B&W is working with NorthStar Clean Energy to finalize the full contract, which includes a FEED study for the project. B&W can now begin detailed design and procurement work, with full notice to proceed expected in the fourth quarter of 2024.

When the conversion project is complete, the 73 MW Filer City power plant will use biomass as fuel – coupled with B&W’s SolveBright post-combustion CO₂ capture technology. The scrubbing system absorbs CO2 directly from the plant’s flue gas using a regenerable solvent that is then recycled for re-use.

B&W’s full contract scope of the conversion project is expected to include engineering, design and delivery of equipment to convert the plant to use biomass fuel and add carbon capture technology. Babcock & Wilcox Construction Co., LLC, will manage the construction and mechanical scope of the project.

The Filer City plant is jointly owned by Texas-based Tondu Corp and NorthStar (a subsidiary of CMS Energy Corporation). The plant generates steam with two non-reheat Foster Wheeler traveling grate spreader stoker boilers. Pollutants are removed from the flue gas stream using two flue gas dry scrubbers and two baghouses.

The plant began commercial operation in 1990. The remaining coal unit is expected to retire by June 2025, according to the U.S. Energy Information Administration (EIA).

Under the agreement, B&W has received limited notice to proceed (LNTP) for the project. Notice to proceed for the full contract is expected in the fourth quarter of 2024, the company said.

B&W will convert the currently unspecified plant’s two coal-fired boilers – totaling more than 1,000 MW – to use natural gas fuel. B&W’s full scope would include the design and installation of new burners, air systems, fans and other equipment necessary to implement the fuel switch.

“Utilities across North America and throughout the world are evaluating options to extend the life of their thermal power generating assets,” said Chris Riker, Senior Vice President, B&W Thermal. “Replacing coal or oil with cleaner-burning fuels like natural gas, biofuels or hydrogen is often a cost-effective way for plant owners to lower emissions while maintaining reliable power generation capacity.”

Babcock & Wilcox said it will begin engineering and design work under the LNTP immediately with support from its affiliate, FPS. Babcock & Wilcox Construction will perform the construction portion of the project under an intercompany agreement when a full notice to proceed is received.  

This order allows NV Energy to move forward with ceasing coal operations at North Valmy Generating Station and transition to a natural gas-fired plant by the end of 2025. North Valmy is the company’s final coal plant in its portfolio. The two-unit, 522 MW facility is jointly owned by NV Energy and Idaho Power.

Unit 1, which went into service in 1981, produces 254 MW with a Babcock & Wilcox Boiler and Westinghouse turbine/generator. Unit 2 came online in 1985 and generates 268 MW with a Foster Wheeler Boiler and GE turbine/generator. Coal for the plant is shipped via railroad from various mines in Utah, Wyoming and Colorado.

PUCN also approved NV Energy’s plan to build additional transmission infrastructure to support continued growth in the state, including in the Apex area in the city of North Las Vegas – a growing center of economic development in Southern Nevada.

NV Energy also received conditional approval to begin developing the Sierra Solar project, a 400 MW solar site with a four-hour battery storage system in Northern Nevada.

While regulators approved the project, they expressed concern about its cost and said there would need to be ratepayer protections in the case of cost overruns.

The commission capped Sierra Solar’s construction costs at $1.5 billion and said NV Energy would need to pay credits to customers if the project doesn’t meet its completion goal of April 2027. Sierra Solar would be “the most expensive project ever proposed to be built or owned by NV Energy.”

The state of Nevada is aiming for a renewable portfolio of 50% by 2030 and 100% by 2050.

The plant design would leverage B&W’s BrightLoop technology to produce clean energy from coal, with the CO₂ emissions sequestered or put to use. The company said the plant would be capable of producing 15 tons of clean hydrogen per day utilizing the BrightLoop process.

B&W said its BrightLoop technology is a chemical looping technology that can produce hydrogen from nearly any feedstock, including solid fuels such as waste wood and other types of biomass. The company said its process can also produce an isolated CO2 stream for capture, use or sequestration, as well as nitrogen that can be combined with hydrogen to create ammonia.

The process uses a proprietary, regenerable particle and has been demonstrated to effectively separate CO₂ while producing hydrogen, steam and/or syngas.

The 90 MW Neil Simpson II Plant went online in 1995.

