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# Coal-Fired Power Plant Heat Rate Improvement Options, Part 2 12/01/2014 | Sam Korellis
Even without regulatory considerations, there are g ood reasons for virtually every coal-fired power plant to improve its heat rate. The Electric Power Research Institute (EPRI) has looked at dozens of methods for improving heat rates and evaluated their applicability and costs. Part 2 of this two-part series details several EPRI case s tudies of heat rate improvements and summarizes key takeaways. In recent years several EPRI projects have explored different aspects of heat rate improvements. This article, following Part 1 in the N ovember 2014 issue of POWER, reviews results of implementing heat rate optimization prog rams at five power plant sites, with summaries of the issues, recommendations, actions t aken, and resulting heat rate improvements. It also discusses a study conducted to identify potential heat rate improvements that could be implemented across all coal-fir ed power plants in a utility fleet and offers recommendations for future research. 

## Production Cost Optimization Case Studies EPRI’s Production Cost Optimization (PCO) project a ssisted participating members in implementing or enhancing heat rate optimization pr ograms to reduce production costs through sustainable performance improvements. The PCO assessment process consisted of benchmarking plant thermal performance using historical plant data, along with an on-site performance appraisal, to identify potential performance improvement. In some instances, a significant heat rate improvem ent can be achieved with a recommitment to best operating practices and without theneed for large capital expenditures on new technology. Unit heat rate improved at four of the five plants. While most plants had estimates of the improvement expected with the actions taken, itwas not always possible to reconcile observed improvements with estimated improveme nts. Recommendations resulting from the PCO appraisal process were typically a combination of plant-specific items and common, general recommendations, such as establ ishing or expanding routine plant monitoring through testing or online means, e stablishing a cycle isolation procedure, and conducting heat rate awareness training f or plant staff. The plant participants were not always able to impl ement all recommendations and of

# 1 of 12ten had their own initiatives for outage work that resulted in improved heat rate. Performance improve ments were significant and ranged from 3% to 5%. This lev el represents an equal percentage of each plant’s a nnual fuel bill and demonstrates that making heat rate an integral part of maintenance and operations activi ties can yield real and lasting financial savings as well asa significant reduction in carbon dioxide (CO2) an d other emissions. Nineteen power companies participated in this proje ct. The group meets periodically via teleconference s in which the participants share their successes and le ssons learned, enabling the entire group to make pr ogress in improving their units’ heat rate. 

## Plant Profiles For the five coal-fired units for which follow-up a nalyses were completed, net unit capacities ranged from 95 MW to 650 MW. The service ages of the plants ranged from 30 to 55 years, with an average of 40 years. Three plants burn Powder River Basin subbituminous coal, while the others burn bituminous coal. Three boiler s are drum-type units; the remaining two are supercritica l units. All plants but one are single reheat. Thre e plants have once-through cooling, another has a mechanical -draft cooling tower, and the fifth has a natural-d raft cooling tower. Of the five plants with completed analyses and repo rts, the common issues included:

■ Combustion problems and high air heater/stack exitgas temperatures.

■ Limited heat rate information availability.

■ Need for heat rate awareness training, including u nderstanding of controllable losses.

■ Need for unit and equipment performance testing.

■ Feedwater heater train performance problems.

■ Need for sootblowing optimization. 

