Lower pressure boilers still must be handled with care

Figure 1 provides a basic schematic of a common co-generation configuration.   

Figure 1. Generic flow diagram of a co-generation system. The blowdown heat exchanger and feedwater heater may not be present in some configurations. Note the multiple condensate return lines. Illustration courtesy of ChemTreat, Inc. 

Depending on boiler pressure and design, and the processes served by the boiler steam, makeup treatment may range from sodium softening to reverse osmosis to perhaps even the high-purity arrangements outlined in Part 1. For steam generators under 600 psig pressure, sodium softening, often combined with downstream equipment for alkalinity removal, is common. Figure 2 below is an extract taken from the recent revision of the American Society of Mechanical Engineers (ASME) industrial boiler water guidelines ⁽¹⁾. This extract provides insight on impurity level limits for low- to medium-pressure water tube industrial steam generators. The complete guidelines are available from the ASME at very reasonable cost and should be in the library of any industrial plant with steam generators.

Figure 2. Data extracted from Table 1, Reference 1 – “Suggested Water Chemistry Targets Industrial Water Tube with Superheater”

While power plant chemists are (or should be) familiar with stringent requirements for their high-pressure units (which we will return to in later parts of this series), several guidelines in this extract stand out for lower-pressure boilers. These include:

• Low feedwater hardness, dissolved oxygen, total iron, copper, and total organic carbon (TOC)
• Feedwater pH ranges designed to protect most metals. (Operation near the lower-end of the range is common to project copper alloys.)
• The long-standing philosophy of allowing some bicarbonate alkalinity (HCO₃^–) in the boiler water, but which may influence condensate return chemistry.
• A strong emphasis on steam purity, which is in part a function of boiler water impurity concentrations, thus the increasingly stringent boiler water contaminant guidelines as a function of increasing pressure.

 Let us consider these items in greater detail with help from References 2 and 3.

Hardness Excursions

A very common comment/question that steam generation chemistry experts receive from industrial boiler operators is, “We are suffering repeated boiler tube failures, can you help us find the source.” One of the first items a specialist will typically examine is the sodium softener. Time after time, the consultant will learn that softener upsets have been common but that the plant continues to operate with out-of-spec makeup water going to the boiler. Figures 2 and 3 illustrate the typical result of softener upsets and malfunctions.

Figure 4.  Bulges and blisters in a boiler tube from overheating due to internal deposits.  Photo courtesy of ChemTreat, Inc.

A common malady at many plants, which this author has directly observed on several occasions, is an intense focus by plant personnel on process chemistry and engineering with insufficient attention to steam generators (and cooling systems) until failures begin to cause unit shutdowns that affect production. Water and steam are the lifeblood at many plants, and to neglect these systems puts plant operation and sometimes employee safety at peril.

Apart from hardness capture, even well-operated sodium softeners by themselves remove no other ions from the makeup water. In low-pressure boilers with good blowdown control, most impurities may be manageable. However, issues regarding alkalinity (the alkalinity in raw water is usually in the bicarbonate, HCO₃^–, form) deserve additional discussion.

HCO₃^–, upon reaching the boiler, in large measure converts to CO₂ via the following reactions:

2HCO₃^– + heat → CO₃^2- + CO₂↑­ + H₂O                                             Eq. 1

CO₃^2- + heat → CO₂↑­ + OH^–                                                              Eq. 2

The conversion of CO₂ from the combined reactions may reach 90%. CO₂ flashes off with steam, and when the CO₂ re-dissolves in the condensate can increase the acidity. 

CO₂ + H₂O ⇌ H₂CO₃ ⇌ H⁺ + HCO₃^–                                                 Eq. 3

Long-term carbon-steel corrosion may be the result.

Figure 5.  Carbonic acid grooving of a condensate return line. Photo courtesy of ChemTreat, Inc.

Furthermore, the iron oxide corrosion products will transport to the steam generators and form porous deposits on boiler tubes and other internals. These precipitates can become sites for under-deposit corrosion (UDC) fed by impurities in the boiler water. UDC generally increases in severity with increasing boiler pressure and temperature. At high-pressures, UDC can lead to hydrogen damage, a very insidious corrosion mechanism. 

Some sodium-softened makeup systems also have a forced-draft de-carbonator or split-stream de-alkalizer to remove most of the bicarbonate alkalinity, but even with this equipment the remaining dissolved ions in the raw water still enter the boiler makeup. These impurities reduce the allowable cycles of concentration in the boiler, which leads to increased blowdown. If not properly monitored and controlled, they may cause corrosion or increase the dissolved solids concentration in the boiler steam. Accordingly, becoming more popular is reverse osmosis (RO) for makeup water treatment. Even single-pass RO will remove 99% or greater of the total dissolved ions in the makeup water.