Each project aims to demonstrate integrated carbon capture, transport and storage technologies and infrastructure that can be deployed at power plants. However, the technologies and environments are different. In this case, three novel solvents would be demonstrated and combined with carbon transport and storage in different geological settings.

Funding for the projects – in California, North Dakota and Texas – comes from the Bipartisan Infrastructure Law signed in 2021.

The Biden Administration believes the large-scale deployment of carbon capture, transport and storage infrastructure could play a vital role in reducing emissions in the U.S. For more than a decade the federal government has provided financial support to boost the development and use of technologies for capturing CO2 emissions.

But in the last couple of years, legislation has significantly increased annual funding for these efforts. The Bipartisan Infrastructure Law, formally known as the Infrastructure Investment and Jobs Act, provides $8.2 billion in advance appropriations for CCS programs over the 2022–2026 period, according to a recent Congressional Budget Office (CBO) report.

Proponents say carbon capture could have a huge role in reducing emissions, while many environmentalists note the technology is far from scale and argue that focusing on it distracts from renewable energy solutions.

According to the CBO report, 15 CCS facilities are currently operating in the U.S. Together, they have the capacity to capture 0.4 percent of the nation’s total annual CO2 emissions.

The report notes an additional 121 CCS facilities are under construction or in development. If all were completed, they would increase the nation’s CCS capacity to 3 percent of current annual CO2 emissions.

Here are the three projects selected for award negotiation: 

Baytown Carbon Capture and Storage Project

The Baytown Carbon Capture and Storage (CCS) Project plans to capture CO2 from the Baytown Energy Center, a natural gas combined-cycle plant in Baytown, Texas. The project would use Shell’s CANSOLV solvent to capture CO2, which would be transported through new and existing pipelines and sequestered in storage sites on the Gulf Coast.

Calpine is serving as the lead for the Baytown CCS project and Covestro, an industrial manufacturer of plastics, will serve as the project’s primary power off-taker. Calpine expects the project will capture up to 2 million metric tons of CO2 per year

The project is also considering the use of greywater cooling to minimize freshwater consumption by reusing wastewater, according to DOE.

The 896 MW Baytown Energy Center provides steam and power to the adjacent Covestro chemicals manufacturing facility as well as power to the Texas electric grid.

Calpine said adding post-combustion carbon capture equipment to this facility would reduce the carbon dioxide emissions intensity of two of its three combustion turbines at a design capture rate of 95%.

Calpine has a total of 11 CCS projects in its pipeline.  

In July 2022 the company unveiled a carbon capture demonstration pilot project at its combined-cycle plant in Pittsburg, California. The CCS project at Calpine’s Los Medanos Energy Center will use a chemical solvent developed by ION Clean Energy to bind with carbon dioxide in the plant’s flue gas.

In the case of this pilot, the project will not store the captured carbon and instead release it back into atmosphere. However, in future plants, the CO2 could be pumped and stored underground.

Project Tundra

Project Tundra is a carbon capture system to be developed adjacent to the Milton R. Young Station, a coal-fired plant near Center, North Dakota. The project plans to use Mitsubishi Heavy Industries’ KS-21 solvent to capture CO2, which would be permanently stored in saline geologic formations beneath and surrounding the power plant. The storage site has already been approved for a Class VI well permit.

Project Tundra is being developed by project sponsors which include Minnkota Power Cooperative and TC Energy. The project is expected to capture an annual average of 4 million metric tons of CO2.

Minnkota said it plans to retrofit the coal-fired plant’s 430 MW Unit 2 to capture up to 90% of its CO2 emissions. Unit 2 is a cyclone-fired wet bottom boiler from Babcock & Wilcox.

MHI will collaborate on the CO2 capture facility with Kiewit, which will construct the project.

Project Tundra is receiving up to $350 million.

Sutter Decarbonization Project

The Sutter Decarbonization Project plans to demonstrate and deploy a carbon capture system at the Sutter Energy Center, a 550 MW combined-cycle plant near Yuba City, California. The project would use ION’s ICE-21 solvent to capture the CO2 and sequester it permanently more than a half a mile underground in saline geologic formations.

This project would be the first in the world to deploy an air-cooling system at a carbon capture facility, which will eliminate the use of cooling water and significantly minimize freshwater usage—a critical concern of the local community.

The Sutter Decarbonization Project will receive up to $270 million. Sutter CCUS (a subsidiary of Calpine) is developing the project.  