## General Recommendations The following recommendations are common to the fiv e units covered by follow-up analyses. Provide Heat Rate Awareness Training to Operations Staff. Provide the entire plant staff with heat rate awareness training focused on the basics of heat ra te, the cost of heat rate deviations, and actionabl e heat rate information for operations. Such training willhelp to enhance a positive work culture and provid e staff with the tools to optimize heat rate on an ongoing basis. Make Heat Rate Information Readily Available to Mor e Plant Personnel . Sharing heat rate–related information with a broader segment of plant personnel ca n result in earlier identification and resolution o f heat rate problems. Incorporating heat rate “thinking” i nto day-to-day operational decision-making can redu ce overall plant heat rate. Improve Utilization of Controllable Losses Informat ion by Operations Staff. Incentivize operations staff to monitor and minimize controllable losses. Set contr ollable losses targets to be achievable within constraints of equipment and operating conditions. This may req uire the site(s) to enhance, upgrade, or initiate r eal-time controllable losses displays. Optimize Sootblower Operation . Sootblower optimization can help improve steam te mperature control, normalize heat absorption patterns, and improve pre cipitator performance. Additional benefits such as reduced air heater/stack exit gas temperature, a decl ine in circumferential cracking of boiler tubes, an d NOx emissions reduction may also result. Automated soot blowing optimization can be effective but expensiveto implement. (For more on such systems, see “Boosting Efficiency with a Sootblowing Optimization System”in the November 2014 issue at powermag.com.) A lower-c ost alternative is to conduct parametric testing toprovide insight into the effectiveness of sootblowing patterns and guide operators in achieving best unitperformance. Initiate a Routine Testing Program . A periodic testing program should be established to aid in early detection of changes in equipment performance and/or uni t operation to improve maintenance scheduling efforts and reduce unscheduled outages. By utilizing statio n instrumentation, a reliable, repeatable trend of unit performance can be developed. Guidelines to conduct su ch testing are contained in EPRI reports Routine Performance Test Guidelines(report 1019004) and Routine Performance Test Guidelines, Volume 2(report 1019705). Increase Routine Feedwater Heater Performance Monit oring . Heater terminal temperature difference (TTD) and drain cooler approach (DCA) should be mon itored on a daily basis along with heater levels to maintain optimal performance. In particular, the DCA sh ould be checked to ensure that steam is not enterin g the drain cooler. If this occurs for an extended period of time, the drain cooler will be damaged, resulti ng in tube leaks, heaters out of service, and higher unit heatrate. 

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## Plant-Specific Recommendations The following recommendations, grouped by plant equ ipment/area, were specific to individual plants. Cycle Alignment (aligning the cycle by isolating asmuch as possible of the high-energy fluid leakage from the plant steam cycle)

■ A site-specific cycle alignment checklist should b e developed for operations use to ensure proper con tinued cycle alignment.

■ Perform periodic cycle water loss tests. Instrumentation

■ As transmitters are replaced or upgraded, they sho uld be replaced with high-accuracy, “smart” transmi tters.

■ Plant calibration standards should be set up on a periodic schedule to be calibrated.

■ Set up and use an electronic database for tracking of instrument calibrations.

■ Redundant instruments should be of sufficient accu racy to provide the same readings. If two instrumen ts are measuring the same parameter and provide differ ent readings, they do not provide value to operatio ns. Boiler

■ Utilize the plant performance calculations to tren d boiler efficiency and individual boiler losses so that changes in performance can be identified quickly an d action can be taken to restore boiler efficiency.

■ Resolve coal distribution problems and periodicall y inspect diffusers and riffle distributors.

■ Review boiler optimization after a coal distributi on problem is addressed.

■ Perform unit diagnostic testing to determine the O 2, CO, and NOx distribution at the economizer outle t duct where the present in-situ O2 analyzers are located. With some additional effort, these tests could be used to assess the degree of air in-leakage between this lo cation and the furnace exit to verify that most, if not all, of the casing leakage has been satisfactorily repaired . This information can be used to fix the leaks and may help to recover induced-draft fan capacity, especially d uring warmer summer months. These tests will also i dentify the minimum O2 operating level for best efficiency without excessive CO and unburned carbon. Other pot ential benefits of these efforts are reduced back-end temperature, improved precipitator performance, an d reduced NOx and mercury emissions.