Figure 6. Basic design of a single-pass, two-stage RO. The designation two-stage comes from treatment of the first stage reject in a second stage. (3)

As we discussed in Part 1, addition of a second pass to the RO system with downstream polishing by ion exchange or electrodeionization produces makeup suitable for even the highest-pressure steam generators.

The wild card for co-gen units – Condensate return

Steam generators that solely produce power nearly represent (usually) a closed circuit. A tight system may only have 1% water loss. The most common source of impurity ingress is a leaking tube or tubes in the steam surface condenser. (Units with air-cooled condensers offer other factors to consider.) So, with a good on-line chemistry monitoring system and attentive plant personnel, upsets can usually be quickly corrected. The situation is frequently much different in co-gen units, where condensate could be coming back from any number of chemical heating/reaction processes. Consider the following case history.

A number of years ago, the author and a colleague were invited to an organic chemicals plant that had four 550-psig package boilers with superheaters. The steam provided energy to multiple plant heat exchangers, with recovery of most of the condensate. Each of the boiler superheaters failed, on average, every 1.5–2 years from internal deposition and subsequent overheating of the tubes. Inspection of an extracted superheater tube bundle revealed deposits of approximately ⅛–¼ inches in depth. 

Additional inspection revealed foam issuing from the saturated steam sample line of every boiler, whose cause became quickly apparent. Among the data from water/steam analyses performed by an outside vendor were total organic carbon (TOC) levels of up to 200 mg/L in the condensate return. Contrast that with the <0.5 mg/L feedwater TOC recommendation in Figure 2. No treatment processes or condensate polishing systems were in place to remove these organics upstream of the boilers. Based on the TOC data alone, it was easily understandable why foam was issuing from the steam sample lines, and why the superheaters rapidly accumulated deposits and then failed from overheating.

To protect steam generators from what could be a wide variety of impurities, careful planning is needed to determine, among others, what contaminants and in what concentration may be in the return condensate, can the impurities be economically removed by some form of condensate polishing system, and what streams may need diversion directly to the wastewater treatment plant? The latter issue, of course, influences the size and treatment methods of the wastewater system. Also, condensate dumping to the WWT plant requires increased makeup water production and a larger system in that regard.

Another important issue with co-gen and industrial steam units is feedwater dissolved oxygen control.  In September and October of 2022, Power Engineering published a four-part series by the author on the importance of controlling flow-accelerated corrosion (FAC) in combined cycle heat recovery steam generators (HRSGs). ⁽⁴⁾ Because these high-pressure HRSGs require high-purity makeup (cation conductivity ≤0.2 mS/cm), and typically have no copper alloys in the feedwater system, the recommended chemistry calls for a small amount of dissolved oxygen (D.O.) in the feedwater with no oxygen scavenger (the better term is reducing agent) feed. For units with deaerators, it may be necessary to close the deaerator vents to help maintain a D.O. residual in the economizer circuits. Supplemental oxygen injection may also be required. For those who review this series, note that these guidelines are part of a feedwater chemistry program known as all-volatile treatment oxidizing (AVT(O)).

However, because the condensate return purity in co-gen and industrial steam generators often does not meet high-pressure feedwater guidelines, AVT(O) is usually not acceptable. The feedwater network may also contain heat exchangers with copper-alloy tubes, which further negates AVT(O) as a potential treatment program. Accordingly, a standard requirement is feed of an alkalizing amine to maintain pH within the range shown in Figure 2 plus mechanical deaeration and reducing agent/oxygen scavenger feed to maintain very low feedwater D.O. concentrations. This in turn necessitates accurate monitoring for feedwater iron (and at times copper) corrosion products to fine-tune chemical treatment programs. The author and colleagues have reported on these issues in previous Power Engineering articles. ^{(5, 6)}

Note:  The Electric Power Research Institute (EPRI) has published a comprehensive book on flow-accelerated corrosion that is offered to EPRI members and non-members alike. ⁽⁷⁾     

Conclusion

Co-generation is becoming increasingly popular for power production and process heating at many facilities, in large part because the net efficiency is much higher (and corresponding carbon dioxide emissions are lower) than for traditional power generation. ⁽⁸⁾ However, co-gen chemistry personnel often face additional challenges over those encountered by their power plant counterparts. Careful planning and good vigilance are necessary to minimize corrosion and fouling in these systems.