Funding applicants were required to submit Community Benefits Plans, intended to spur community and labor engagement in carbon management technologies while addressing environmental burdens in partnership with surrounding communities.

DOE estimates that reaching the current administration’s plan for a net-zero emissions economy would require capturing and storing between 400 million and 1.8 billion metric tons of CO2 annually by 2050. The power sector accounts for more than a quarter of U.S. carbon emissions.

According to the CBO report, the future adoption of carbon capture and storage depends on a variety of factors, like changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions and the development of clean energy technologies that could affect the demand for CCS.

DOE said it will host a national briefing on Dec. 18 to share more information about the selected projects. A period of stakeholder engagement will then take place starting in January. 

B&W will manage and conduct maintenance for the three unit, 490 MW oil-fired plant’s boilers and boiler auxiliary equipment, including annual standard maintenance as well as capital projects for the plant’s units over the next three years.

The contract includes an option for additional work, if necessary.

Located in the Town of Holyrood and bordering Conception Bay South, the Holyrood Thermal Generating Station burns 0.7% sulphur fuel.

The plant is a major source of Newfoundland and Labrador’s energy, generating between 15% and 25% of the island’s electricity every year. If needed, the Holyrood plant has the capacity to generate up to 40% of the island’s annual energy needs.

B&W said its BrightLoop technology is a chemical looping technology that can produce hydrogen from nearly any feedstock, including solid fuels such as waste wood and other types of biomass. The company said its process also produces an isolated CO2 stream for capture, use or sequestration, as well as nitrogen that can be combined with hydrogen to create ammonia.

Babcock & Wilcox also said it reached an agreement for General Hydrogen, a CGI Gases subsidiary, to purchase hydrogen from the facility. General Hydrogen would purchase and transport off-site up to 15 tons of hydrogen per day, according to the terms of the agreement.

CGI Gases would purchase and transport compressed carbon dioxide (CO2) captured during the process.

Joe Buckler, B&W Senior Vice President of Clean Energy, said the hydrogen could be used in power production, industrial processes or as transportation fuel.

Project Tundra is designed to capture up to four million metric tons of CO2 annually from the coal-fired plant. Minnkota said it plans to retrofit the 430 MW Unit 2 to capture up to 90% of its CO2 emissions. Unit 2 is a cyclone-fired wet bottom boiler from Babcock & Wilcox.

Minnkota said the CO2 will be stored more than a mile underground in geologic formations. Minnkota said it currently has the largest fully permitted CO2 storage facility in the U.S. and is pursuing additional CO2 storage opportunities near the Milton R. Young plant.

In late July, Minnkota lined up a tentative $150 million loan to advance the project. The loan was authorized by the state’s Clean Sustainable Energy Authority (CSEA) and is in addition to an earlier $100 million CSEA loan approved in 2022. Project Tundra partners also applied for a $350 million grant through the  Department of Energy’s Carbon Capture Demonstration Projects Program.

Closing on financing and the notice to move forward with construction of Project Tundra are expected in early 2024. The project remains subject to closing on financing and a final investment decision by each of the project entities

In June, the co-op announced project agreements with TC Energy, Mitsubishi Heavy Industries (MHI) and Kiewit.

TC Energy will lead commercialization activities, including qualifying for federal 45Q tax credits. Expanded incentives under the Inflation Reduction Act (IRA) are expected to further bring down the cost of CCS, providing $85 for every ton of captured CO2 through the 45Q tax credit, up from $50 a ton.

The project is expected use MHI’s CO2 capture technology “Advanced KM CDR Process” with new solvent “KS-21.” According to EPA filings, this process is similar to an amine-based solvent process but uses a proprietary solvent and is optimized for CO2 capture from a coal-fired generator’s flue gas.

MHI will collaborate on the CO2 capture facility with Kiewit, which will construct the project.

When the project is complete, the 75 MW TES Filer City Station plant would use biomass to generate power and be equipped with B&W’s SolveBright post-combustion CO2 scrubbing process. The process would remove CO2 for sequestration or utilization.

The project is partially funded by the U.S. Department of Energy. Babcock & Wilcox will manage construction and mechanical scope of the study and commercial phase.

The Filer City plant is jointly owned by NorthStar Clean Energy and Houston, Texas-based Tondu Corp.

The electricity generated at the plant is sold to Consumers Energy, and the steam is sold to the Packaging Corporation of America facility adjacent to the site.