■ Maintenance efforts should give priority to restor ing burner tilt functionality; restoring burner cor ner secondary air damper functionality; inspecting coal no zzle condition and replacing as necessary; repairin g furnace casing leaks; and repairing leaking valves. Turbine

■ Use turbine performance data to help determine whe n a turbine overhaul is necessary.

■ Trend the high-pressure (HP) and intermediate-pres sure (IP) turbine efficiency periodically with the unit at a consistent operating point (typically, full load, v alves-wide-open is best).

■ Continue to monitor HP and IP section efficiency u sing the performance monitoring system.

■ Conduct temperature variation tests prior to the n ext turbine outage to determine the benefit of repl acing turbine seals and/or snout rings. Condenser

■ Monitor condenser pressure and compare to target d aily to ensure proper condenser performance.

■ Consider using or installing an online air in-leakage monitor. Feedwater Heaters

■ Monitor heater TTDs and DCAs on a daily basis, alo ng with heater levels, to maintain optimal performa nce.

■ For heaters with off-design TTDs and temperature r ises that are close to design, verify that extracti on pressure water legs are properly accounted for.

■ Repair or replace the HP feedwater heater.

■ Check first-point heater outlet temperature as com pared to economizer inlet temperature to ensure fee dwater is not bypassing the top heater(s). 

# 3 of 12Cooling Tower

■ Consider accelerating the fill replacement schedul e to reduce cold water temperature and condenser pr essure.

■ Perform an annual inspection of the cooling tower with a focus on performance.

■ For mechanical-draft towers, as fan blades require replacement, consider upgrading to high-efficiency fans. There is insufficient justification for upgrading t he fans until there is a mechanical reason for repl acement.

■ As replacement fan stacks are needed, upgrade to h igh-performance stacks to improve airflow and cooli ng. Technology Review

■ Maintain controls tuning and responsiveness in add ressing controls issues.

■ Review the plant historian and consider removing p oints that are no longer valid or no longer used.

■ Distribute key performance information to commonlyused operator screens. If the controllable loss in formation is on the common screens, there is a better chance that it will be used.

■ Increase the visibility of heat rate and performan ce information throughout the plant. Taking this st ep will help improve heat rate awareness.

■ Ensure that the design or target values on the con trollable loss screens are realistic, achievable va lues over the load range.

■ Input periodic fuel analysis into the online monit oring system so that better values of heat rate and boiler efficiency can be calculated.

■ Input periodic carbon-in-ash loss values into the online performance monitoring system so that bettervalues of heat rate and boiler efficiency can be calcu lated.

■ Provide heat rate awareness training, primarily fo r operations.

■ Have operations start monitoring controllable loss es.

■ Ensure that critical performance-related data are being properly stored in the plant historian.

■ Consider upgrading to a more robust performance mo nitoring system that will run reliably without sign ificant upkeep. 

## Potential Heat Rate Improvements As noted above, actual heat rate improvement for th e plants participating in the PCO follow-up assessm ents ranged from 3% to 5%. Potential heat rate improveme nts for some of the common recommendations were estimated as follows:

■ Provide heat rate awareness training to operationsstaff: 50 Btu/kWh to 100 Btu/kWh.

■ Make heat rate information readily available to mo re plant personnel: 50 Btu/kWh to 150 Btu/kWh.

■ Improve utilization of controllable losses informa tion by operations staff: 75 Btu/kWh to 100 Btu/kWh
.
■ Optimize sootblower operation: 70 Btu/kWh.

■ Initiate a routine testing program: 75 Btu/kWh to 200 Btu/kWh.