References

1. Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers, The American Society of Mechanical Engineers, New York, NY, 2021.
2. Buecker, B., Koom-Dadzie, A., Barbot, E., and F. Murphy, “Makeup Water Treatment and Condensate Return:  Major Influences on Chemistry Control in Co-Gen and Industrial Steam Generators”; presented at the 41^st Annual Electric Utility Chemistry Workshop, June 6-8, 2023, Champaign, Illinois.
3. B. Buecker (Tech. Ed.), “Water Essentials Handbook”; 2023. ChemTreat, Inc., Glen Allen, VA.  Currently being released in digital format at www.chemtreat.com.
4. B. Buecker, “HRSG Steam Generation Issues: Reemphasizing the Importance of FAC Corrosion Control, Parts 1-4”; Power Engineering, September-October 2022.
5. Buecker, B., and F. Murphy, “Breakdown:  Is Flow-Accelerated Corrosion a Concern in Co-Generation Steam Generators”; Power Engineering, October 2020.
6. Buecker, B., Kuruc, K., and L. Johnson, “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
7. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Plants, 2017. Electric Power Research Institute, Palo Alto, CA, USA, 3002011569. While EPRI typically charges a fee for reports to non-EPRI members, this document is available at no charge due to the importance of safety for FAC understanding and mitigation.
8. B. Buecker, “A Thermodynamic Overview of Co-Generation and Combined Cycle Power vs. Conventional Steam Generation”; Power Engineering, March 2021.

Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station.  His work also included 11 years with two engineering firms, Burns & McDonnell and Kiewit, and he also spent two years as acting water/wastewater supervisor at a chemical plant.  Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry.  He has authored or co-authored over 250 articles for various technical trade magazines and has written three books on power plant chemistry and air pollution control.  He may be reached at beakertoo@aol.com.

District Energy St. Paul and Caterpillar plan to demonstrate a hydrogen-fueled combined heat and power (CHP) system.

The three-year project involves siting a Caterpillar-supplied CHP unit capable of producing 2 MW and providing waste heat for useable thermal energy. The CHP unit will be fueled by various combinations of hydrogen and natural gas.

Power and heat from the project will integrate into District Energy St. Paul’s infrastructure. District Energy St. Paul distributes cold and hot water to heat and cool buildings in downtown St. Paul, Minnesota and adjacent areas.

The pilot is supported and partially funded by the Department of Energy’s Office of Energy Efficiency and Renewable Energy as well as the National Renewable Energy Laboratory (NREL).

The project is in the early planning and design stage, with installation and data collection expected to begin in late 2023.

District Energy aims to be carbon neutral by 2050, with a 7% carbon reduction goal per year. District Energy is also working with Xcel Energy on an electrification project to further decarbonize its heating systems.

Caterpillar currently offers a 1250 kW generator set capable of operating on 100% hydrogen, according to the company, as well as power generators from 400 kW to 4.5 MW that can be configured to operate on natural gas blended with up to 25% hydrogen.

A Level-1 trauma center in Staten Island, New York is adding a natural gas-fueled onsite cogeneration plant so the hospital can produce its own power.

Rolls-Royce is providing two combined cooling, heating and power (CCHP) trigeneration units for Richmond University Medical Center (RUMC). The system is expected to provide the hospital’s daily power needs, while generating steam for hot water, heating and air conditioning.

The project will begin powering the hospital in Fall 2022, hospital officials said.

Rated at 1.5 MW each, the CCHP units are to be housed in a former laundry facility adjacent to the hospital. The project is being managed by developer Innovative Energy Strategies (IES) and is part of RUMC’s multi-million dollar expansion.

While RUMC will remain connected to the grid, the cogeneration plant will allow it to become self-sufficient, especially during emergency situations. The hospital has recognized the need for an alternative power supply system following outages caused by Hurricane Sandy in 2012.

“Given that RUMC is the only hospital on Staten Island not in a flood zone, the ability to maximize hospital resilience by being energy self-sufficient was of major importance,” an RUMC spokesperson said.

A 16 MW combined heat and power (CHP) plant is now operating on the southern edge of Purdue University’s West Lafayette, Indiana campus.

The gas-powered plant was built and is owned and operated by Duke Energy. It produces electricity for the company’s Indiana customers and provides thermal energy in the form of steam for Purdue’s heating and hot water needs.

Through an approved agreement, Duke Energy will sell to Purdue the steam the plant produces. The plant can produce up to 150,000 pounds of steam per hour, according to the utility. 

By using steam from the new CHP plant, the university will have more operational flexibility. In the event of an electric grid disruption, the new plant could provide emergency power to help keep the campus running.