The plant generates steam with two non-reheat Foster Wheeler traveling grate spreader stoker boilers. Pollutants are removed from the flue gas stream using two flue gas dry scrubbers and two baghouses.

TES Filer City Station began commercial operation in 1990.

It is common knowledge that many coal-fired power plants in the United States and other parts
of the world are being retired in response to concerns about climate change. However, in some
countries coal plants still provide a substantial portion of electrical needs. And, if carbon capture
and sequestration (CCS) continues to move forward, some coal plants may be with us for years
to come.

Regardless of one’s view on coal plant acceptability, a critical aspect continues to be
limiting sulfur dioxide (SO₂) emissions. A technology to do so that has been around for decades
is wet-limestone scrubbing. But a question that may not be understood by many is: “How can
this natural mineral, which is a hugely important construction material and has very low
solubility in water, serve as a scrubbing reagent in a power plant?” This article examines the
unique chemistry behind this application.

Limestone – The material

Limestone is a common deposit in many global locations, including the U.S. The principal
component of limestone is calcium carbonate (CaCO₃), and some stones may contain 95% or
greater CaCO₃. Second in abundance is magnesium carbonate (MgCO₃), which often constitutes
only a small percentage of the total carbonate, although some formations may include dolomite
that has an equal molecular mixture of calcium and magnesium carbonate (MgCO₃·CaCO₃).

Dolomite is rather unreactive in scrubbers. Lower quality limestones contain inert minerals such
as silicates in the form of quartz, shale, or clay. Some stones have minor concentrations of iron
and/or manganese carbonate (FeCO₃ and MnCO₃), which can influence some aspects of scrubber
operation.

A look at natural limestone/water chemistry

An examination of limestone’s reactivity in natural waters provides a good foundation (pardon
the pun) for understanding why it can work well in scrubbers. Consider the lab experiment of
placing a limestone sample in pure water with a pH of 7.0. Limestone is only slightly soluble in
water.

CaCO₃ ⇌ Ca²⁺_(aq) + CO3^2-_(aq) Eq. 1

K_sp (25^o C) = [Ca²⁺] * [CO₃^2-] = 4.6 * 10^-9 (mol/L)² Eq. 2

Straightforward calculations indicate that the initial CaCO₃ solubility per Equation 2 is only
6.8 * 10^-5 moles per liter (M), equivalent to just under 7 mg/L.

However, carbonate is a relatively strong base, and it will react with water as follows:

CO₃^2- + H₂O ⇌ HCO₃^– + OH^– Eq. 3

This influence drives the reaction shown in Equation 1 somewhat to the right, where the overall
reaction can be written as:

CaCO₃ (s) + H₂O ⇌ Ca²⁺ + HCO₃^– + OH^– Eq. 4

The CaCO₃ solubility (25^o C) rises to 9.9 * 10^-5 M (~ 10 mg/L) per this effect, (1) which
represents a roughly 1/3 increase in solubility, but is still very slight.

However, this chemistry leaves two important unanswered questions.

• If CaCO₃ solubility is so low, why do many natural water supplies have alkalinity
concentrations in the double to triple digits mg/L range?
• How could such a material be effective in a flue gas scrubber?

The answers are directly related, as we shall now explore.

In surface waters, carbon dioxide from the atmosphere dissolves as follows:

CO₂ + H₂O ⇌ H₂CO₃ Eq. 5

The amount that enters solution can be calculated from Henry’s Law:

K_H = [H₂CO₃ (aq)]/P = 3.4 * 10^-2 mol/L · atm (25^oC), where Eq. 6
P = the partial pressure of CO₂

The current atmospheric concentration of CO₂ is near 420 ppm, which calculates to 0.00042 atm.
So, for neutral water the H₂CO₃ concentration is around 1.43 * 10^-5 M, which is not very large.

Research suggests that most solvated carbon dioxide remains as CO₂ and does not dissociate.
However, a small amount does, per the following reaction:

H₂CO₃ ⇌ HCO₃^– + H⁺ Eq. 7

The acidity this dissociation generates can be calculated from the following equation.