■ Increase routine feedwater heater monitoring: 30 B tu/kWh to 60 Btu/kWh. Boiler . Potential heat rate improvement from recommendati ons to improve boiler heat transfer and combustion were estimated to be 100 Btu/kWh or better. So otblowing optimization was estimated to have a pote ntial improvement of 70 Btu/kWh. Turbine . Potential heat rate improvement from recommendati ons to improve turbine cycle performance was estimated to be 100 Btu/kWh or better. Losses due t o worn internal seals and snout rings were estimate d to be 20 to 50 Btu/kWh or higher. Feedwater Heaters . Potential heat rate improvement from replacing th e first point heater was estimated to be 150 Btu/kWh. Plant heat rates were trended for one-month periodsduring the original PCO assessment and then again during the follow-up assessment. The time elapsed b etween the original and follow-up assessments range d from 20 to 24 months. Heat rates were calculated us ing two different methods: input/output method and en

# 4 of 12ergy balance method. Some plants reported expected heat rate improvement s from actions that they had taken or planned to ta ke, which ranged from 200 Btu/kWh to 400 Btu/kWh, appro ximately 2% to 4%. Though it was difficult to corre late specific improvements with measured data, it was cl ear from the assessments that plant efficiency impr oved significantly at four of the five plants completing follow-up assessments. The magnitude of the heat r ate improvements ranged from 279 Btu/kWh to 557 Btu/kWh a t or near full-load operation, which represents an approximate 3% to 5% improvement in heat rate. The re sults of this project are site-specific and are notuniversally applicable to all coal-fired power plants. Winners and a Loser. Plant “A” improved its heat rate by 279 Btu/kWh th rough comprehensive organizational focus of multi-level heat rate teams, traini ng of operations staff, and close attention to mini mizing boiler excess air. With a 557 Btu/kWh improvement, Plant “B” decreased its heat rate by the largest margin. This improvem ent was accomplished through diligent cycle alignment, reduction of boiler casing air in-leakage, a turbin e chemical cleaning, and reduced condenser air in-leakage. Plant “C” improved its heat rate by 400 Btu/kWh, of which plant staff attributed 100 Btu/kWh to boilerimprovements and 250 Btu/kWh to steam path maintenanc e and a feedwater heater replacement. Plant “D” improved heat rate by 500 Btu/kWh with su bstantial maintenance work, including reducing boil er casing air in-leakage, replacing a feedwater heater, and cleaning condenser and feedwater tubes. Unlike the other four plants in the follow-up studi es, heat rate for Plant “E” increased unexpectedly by 350 Btu/kWh. This result was thought to be due in part to increased cycling and extended operation at lowe r loads. Fuel Savings and CO2 Benefits. With heat rate improvements ranging from 3% to 5%, the results of the PCO follow-up studies clearly demonstrate that plant he at rate can be favorably affected by operational an d maintenance activities undertaken by plant owners. Not all participants actively quantify return on invest ment of activities in terms of fuel savings, but these savi ngs are very significant. For example, a 5% improve ment in the heat rate of an 500-MW (net) power plant can be worth more than $3,500,000 in annual fuel savings and reduce CO2 emissions over 180,000 tons annually. 

## Fleetwide Assessment Case Study In 2010, EPRI conducted a study with a member utili ty to identify power plant efficiency improvements that could be implemented across all 12 coal-fired unitsin its fleet to reduce CO  emissions. The study and its findings are described in the EPRI report Methodology for Fleetwide Energy Efficiency Analysi s(report 1021206). This project was undertaken to show how coal plant energy-efficiency improvements could be used to red uce CO  emissions. The utility established a Plant Energ y Efficiency Team (PEET) to explore the company’s o ptions for improving coal plant efficiency. The PEET resul ts are focused on tons of CO  avoided or reduced and the cost per ton of CO  avoided or reduced. The estimate d cost per ton of CO  avoided or reduced for each te chnology can be used to determine which projects are potentially viable based on the price of CO  credits . For the study, the project team applied a standardi zed methodology previously developed for evaluating efficiency improving projects in a single power plant, described in the EPRI report Capital and Maintenance Projects for Efficiency Improvements(report 1019002). (See Part 1 in the November issu e for more.) The most powerful use of this approach is to apply the method to an entire fleet, in which a set of po tential projects can be evaluated for a group of specific c oal-fired units. In this project, the project team compiled a list of feasible efficiency improvement options and conducted analyses to determine project-specific n et annual benefits in relation to reduction of CO  emissi ons. Researchers compiled information from various internal sources and then added more projects from an EP RI capital projects report. All projects were liste d in a spreadsheet and normalized to match each unit withi n the current operating system. This study covered only projects for existing coal- fired power plants. This was not an integrated reso urce plan study; the PEET was not trying to determine how bes t to increase generation. The assumption was made t hat net plant output remained constant. If the proposed project happened to increase capacity along with e fficiency, the fuel burn was reduced to maintain a con stant net output. CO  emissions reduced or avoided w ere then calculated and summarized. The following steps were used to evaluate potential energy-efficiency improvement projects for that fl eet:

■ Assemble a team of experts within the utility with collective knowledge covering all of the units bei ng investigated and all the projects being considered.

■ Identify the potential projects, using the spreads heet in EPRI Report 1019002 as the starting point.

■ Identify the coal-fired units to be included in th e analysis. 2

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# 5 of 12■ Screen projects for feasibility of application to each unit in the fleet.

■ Determine project attributes for each application.

■ Evaluate the applicable projects for each unit.

■ Develop project ranking based on the cost/benefit analysis for each application.

■ Prepare Pareto curves to provide management with a decision-making tool to prepare for any future car bon-related charges.

■ Issue fleet-specific report. The technology feasibility screening process identi fied more than 40 candidate projects, organized by six major plant systems (Table 1). The project team condu cted a fatal-flaw analysis to determine the feasibi lity of the efficiency projects on a unit-by-unit basis at the 12 coal-fired units. Many potential projects may no t be feasible for a particular plant or unit based on its con figuration. For example, low-pressure turbine repla cement is not a potential project for a unit that just replac ed its entire turbine. Numerous energy efficiency p rojects had already been completed in advance of this study. Th is list is not inclusive of all potential heat rateimprovement projects—only those used by the utility conduct ing this analysis.

(http://cdn.powermag.com/wp-content/uploads/2014/1 2

/PWR_120114_SR_Heatrate_Table1.jpg) Table 1. List of generation efficiency projects by major plant systems. Source: EPRI More than 490 individual potential projects were id entified and screened for feasibility. Of these, 17 4 projects were identified by PEET as potentially feasible. An alysis determined that several project types may bejustified, independent of the project’s economic life, and man y may be justified without any CO  credits and shoul d be given further consideration. There are many potential projects to improve plant energy efficiency and reduce CO  emissions. The PEET 2

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# 6 of 12analysis provides a tool that will allow for numero us potential projects that improve plant energy efficiency and reduce CO  emissions to be evaluated and ranked easily. Based on a 30-year economic life, the PEET analysis estimated that if all 174 projects were implem ented, the upper limit for fleetwide coal plant CO reductions through efficiency improvement would be abouttwo million tons a year (approximately a 5.3% redu ction of the current operating fleet CO  emissions) a t an estimated capital cost of over $800,000,000 (F igure 1). However, initial evaluation indicated there might b e some projects that should be investigated furtherregardless of the value of CO , yielding about one mil lion tons a year in reduction of CO  emissions (appr oximately a 2.7% reduction of the fleet’s CO  emissions ).

(http://cdn.powermag.com/wp-content/uploads/2014/12 /PWR_120114_SR_Heatrate_Fig1.jpg) 1. CO  reductions . This graph depicts cumulative CO  reduction and co st per ton of CO  removed for heat rate improvement projects discussed in this article. Projects with a negative cost per ton of CO  (where the blue line i s below the red line) may be justified even without a credit for CO removal. Courtesy: EPRI 

