Eco Material and Rainbow will capture, beneficiate, and market all of the solid-form discharged materials from Coal Creek Station, adding to their existing partnership that markets fly ash in the concrete sector, in what the two companies are calling a “fully circular” power plant.

“We expect demand for high-quality sustainable cementitious materials (SCMs) like fly ash and pozzolans to grow rapidly over the next 10 years and we are excited to work with Rainbow to provide that for the industry,” said Grant Quasha, CEO of Eco Material Technologies. “This project is the culmination of a relationship between Eco Material and Coal Creek Station on fly ash beneficial use for over 30 years, and that partnership has only grown since Rainbow’s purchase of the facility in 2022. This project marks a key turning point in the SCM market for the region.”

The project will be the first beneficiation and harvesting plant in the state of North Dakota and the second bottom ash beneficiation and harvesting project within Eco Material’s portfolio. The Coal Creek project will provide an additional 400,000 tons annually of SCMs over the next 25 years to service the rapidly growing markets in North Dakota, Minnesota, and Wisconsin. The project will also beneficiate Coal Creek’s annual production of 150,000 tons of calcium sulfite into marketable synthetic gypsum, which will be primarily marketed to the wallboard industry by Eco Material.

Rainbow purchased the 1051 MW, 2-unit station at Coal Creek in May 2022, and the plant was originally scheduled to be shut down before this purchase. However, Rainbow infused capital into the plant, including these projects, to ensure it remains operational long-term. The plant currently produces approximately 500,000 tons annually of high-quality Class F fly ash.

Materials harvested from Coal Creek Station are and will be used in concrete blends to repair and construct bridges, roads, and buildings across the region. Coal ash replacement in cement has been shown to enhance the strength, impermeability, and durability of concrete, Eco Material said.

Eco Material will also be investing in additional storage terminals across the region to ensure that no winter ash is disposed of and that customers have the materials they need for projects in the region’s shorter summer season. The beneficiation plants at Coal Creek and the new regional storage terminals are expected to be completed in 2025.

Eco Material has a portfolio of nine plants producing or under construction that represent over four million tons per annum of novel, beneficiated SCMs and Green Cement products to help decarbonize the North American concrete market.

By Brian Brigandi, Platte River Power Authority

By Nick Lumley, PE, Burns & McDonnell Engineering Co.

Heat rate is often the single most important factor in a coal-fired power plant’s economic and emissions profile. Expressed in Btu/kWh or GJ/kWh, heat rate is a measure of efficiency: the quantity of fuel burned to produce a unit of power. Heat rate is best (lowest) at rated plant load and increases as load declines, generally due to equipment being optimized for rated load operation.

In competitive power markets, units with low heat rates can profitably bid into the dispatch stack over a greater range of marginal pricing environments. Even must-run plants benefit from improved heat rates because they lead to better margins.

Minimum load is similarly important to the competitiveness of thermal plants. Low minimum load enables a plant to ‘ride though’ periods of low power demand and earn spinning reserve payments where available without accumulating damaging start-stop cycles.

Reducing heat rate is equivalent to reducing emissions and operating expenses and remains a goal of the power industry since its inception. However, the growing penetration of low-cost and prioritized variable renewable generation has made heat rate and minimum load more important than ever. Recognizing the benefit of improving these characteristics in the current market environment, Platte River Power Authority embarked on a program of improvements to the coal-fired Rawhide Unit 1 intended to reduce heat rate and minimum load.

The Rawhide Unit 1 VFD Conversion

The efficiency of rotodynamic machines, like centrifugal pumps and fans, depends on flow through the machine. For constant-speed machines, the best efficiency point is usually chosen for the flow at rated plant load, resulting in relatively poor efficiency at lower load. Conversion of constant speed machines to variable speed can offer high efficiency throughout the load range, saving megawatts of auxiliary power at low load.

Electronic variable frequency drives (VFD) are an ideal solution to convert centrifugal machines to variable speed operation. Large, medium-voltage VFDs can readily be matched to existing motors, even older non-inverter-duty motors, due to extensive, custom designed filtering. Even pumps and fans using hydraulic variable speed drives can benefit from a VFD conversion with hydraulic drive removal. Hydraulic drives are robust but their efficiency declines at lower transmitted speeds. In contrast, VFDs offer greater than 90% efficiency across the speed range and over 97% at full speed.