K_a = [HCO₃^–] * [H⁺]/[H₂CO₃] = 4.5 * 10^-7 mol/L (25^oC) Eq. 8

The very small value for K_a shows that H₂CO₃ (carbonic acid) is a weak acid. Per Equations 6
and 8, the acid concentration in neutral water calculates to 2.32 * 10^-6 M, equivalent to a pH of
about 5.6. (A point worth noting here is that because H₂CO₃ is a weak acid, if few buffering ions
are present in the water, an external acidic influence can significantly lower pH. The classic case
is acid rain, which plagued the northeastern U.S. before power plants began installing sulfur
dioxide and nitrogen oxide (NO_x) treatment equipment.)

This is where the chemistry becomes more interesting. Even though calcium carbonate is only
slightly soluble in neutral waters, and carbonic acid has a low dissociation constant, observe
again that the limestone dissolution produces hydroxyl ions (OH^–) and the carbonic acid
produces hydrogen ions (correct is hydronium ions, H₃O⁺ or multiples thereof, but we can ignore
that concept in this discussion), where the following reaction represents a simplified combination
of Equations 4 and 7.

H⁺ + OH^– –> H₂O Eq. 9

The acid-base neutralization drives both Reactions 4 and 7 to the right and causes a 35-fold
increase in CO2 dissolution and a four-fold increase in the calcium concentration. (1) This
explains why many natural waters have a significant bicarbonate alkalinity concentration and a
mildly basic pH range of 7 to 8.

OK, so now you may be asking, what does all this chemistry have to do with wet-limestone
scrubbers?

Wet limestone scrubbing

Briefly reconsider the concepts shown in Equations 5, 6 and 8. The following example uses data
from Reference 2 that has a table outlining the theoretical combustion product calculations for a
steam-generating unit burning 1.5% sulfur coal. The program calculates an SO₂ concentration in
the flue gas of around 0.11%, which is roughly three times greater than the atmospheric CO₂ concentration as described above. The reaction of SO₂ with water is analogous to Equations 5 and 7.

SO₂ + H₂O ⇌ H₂SO₃ Eq. 10

H₂SO₃ ⇌ HSO₃^– + H⁺ Eq. 11

But, the K_a for Equation 11 is 1.7 * 10^-2, which is quite higher than carbonic acid.

So, the driving force for CaCO₃ dissolution and reactivity is much greater in sulfurous acid
solutions than carbonic acid.

Now we can examine how this chemistry plays out in a scrubber. Figure 1 outlines a general
flow diagram of a spray-tower, wet-limestone scrubber.

The general equation for the initial scrubber reaction is:

C_aCO₃ + 2H⁺ + SO₃^-2 –> Ca⁺² + SO₃^-2 + H₂O + CO₂↑ Eq. 12

In the absence of any other reactants, calcium and sulfite ions will precipitate as a hemihydrate,
with water included in the crystal lattice of the byproduct.

Ca⁺² + SO₃^-2 + ½H₂O –> CaSO₃·½H₂O↓ Eq. 13

Proper operation of a scrubber is dependent upon the efficiency of the above-listed reactions,
where pH control via accurate reagent feed is critical. Many wet-limestone scrubbers operate at
a solution pH of around 5.6 to 5.8. A too-acidic solution inhibits SO₂ transfer from gas to liquid,
while an excessively basic slurry (pH > 6.0) indicates overfeed of limestone.

Oxygen in the flue gas greatly influences chemistry. Aqueous bisulfite and sulfite ions react
with oxygen to produce sulfate ions (SO₄^-2).

2SO₃^-2 + O₂ –> 2SO₄^-2 Eq. 14

Approximately the first 15 mole percent of sulfate ions co-precipitates with sulfite to form
calcium sulfite-sulfate hemihydrate [(0.85CaSO₃·0.15CaSO₄)·½H₂O]. Any sulfate above the 15
percent mole ratio precipitates with calcium as gypsum (CaSO₄·2H₂O).

Ca⁺² + SO4^-2 + 2H₂O –> CaSO₄·2H₂O↓ Eq. 15

Calcium sulfite-sulfate hemihydrate is a soft material that tends to retain water. It has little value
as a chemical commodity. For this reason, many scrubbers are (or were) equipped with forced-air oxidation systems to introduce additional oxygen to the scrubber slurry. A properly designed
oxidation system will convert all of the sulfite to gypsum, which forms a cake-like material when
subjected to vacuum filtration.

In many cases, 85 to 90% of the free moisture in gypsum can be extracted by this relatively simple mechanical process. High-purity, dried synthetic gypsum was once a favorite material of wallboard manufacturers.

