart, ReinhartBC@bv.com
  Alap Shah, ShahAR@bv.com
  Mark Dittus, DittusM@bv.com
  Una Nowling, NowlingUC@bv.com
  Bob Slettehaugh, SlettehaughRA@bv.com