In combined heat and power, or cogeneration plants, heat that would otherwise be wasted in the production of electricity is captured and used. Because of this, CHP plants require less fuel to produce the same amount of total energy, resulting in reduced environmental emissions.

According to Duke Energy, the new plant is projected to reduce carbon dioxide emissions by approximately 50,000 metric tons.

In 2019, Purdue trustees approved leasing one acre of land to the utility, which allowed for the building of the CHP plant.

Duke Energy has pursued similar CHP plant partnerships with universities and other institutions.

The utility also has a CHP plant at Clemson University in South Carolina. Duke Energy and Clemson, along with Siemens Energy, teamed up to study the use of hydrogen for energy storage and as a low-carbon fuel source at the Clemson CHP plant. The U.S. Department of Energy (DOE) awarded a $200,000 grant for the pilot research initiative.    

The pilot, called H2-Orange – a nod to hydrogen gas and the collaboration with Clemson University – began in March 2021 and would include studies on hydrogen production, storage and co-firing with natural gas.

By Andre de Bache, Kurita Europe; Bill Smith, Uniper UK Ltd.; and Paul McCann, Uniper UK Ltd.

Film Forming Products (FFP) based on Film Forming Substances (FFS) or Film Forming Amines (FFA) are increasingly being used as an alternative to conventional treatment programs for water/steam cycle protection against corrosion in industrial steam generators, as well as in fossil, combined cycle and biomass power plants.

If applied correctly, FFPs can provide the following advantages if plant design or operation means that effective protection is not achieved with optimized traditional treatment programs:

• Reduction of Flow-Accelerated Corrosion (FAC)
• Excellent protection during outages and lay-up periods
• Significant reduction of corrosion and metal oxide transport
• Lower corrosion products especially during start-ups after shutdown periods
• Shorter turbine coupling time at restart after shutdown
• Formation of clean, smooth heat transfer surfaces.

The number of units treated with FFP has significantly increased over recent years. The International Association for the Properties of Water and Steam (IAPWS) has released two Technical Guidance Documents (TGD) dealing with the Application of Film Forming Substances (FFS) in Industrial Steam Generators (IAPWS TGD11-19), and in Fossil, Combined Cycle and Biomass Power Plants (IAPWS TGD8-16, 2019). In these TGDs three substances, among them, Oleyl Propylenediamine (OLDA) are listed. These have been the subject of intensive research and where significant application experience is available [1], [2].

Kurita’s Cetamine^® technology, based on OLDA, provides an excellent treatment option for water/steam cycles, especially for plants operating in cycling mode where preservation is required during shutdowns, but unit availability must be maintained [3]. Successful applications of Film Forming Products have been reported for plants which are both continuously operated, [4 – 8] and under wet or dry-lay-up [9, 10].

The Film Forming Amine (FFA) molecule (OLDA) adsorbs onto metal/metal oxide surfaces to form a hydrophobic film or barrier, which prevents corrosion by stopping water and other corrosive agents from contacting the metal/metal oxide surface. Furthermore, the thin film fosters the formation of a smooth and compact iron oxide layer [11].

Once formed, the protective film remains intact in both wet and dry conditions. This offers significant potential benefits for plants under a cycling mode of operation, and for the preservation of both drained and (partially) filled plants during a shutdown. In particular, it is especially important to demonstrate the presence of a protective Cetamine^®-film on system surfaces to assure long-term protection during shutdown conditions. To demonstrate this, Kurita has developed the patented Cetamine^® Wipe Test to be applied on accessible system surfaces during routine plant inspections.

In this article, the successful application of Cetamine^® technology in a combined cycle power plant under cycling mode conditions is described.

To learn more about Kurita, click here.

Cycling mode operation

Connah’s Quay Power Station consists of four 345 MW single-shaft combined cycle units. The heat recovery steam generators (HRSGs) are vertical gas path drum boilers, with three pressure stages (6, 36 and 120 bar) and reheat (Figures 1 and 2). The final superheated steam temperature is 540 °C [3].

The station operating regime varies, with between one and four units running with daily start-ups and shutdowns, and longer standby periods where unit availability must be maintained. The implementation of conventional preservation methods was difficult without compromising start-up times and it was not possible to protect all plant areas due to plant design [3].

Film Forming Technology was identified as a flexible preservation option and the application of Cetamine^® Technology was implemented in December 2013. The conventional cycle chemistry was kept on ammonia dosing to the feedwater to pH 9.4 to 9.6, and sodium hydroxide to the drums to achieve a pH between 9.2 and 9.4 in the high pressure (HP) drum and, between 9.5 and 9.8 in the intermediate pressure (IP) and low pressure (LP) drums.