Limestone utilization and scrubbing efficiency are critical issues. Factors that influence scrubber
performance include:

• Limestone grind size
• Limestone purity, especially with regard to CaCO₃ concentration
• Performance of slurry separation devices
• Spray nozzle efficiency
• Adequate forced-air oxidation efficiency

Let’s briefly review these concepts.

Limestone grind size

Grind size is quite important. This author first cut his teeth working with a scrubber that had just
been commissioned a few months before. Grinding was performed in wet ball mills. The stone
was high purity with a typical CaCO₃ concentration of 96-97%. The initial grinding specification
called for 70% ground particles passing through a 200-mesh screen as analyzed in the lab. But
even with this high-purity stone, it quickly became apparent that the initial grind size was too
coarse and did not allow sufficient reaction. The grind was adjusted over time to an eventual
specification of 90% through a 325-mesh screen. Following the grinding adjustments, the
limestone utilization increased to 98% or thereabouts. (3)

Limestone purity and reactivity

The author was also part of a team that evaluated several limestones on a full-scale basis over a
two-year period to see if materials and transportation costs could be lowered from those of the
high-purity stone mentioned above, which was delivered form over 100 miles away. Some of
the test stones had a total carbonate alkalinity of greater than 90%, but where a significant
portion was dolomite. Others had CaCO₃ concentrations in an 80-90% range, with the balance
made up of inert materials. In all cases, the lesser-quality stones performed very poorly and were
abandoned. Limestone utilization decreased dramatically, and some materials caused a
significant increase in scale formation. Furthermore, the much higher concentrations of inert
materials negatively impacted slurry-separating hydrocyclones.

The cyclone manufacturer was brought in to adjust the vortex finders of the units to improve
particle separation, but the results were marginal at best.

In another test, a small but significant concentration of FeCO₃ in the stone converted to very fine
iron oxide particles which plugged the cloth on the rotary vacuum drum filters.

Spray nozzle efficiency

Spraying technology has advanced immensely from early designs, and open spray towers are
now normal. Modern towers can potentially remove 98% or more of the entering SO₂.
However, the spray nozzle grid must be designed to provide uniform coverage and prevent
channeling of the flue gas. A common problem in early scrubbers was nozzle plugging from
pieces of internal lining material that had broken loose in slurry circulating lines. This author
clearly recalls pulling pieces of fractured rubber liner from spray nozzles during periodic
inspections.

Forced-air oxidation efficiency

As has been noted, the handling characteristics of fully oxidized slurry are much better than for
slurry that is only partially oxidized. Accordingly, oxidation air system design and operation are
critical. Under-sizing of the oxidation air system during design is a noted problem, while at
other times the small bore-holes in oxidation air laterals can become encrusted with scale. The
analytical technique outlined in Reference 3 can quickly detect loss of oxidation efficiency.

Conclusion

Gone is the heyday of massive scrubber installations at coal-fired power plants. However, this
technology still has value in some applications, and perhaps future CCS projects will require wet
scrubbing of SO₂. Limestone is a plentiful and inexpensive material that can remove nearly all
SO₂ from a flue gas stream. But wet scrubbing raises issues about byproduct and wastewater
disposal, particularly in regard to discharge of heavy metals and metalloids. The author and two
colleagues reported on an emerging selenium capture (along with other impurities) method in a
previous Power Engineering article. (4) Concerns about liquid discharge and disposal have had
a strong influence at some plants, where dry scrubbing (with more expensive lime reagent) was
chosen vs wet scrubbing. Even so, limestone still plays a critical role, as it is the base material
for the scrubbing reagent.

References

1. C. Baird, Environmental Chemistry, Second Edition, W.H. Freeman and Company, New
   York, NY, 1999.
2. Kitto, J.B., and Stultz, S.C., Eds., Steam, its generation and use, 41st Edition, the Babcock
   & Wilcox Company, Barberton, Ohio, 2005.
3. B. Buecker, “Wet Limestone FGD Solids Analysis by Thermogravimetry”; proceedings
   of the 24th Annual Electric Utility Chemistry Workshop, May 11-13, 2004, Champaign,
   Illinois.
4. Djukanovic, V., Karlovich, D., and B. Buecker, “A Novel Non-Biological Process for
   Selenium Removal”; Power Engineering, March 2020.

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. 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.