For the 280 MW Rawhide Unit 1, the 2x 5,000 hp boiler feedwater pumps (BFP), 2x 5,500 hp induced draft (ID) fans, and 2x 500 hp condensate pumps were found to be candidates for VFD conversion. The ID fans and BFPs had existing hydraulic drives; the condensate pumps were constant speed prior to conversion. The unit’s forced draft and primary air fans remain constant speed axial models with variable pitch vanes; variable-vane fans adapt vane pitch to flow, resulting in high intrinsic efficiency.

The conversion began with electrical engineering efforts to develop procurement specifications for the new VFDs and identify an installation location optimizing cable length and maintenance access. Siemens drives were selected for all pumps and fans and were custom designed for the electrical characteristics of each motor. No motor replacements were required. Fortunately, indoor laydown area underneath the steam turbine pedestal was available and large enough to install VFDs for each of the two BFPs and two ID fans. The smaller condensate pump VFDs were installed near the pumps (Figure 1 and Figure 2).

Removing hydraulic drives from the BFPs and ID fans constituted a fundamental redesign of the machines. Machinery modifications began with a rotordynamic study and subsequent shafting design by specialist subcontractor Electro-Mechanical Engineering Associates. The rotordynamic study involved a computational rotor model to evaluate vibration performance of candidate designs. For both the BFPs and ID fans, rigid shafts were found to have the best vibration performance (Figure 3).

During the rotordynamic analysis, it was found that the existing 3,550-rpm BFP motors, which were to be retained, had lateral critical speeds peaking at about 2,700 rpm. This critical speed is inherent to the motor’s design and cannot be removed.

To prevent operating the BFPs at damaging vibration amplitude, the shafts were designed with balance planes located along the antinodes of the lateral mode shape. Careful installation of balance weights, a specialist 3^rd party engineering and testing task, can offset some rotor imbalance and reduce vibration amplitudes. If potentially damaging vibrations were found to remain after balancing, the affected speed range could be rapidly bypassed using controls.

For the BFPs, existing severe-service recirculation valves were used to create artificial pump demand by shunting flow back to the deaerator to force speed out of the critical zone. Simply locking out certain speeds was not possible in this plant which uses BFP speed to control drum level.

Results of the VFD Conversion

Following conversion, Rawhide realized significant improvements as summarized in Table 1:

For context, heat rate improvement is 6% at minimum load and 1.5% at maximum load over pre-VFD performance. Lowering Rawhide’s full-load heat rate below 10,000 Btu/kWh was an achievement for a high-altitude subcritical unit. Rawhide has also realized improved furnace pressure and drum level control due to rapid VFD speed response.

The auxiliary load savings are a direct result of improved efficiency from VFDs, compared to hydraulic drives, and improvements in power factor. Reactive currents circulating in motors with low power factor, like induction motors at low load, dissipate real power as heat. The VFD conversion improves power factor on the auxiliary network, reducing heating. Moreover, the source of plant reactive power is the generator: better internal power factor makes more generator reactive power capability (MVARs) available to the grid.

Figure 4 shows the improvement in the power factor. Weighted mean power factor for all 6 motors could be as low as 0.70 prior to the VFD conversion. Following the project, the power factor is consistently about 0.97 across the load/speed range.

Trimming auxiliary load

Coal-fired power plants depend on large, high-power pumps and fans. These machines can easily draw a percentage of the generator’s gross output to cover auxiliary load. Because the efficiency of constant speed centrifugal pumps and fans depends on flow, converting existing constant speed machines to variable speed can reduce auxiliary load and improve heat rate throughout the load range.

Electronic VFDs are an ideal speed control mechanism for large machines, offering efficiencies exceeding 90% across the speed range and can be installed on existing motors. Even plants with existing hydraulic speed control can benefit from VFD conversions. Rotordynamic studies should be performed prior to a VFD conversion to explore means of reducing vibration, including possibly replacing motors.

Following its VFD conversion project, Rawhide Unit 1 saved over 4 MW of full load auxiliary power, setting records for its heat rate and dispatchable power, while simultaneously reducing CO₂ emissions per MWh.

Platte River Power Authority is a not-for-profit, community-owned public power utility that generates and delivers safe, reliable, environmentally responsible and financially sustainable energy and services to Estes Park, Fort Collins, Longmont and Loveland, Colorado. Platte River’s generation portfolio includes coal, wind, hydro, solar and gas resources. Rawhide Unit 1 is a 300-MW single-unit coal-fired power plant in northern Colorado.