The Cetamine^® product was dosed into the condensate line. After initial dosing, the target residual FFA in the return condensate before the injection point was measured in Unit 4 after 420 hours of operation and in Unit 1 after 380 hours of operation [3]. The measurement was realized by the Cetamine® Photometric Method.

During inspections of Unit 1 and Unit 4, systematic investigations have been done to answer one of the key questions: Had the protective Cetamine^®-film been established in the entire system. For the determination of the FFA molecule OLDA on the internal surfaces of components in the water/steam cycles, three different test methods were applied: the hydrophobicity test (droplet test) and the Cetamine^® Wipe Test were used on-site; X-ray photoelectron spectroscopy (XPS) was carried out on small tubing samples by a specialist external laboratory.

The hydrophobicity test is very simple to apply and qualitatively, the presence of a film can be demonstrated by the lack of wettability of the metal surface. This is the most common and easiest method to qualitatively detect the FFA on a metal/oxide surface. However,  hydrophobicity sometimes cannot be observed, e.g. in the case of a rough surface with porous iron oxide deposits, even though FFA is present on the surface [1], [2].

Consequently, Kurita has developed the Cetamine^® Wipe Test, an easy, non-destructive method to semi-quantitatively determine FFA on the inner surfaces of water-steam cycles immediately on-site during plant inspections (Figure 3). XPS was applied as an additional technique to analyze the presence of the FFA nitrogen atoms on a total of four HP evaporator tubes and two reheater tubes.

During the inspection of the LP turbines from Unit 1 and Unit 4, the surfaces in Stage 5 (outlet) were submitted to extensive evaluation with the wipe test due to ready in-situ access. Each wipe test sample showed a clear pink coloration and a significantly higher absorbance value compared to the blank. Furthermore, wipe tests from all stages of the Unit 1 LP turbine were taken from both the trailing face and from the front face of the turbine blades. The results are summarized in Table 1 [3].

Table 1 Cetamine^® Wipe Test short procedure

A total of four evaporator HP evaporator tubes and two reheater tubes were analyzed by XPS. The FFA nitrogen was found in all of the samples. As a comparison, nitrogen could not be detected on the HP evaporator tube from 2012 before the Cetamine^® treatment, which had been taken as a blank. The results are summarized in Table 2. The positive results of the Cetamine^® Wipe Test on the Unit 1 HP evaporator tube confirmed qualitatively the findings of the XPS study [3].

Table 2 Cetamine^® Wipe Test short procedure

After more than seven years of use of Kurita’s Cetamine^® technology in all four units of Uniper’s Connah Quay power station in the UK, the following plant monitoring, inspections, and operating experiences have been observed:

• During shutdowns, Cetamine^® Technology enables the protection of components throughout the water/steam cycle, including areas that could not be preserved by conventional lay-up methods.
• Reduced manpower is required for boiler and turbine preservation compared to previous practices.
• Outage inspections showed that the HRSG and LP steam turbine internal surfaces remained clean and free of corrosion.
• A reliable Cetamine^® Photometric Method was provided by Kurita to monitor the residual concentrations of Cetamine^® in water-steam samples.
• Cetamine adsorption onto HRSG water and dry steam surfaces was proven by positive detection of amine nitrogen on boiler tube samples.
• Cetamine^® Technology has enabled plant preservation to be significantly improved without affecting unit availability or start-up times.

Conclusion

During plant inspections, the presence of the FFA OLDA has been verified on HP evaporator boiler tube surfaces both with the Cetamine^® Wipe Test and by XPS. OLDA was also present on the surfaces of reheater tubes and LP turbine blades. The investigations strongly indicate that the Cetamine^®-film has been established in the entire system both water and dry steam stages. This demonstrates that this technology can be used to protect all components in water/steam cycles, including areas that could not be preserved by conventional lay-up methods.

The Cetamine^® Wipe Test is an easy to apply tool which enables operators to verify film formation on the water/steam cycle surfaces during inspections [3].  Outage inspections showed that the HRSG and LP steam turbine internal surfaces remained clean and free of corrosion. Cetamine^® technology has enabled plant preservation to be significantly improved without affecting unit availability or start-up times.