## Adding It All Up Power plants are designed for an optimal heat rate. Although that heat rate may not be the lowest achi evable at any point in time, trade-offs occur with respectto capital and operation and maintenance costs, si ting, and fuel. The average age of operating coal-fired powerplants is 40 years. Over the course of those four decades, the plants have been subject to physical modificati ons and repairs and have suffered age-related degra dation. Many of those modifications have been the add ition of emissions controls, which typically have a n adverse effect on heat rate. Since initial startup, m any units have changed their fuel supply and reduce d staffing size, creating additional potentially adverse heat rate effects. In most recent times, these old coal plants have been called on for flexible operation, requiring lo ad following and significant time at part load, aga in reducing plant efficiency. EPRI’s research has identified examples—both demonst rated/realized and projected—of methods to improve heat rate or recover efficiency losses:

■ PCO project. The units evaluated realized 3% to 5% heat rate i mprovements through various means.

■ Sliding pressure . By employing sliding pressure over a several-mont h period, a 2% heat rate improvement was realized at part load.

■ Remote monitoring. The use of remote monitoring centers was documente d to improve heat rate 2.5% to 4%.

■ Steam turbine steam path modifications. EPRI members reported steam turbine steam path mod ifications were worth 2% to 4% heat rate improvements.

■ Cycle alignment. Implementing a cycle alignment (isolation) program was documented to be worth at least 0.5% improvement in heat rate.

■ Capital and maintenance projects. A list of 57 potential actions and modifications t o improve efficiency was made and evaluated in detail. While the amount of g ains would be unit-specific, the projected heat rat e improvements ranged from less than 0.1% to over 2% fo r the various actions and modifications. One utility applied the methodology and analyzed a number of thes e potential projects for its own specific fleet, re sulting in a projected 5% improvement in heat rate.

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# 7 of 12←EPA’s Proposed Revisions to Ozone Standards to Cost up to $15B Annually (http://www.powermag.com /epas-proposed-revisions-to-ozone-standards-to-cost up-to-15b-annually/ ) THE BIG PICTURE: Wind and Solar Variability →(http://www.powermag.com/the-big-picturewind-and-solar-variability/) More Stories You Might Like The numerical values presented in this article may not be additive. They also may not be achievable orjustifiable at every coal-fired plant. The staffs at many well-performing plants have been proactive and havealready implemented some of the previously discussed improv ements (for example, steam turbine upgrades and remote monitoring centers), thereby reducing their po tential maximum heat rate improvement range. The finances of power generating companies, both re gulated and independent power producers, are managed prudently, so any large expenditure must be ju stified and/or create a return on investment. Small er units consume less fuel, making a reasonable return on investment difficult to achieve for expensive m odifications. As mentioned, these units are old and may ha ve a limited remaining life. Some of these modifica tions and actions are quite costly and require a long per iod of operation to realize a return on investment. Such modifications may not be applicable for units with a few or unknown years of remaining projected lifet ime. Finally, management of many coal-fired plants may b e unwilling to attempt many of these proposed impro vements in order to avoid the possibility of triggeri ng a New Source Review, which may result in having to install millions of dollars of additional emissions control s. 

## Future Research Many of the efficiency improvement projects have be en done in parallel, so the individual effect of ea ch is not well defined. Tests and analyses could be conducted before and after future individual modifications a re made to refine the results and reduce the uncertainty wh en those modifications are proposed for other units . Based on industry data and studies conducted by EPRI and others, the maximum achievable heat rate improvement for any given coal-fired plant is unknown . More detailed studies to characterize improvement s, taking into consideration constraints like fuel cha nges, equipment degradation, design changes, new en vironmental controls, and so forth, are needed to determ ine the technical and economic feasibility of the o ptions. Afterwards, an estimate could be made of the maximu m potential efficiency gains. While the cost may be high, one could attempt to im plement as many of those modifications and actions as possible on one unit and measure the gains realized to provide perhaps the upper cap of expected heat rate improvement. ■

— Sam Korellisis a principal technical leader in the Combustion Performance and Emissions Control R&D group at EPRI.

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