Jeff Harmon is Rawhide’s Performance Engineer and project manager for the VFD conversion project.

Brian Brigandi is a Rawhide Plant Electrical Engineer and project electrical engineer for the VFD conversion project.

Nick Lumley, PE is the project’s lead mechanical engineer for Burns & McDonnell.

The EPA said it was following Clean Air Act requirements and meeting a court deadline in proposing the rules, which is said would help states “fully resolve” their Clean Air Act “good neighbor” obligations for the 2015 Ozone National Ambient Air Quality Standards (NAAQS).

Beginning in 2023, EPA is proposing to include electric generating units in 25 states in the Cross-State Air Pollution Rule (CSAPR) NOX Ozone Season Group 3 Trading Program, which would be revised and strengthened for the 2015 ozone NAAQS. 

The states include Alabama, Arkansas, California, Delaware, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia, Wisconsin, and Wyoming.

Beginning in 2026, EPA is proposing emissions standards for certain industrial sources in 23 states that EPA said have a “significant impact” on downwind air quality. EPA said its proposed limits on emissions from power plants and industrial sources reflect the installation and operation of “proven, cost-effective emission controls,” which it said in many cases have been implemented for years in numerous states.

The 23 states are Alabama, Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Tennessee, Texas, Utah, West Virginia, Wisconsin, and Wyoming.

EPA projects that the proposed rule by 2026 would prevent around 1,000 premature deaths and avoid more than 2,000 hospital and emergency room visits, 1.3 million cases of asthma symptoms, and 470,000 school absence days. It said reducing ozone levels also would improve visibility in national and state parks and increase protection for sensitive ecosystems, coastal waters, estuaries, and forests.

In 2026, the cost of achieving these reductions would be roughly $1.1 billion (in 2016 dollars), EPA said, and offer at least $9.3 billion in benefits. 

EPA said its proposed limits on NOX pollution from power plants would build upon existing CSAPR trading programs by including additional features that promote the consistent operation of emission controls to enhance public health and environmental protection for the region and for local communities.

Features would include daily emissions rate limits on large coal-fired units to promote more consistent operation and optimization of emissions controls, limits on “banking” of allowances, and annual updates to the emission budgets starting in 2025 to account for changes in the generating fleet.

EPA also proposed emissions standards for new and existing emissions units in additional industries: reciprocating internal combustion engines in pipeline transportation of natural gas; kilns in cement and cement product manufacturing; boilers and furnaces in iron and steel mills and ferroalloy manufacturing; furnaces in glass and glass product manufacturing; and high-emitting, large boilers in basic chemical manufacturing, petroleum and coal products manufacturing, and pulp, paper, and paperboard mills.

EPA said its proposal implements the Clean Air Act’s “good neighbor” or “interstate transport” provision, which requires each state to submit a State Implementation Plan (SIP) that ensures sources within the state do not contribute significantly to nonattainment or interfere with maintenance of the NAAQS in other states. Each state must make this new SIP submission within three years after the promulgation of a new or revised NAAQS.

Where EPA finds that a state has not submitted a good neighbor SIP, or if the EPA disapproves the SIP, the EPA must issue a Federal Implementation Plan (FIP) within two years to assure downwind states are protected. EPA said it is reviewing and acting on SIP submissions from the relevant states covered by this proposal.

EPA said it will take comment on the proposed rule for 60 days after it is published in the Federal Register. 

The conversion of Keephills Unit 3 from coal to natural gas ends the last of three planned conversions at the power producer’s facilities inAlberta. KH3 will maintain its original generating capacity of 463 MW, the company said.

TransAlta said the KH3 job cost C$29 million ($22.83 million), plus another C$48 million ($37.79 million) for gas infrastructure and maintenance projects. Since 2019, the company said it has spent C$295 million ($232.27 million) on coal-to-gas conversion projects at its Keephills, Sundance and Sheerness facilities.

As part of the conversion, the pulverized coal burners were replaced with gas burners, but the existing boiler and steam turbine equipment remained largely in place. The relatively low-cost conversion was completed within a few months, and yielded no marked improvements either in heat rate or efficiency.