References

[1] Technical Guidance Document: Application of Film Forming Amines in Fossil, Combined Cycle, and Biomass Power Plants, 2019. International Association for the Properties of Water and Steam, IAPWS TGD8-16, available from http://www.iapws.org

[2] Technical Guidance Document: Application of Film Forming Substances in Industrial Steam Generators, 2019. International Association for the Properties of Water and Steam, IAPWS TGD11-19, available from http://www.iapws.org

[3] Hater, W., Smith. B., McCann, P., de Bache, A., PowerPlant Chemistry 2017, 19(3), 129-140

[4] Allard, B., Chakraborti, S., Svensk Papperstidning 1983, 86(18), R 186

[5] Hater, W., Rudschützky, N., Olivet, D., PowerPlant Chemistry 2009, 11(2), 90

[6] Kolander, B., de Bache, A., Hater, W., VGB PowerTech 2012 92(8), 69

[7] van Lier, R., Gerards, M., Savelokoul, J., VGB PowerTech 2012, 92(8), 84

[8] Hook, B., Hater, W., de Bache, A., PowerPlant Chemistry 2015, 17(5), 283

[9] Hater, W., de Bache, A., Petrick, T., PowerPlant Chemistry 2014, 16(5), 284

[10] Wagner, R., Czempik, E., VGB PowerTech 2014, 94(3), 48

[11] Topp, H., Hater, W., de Bache, A., zum Kolk, C., PowerPlant Chemistry 2012, 14(1), 38

The state of Georgia could dramatically reduce its greenhouse gas emissions, while creating new jobs and a healthier public, if more of its energy-intensive industries and commercial buildings were to utilize combined heat and power (CHP), according to the latest research from Georgia Tech’s School of Public Policy.

The paper, digitally available now and in print on December 15 in the journal Applied Energy, finds that CHP – or cogeneration – could measurably reduce Georgia’s carbon footprint while creating green jobs. Georgia ranks 8^th among all 50 states for total net electricity generation and 11^th for total carbon dioxide emissions,  according to data from the U.S. Energy Information Administration.

“There is an enormous opportunity for CHP to save industries money and make them more competitive, while at the same time reducing air pollution, creating jobs and enhancing public health,” said principal investigator Marilyn Brown, Regents and Brook Byers professor of Sustainable Systems at Georgia Tech’s School of Public Policy.

Benefiting the Environment, Economy, and Public Health

The research finds that if Georgia added CHP systems to the 9,374 sites that are suitable for cogeneration, it could reduce carbon emissions in Georgia by 13%. Bringing CHP to just 34 of Georgia’s industrial plants, each with 25 MW of electricity capacity, could reduce greenhouse gas emissions by 2%.

The study authors, using modeling tools they developed, note that this “achievable” level of CHP adoption could add 2,000 jobs to the state; full deployment could support 13,000 new jobs.

According to Brown, CHP systems can be 85% to 90% efficient, compared with 45% to 60% efficiency of traditional heat and power systems. CHP has advantages over renewable electricity from solar and wind, which only offers intermittent power.

CHP technologies co-produce electricity useful for heat and cooling, resulting in ultra-high system efficiencies, cleaner air, and more affordable energy. Georgia industries that would profit from CHP include chemical, textile, pulp and paper, and food production. Large commercial buildings, campuses, and military bases also could benefit from CHP. By utilizing both electricity and heat from a single source onsite, the energy system if more reliable, resilient, and efficient.   

CHP can meet the same needs at higher efficiency using less overall energy, while reducing peak demand on a region’s utility-operated power grid, Brown explained. In addition, if there is an outage or disruption in a community’s power grid, companies with their own onsite electricity sources can continue to have power.

Calculating CHP Costs and Benefits per Plant  

The research used a database of every Georgia industrial site to determine which facilitates operated or could operate a CHP system. They then identified the appropriate type of CHP system for plants without one.  To help assess if a CHP system was a financially sound investment, they developed a model to estimate the benefits and costs of each CHP system, factoring in the cost to install the equipment, operations and maintenance, fuel expenses, and financing.

The result was an estimated “net present value” of each system that reflected the present value of future costs and benefits, Brown explained.

The paper also used data analytics to predict economic and health benefits of CHP for Georgians. Plants converting to cogeneration could boost the state’s clean energy workforce by 2,000 to 13,000 depending on how widely it’s adopted, Brown said. Currently, the state has about 2,600 jobs in electric vehicle manufacturing and less than 5,000 in the solar industry, according to the 11^th Annual National Solar Jobs Census 2020.

In addition to job growth, CHP adoption could lead to dramatic health benefits for the state’s more vulnerable residents, Brown emphasized. “We’re displacing more polluting electricity when companies generate their own from waste heat,” she noted.

The study estimates nearly $150 million in reduced health costs and ecological damages in 2030 in the “achievable” scenario for CHP, with nearly $1 billion in health and ecological benefits if every Georgia plant identified in the study adopted CHP.

“The public health improvements are gigantic — that’s a lot of lives saved, as well as childhood asthma and heart problems avoided,” Brown said.

Georgia Tech’s research was sponsored by Drawdown Georgia, a statewide initiative focused on scaling market-ready, high-impact climate solutions in Georgia this decade. The organization has identified a roadmap of 20 solutions, including electricity solutions such as CHP.

The impact of CHP could be dramatic considering that electricity generation accounts for nearly 37% of Georgia’s energy-related carbon dioxide emissions, according to findings Brown and other researchers published earlier this year in the journal, Environmental Management.

Identifying Ideal CHP Sites

Georgia Tech researchers identified numerous different industrial sites in Georgia that could use combined heat and power. Ideal locations include established universities or military bases, and large industrial sites such as paper making, chemical sites, and food processing facilities. Georgia’s number-one industry is agriculture, with chemicals and wood products among the state’s top manufacturers.

“I find Georgia’s potential to take advantage of existing industrial and commercial facilities to build CHP plants very interesting,” said study co-author Valentina Sanmiguel, a 2020 master’s graduate of the School of Public Policy in sustainable energy and environmental management. “I hope both industries and policymakers in Georgia realize the benefits that cogeneration has on the environment, the economy and society and take action to implement CHP in the state at a greater scale.”

Dissecting Hurdles to Adoption

Despite the advantages of CHP, there remains hurdles to its adoption  – for one, establishing these facilities is capital-intensive, ranging from tens of millions for a campus CHP plant to hundreds of millions for a large plant at an industrial site. Once built, these facilities require their own workforce to operate, explained Brown.

“The cost-competitiveness of CHP systems depends significantly on two factors – whether they are customer or utility-owned, and the type of rate tariff they operate under,” said Brown.

In the paper, Georgia Tech cited three ways to improve the business case for CHP: clean energy portfolio standards, regulatory reform, and financial incentives such as tax credits.

Those approaches have worked well in North Carolina, noted Isaac Panzarella, director of the Department of Energy Southeast CHP Technical Assistance Partnership, and the assistant director for Technical Services for the North Carolina’s Clean Energy Technology Center at North Carolina State University. North Carolina State University, where Panzarella is based, recently installed its second CHP facility on campus.

North Carolina, he added,  has a policy that supports the use of renewable energy. Along with solar and wind,  North Carolina embraced converting waste from swine and poultry-feeding operations into renewable energy.  

“It’s taken a long time, but finally there are more and more of these digester or biomass operations, using CHP to generate electricity and thermal energy from those waste resources,” he said.

While Georgia Tech is not yet operating a CHP system, the Campus Sustainability Committee is currently examining options for lessening their energy footprint.

“Georgia Tech seeks to leverage Dr. Brown’s important research, and the deep faculty expertise at Georgia Tech in climate solutions, as we advance the development of a campus-wide Carbon Neutrality Plan and Campus Master Plan in 2022,” said Anne Rogers, associate director, Office of Campus Sustainability. “The Campus Master and Carbon Neutrality Plan will provide a roadmap to implementing sustainable infrastructure solutions to advance Georgia Tech’s strategic goals.”

Brown emphasized that Georgia utilities should get behind cogeneration projects to help the state reduce its carbon footprint.

Another hurdle is the relatively low electric rates in the Southeast, which provide less of an opportunity to achieve a reasonable payback on those systems. Georgia’s industries that wish to be competitive globally need to look at CHP considering that the rest of the world is embracing renewable and recycled energy at a faster rate than the U.S., Brown noted.

“In industries where CHP is well understood, and there are solidly established businesses, it’s a great investment and  a smart way to keep jobs in the community, while being good for the environment. The hurdles are not about technology; they are all about policies and business models,” she concluded.

Automotive OEM supplier Raloy Lubricantes selected the mtu Series 500 gen-sets for powering operations at the Santiago Tianquistenco facility. In addition to the electricity used at the plant, heat from exhaust will warm up thermal oil for mixing processes.

At the same time, thermal energy from jacket heat will be recaptured and run through an absorption chiller to produce chilled water for cooling plastic bottles manufactured in Raloy’s sister company, Thermfluidos.

The new Series 500 generator set at Raloy’s manufacturing plant is expected to be commissioned by April 2022.

“It is not common to work with a customer that is ready to embrace new technology and lead an industry, as it has been with Raloy,” said Javier Gonzalez, Senior Manager of Gas System Sales, Americas, at Rolls-Royce Power Systems. “Raloy knows and trusts the high quality of our products and this added with their genuine interest of developing sustainable processes, is why they decided to put them to work in their operations.”

The mtu Series 500 is the new successor to the Series 400 and reportedly improves on engine efficiency and generates 30 percent more power, according to Rolls-Royce. The system is dual fuel, available to run on either natural gas or biogas, and can be ready for a blend of up to 10 percent carbon-free hydrogen.

Raloy Lubricantes makes motor oil and other automotive and generator-set lubricants. The company is 100-percent Mexican-owned and employs more than 200 people.

MTU became part of Rolls-Royce when the latter acquired Tognum Corp. in 2011.

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On-site power, hydrogen and CHP all are topics of content sessions happening at POWERGEN International live Jan. 26-28 in Dallas. Registration is now open.

B&W Renewables was awarded the $35 million-plus contract by ESANI A/S, Greenland’s national waste management company. The facilities will be built near the cities of Nuuk and Sisimiut and provide district heating for residents and businesses.

Utilizing waste from existing landfills and convert it to energy reduce net methane emissions by a considerable degree. Climate experts say that methane is multiple times more harmful as a greenhouse gas than carbon emissions, according to reports.

“Waste-to-energy technologies are some of the most effective solutions for combatting climate change by reducing methane emissions from landfills and can be combined with carbon capture technologies to further reduce greenhouse gas emissions,” said Jimmy Morgan, B&W Chief Operating Officer. “Using B&W Renewable’s proven waste-to-energy and environmental technologies, operators can generate clean energy while reducing the amount of trash in landfills, protecting the air and water from emissions and runoff, and fighting climate change. B&W Renewable’s technology also provides a fully sustainable solution, now and in the future, to process municipal waste while helping to protect Greenland’s pristine and fragile arctic environment.”

Waste-to-energy projects will be part of the content offered at POWERGEN this January

B&W Renewable’s project scope includes supplying advanced Vølund DynaGrate combustion grates as well as boilers, waste feeding systems, a Vølund DynaDischarger ash extractor, GMAB flu gas cleaning systems and advanced control and monitoring systems.

The company also will install and commission the facilities. The waste-to-energy plants are scheduled for completion in 2023 and 2024.

B&W has participated in more than 100 waste-to-energy power projects worldwide. Many of those have been in Scandinavia, which is evidence of island nations concerned about land scarcity and costs for dumps, not to mention the environmental impacts.

In the U.S., the federal Energy Information Administration estimated that only about 12 percent of the nearly 300 million tons of municipal solid waste produced in the U.S. was burned in WTE plants. In 2019, 67 U.S. power plants generated about 13 billion kWh of electricity from burning nearly 25 million tons of combustible solid waste, according to the EIA.

Boortmalt, a malting company, has tasked Wärtsilä with converting its Punta Alvear dual-fuel plant to a gas-fueled system.

This will help the malting firm to lower its production and operating costs and aligns with the company’s sustainable development strategy, which aims to reduce energy consumption and carbon emissions by 50% by 2030.

The upgrade is expected to increase the plant’s efficiency and power output, and the process reduces Bootmalt’s malt production expenses. The project is also expected to help reduce the plant’s carbon footprint.

Jorge Alcaide, Wärtsilä Energy Business Director, Americas, Region South, added: “By carrying out this gas conversion project, we are in effect future-proofing the plant’s operational performance, since it will facilitate the future integration of energy from renewable sources, such as wind and solar. In the meantime, it will reduce the need for power from the grid, thereby lowering costs.”

Gas conversions will also enable the transition to future synthetic fuels, such as hydrogen.

The city of Lakeland’s municipal utility has contracted German-based MAN to supply six 18V51/60G reciprocating internal combustion engines for the new McIntosh power plant. MAN is committed to delivering the engines and balance of plant equipment to the 120-MW plant by July 2022.

“We are very proud that Lakeland Electric entrusts us with this lighthouse project, which represents a significant milestone for our power segment here in the U.S.,” Wayne Jones, chief sales officer and executive energy board member with MAN Energy Solutions, said in a statement.

“Our top-of-the-line 18V51/60 reciprocating gas engine, combined with a very sophisticated, heat-recovery system, specifically designed to support the plant’s stand-by operation, perfectly matches Lakeland Electric’s stated commitment to safely provide its customers with affordable, highly dependable and sustainable electric-services,” he added.

Both Lakeland Electric and MAN are committing to building the plant and making it operational as soon as safely possible.

MAN also is contracted with a 10-year service agreement for the plant.

The MAN 51/60G gas engine has a 50-percent efficiency rating in single cycle and up to 95 percent in cogeneration. The Lakeland plant will be a stand-by operation, so the engine’s quick startup time is advantageous to the city’s power needs.