Keephills entered service in 2011 at a cost of C$1.98 billion ($1.56 billion) and included a supercritical boiler and turbine, supplied by Hitachi Canada and shipped from Japan. At the time, co-owners Capital Power and TransAlta handled all aspects of construction, with engineering support from WorleyParsons. As a a coal unit, Keephills 3 was equipped with an advanced air quality control system to remove sulphur dioxide, nitrogen oxides, mercury and particulates from the flue gas prior to leaving the stack.

TransAlta said it has retired 3,794 MW of coal-fired generation since 2018, and converted 1,659 MW to natural gas. Canada has a federal mandate requiring the full phaseout of coal-fired electricity generation by 2030. TransAlta itself said it aims to reduce its annual emissions 60% by 2030 and become carbon neutral by 2050.

“Converting to natural gas from coal maintains the current generation capacity of KH3 and reduces our CO2 emissions by almost 50 per cent from approximately 0.86 [metric tons] CO2e per MWh to approximately 0.43 [metric tons] CO2e per MWh,” said John Kousinioris, TransAlta president and CEO.

In the United States, the company operates the Centralia coal plant in Washington, which is to be shut down in 2025.

Subscribe to Power Engineering’s free, weekly newsletter for more stories like this

The roughly $142 million program would include new wastewater treatment equipment at the fossil fuel-burning plants to meet U.S. Environmental Protection Agency effluent limitation guideline (ELG) requirements.

As proposed, the upgrades at the coal plants would be funded by ratepayers, starting at $0.51 a month for the average West Virginia residential customer. The surcharge would take effect when the first projects are implemented in 2024.

If the program is approved, the companies could complete the work by the end of 2025. Fort Martin and Harrison would operate until their planned retirement dates of 2035 and 2040, respectively. Fort Martin and Harrison were placed into service in the late 1960s and early 1970s.

The utilities said they will work to evaluate ways to replace the coal plants’ capacity, which combined totals around 3,080 MW.

Previous environmental actions

In 2020, FirstEnergy said it planned pledge to achieve carbon neutrality by 2050. According to FirstEnergy reports, Fort Martin Power Station has spent nearly $625 million on environmental control systems. The company reported each unit at the plant has a scrubber system, implemented in 2009, that removes more than 98% of sulfur-dioxide emissions.

According to FirstEnergy, Fort Martin is also equipped with electrostatic precipitators, removing 99% of the fly ash from flue gases.

FirstEnergy said environmental controls date back further at Harrison Power Station. The utility said Harrison has nearly $1 billion dollars in investments, including scrubber modules that remove more than 98% of the sulfur dioxide emissions. The scrubbers have been a part of the plant since 1995.

Selective catalytic reduction systems remove at least 90% of nitrogen oxide in the coal burned at Harrison.

NEW YORK (AP) — The Houston Ship Channel is home to petrochemical plants, power companies and heavy industries, all of which throw climate-harming emissions into the air.

In a process called “carbon capture and storage” (CCS), some industrial facilities capture this carbon dioxide before it leaves their plants, and then use it to develop products or store it underground.

Now Exxon Mobil has suggested turning the 50-mile-long channel into a CCS hub. The oil and gas giant is calling on industry and government to jointly raise $100 billion to create infrastructure to capture carbon dioxide at industrial plants, carry it away in pipelines and inject it deep under the floor of the Gulf of Mexico.

Joe Blommaert, President of Low Carbon Solutions at Exxon, says CCS is essential to meeting the goals of the Paris agreement while also meeting the growing energy needs of the world. Exxon has raked in more than $20 billion annually in profits over the past decade, on average, and nearly $300 billion annually in revenues. Blommaert talked with The Associated Press about the $3 billion that Exxon plans to spend on the business through 2025, and how the project might take shape. The interview has been edited for length and clarity.

Q: Your vision for the Houston Ship Channel calls for a $100 billion investment from companies and government. That’s a lot of money. How do you envision it would be spent?

A: Obviously, the scale is unprecedented. When you look into the details, actually, it is many capture facilities and storage facilities, and actually this CCS is executed at scale already around the world. What is important in my mind is this collaboration of the whole industry, the whole of government and the whole of society. And it is actually addressing climate change, which technically is a very complicated issue. It needs all of the solutions, and it is not one or the other. And that’s why with the Houston Hub we were so pleased with the 10 companies willing to step forward to help make this a reality.

Q: How much is Exxon willing to invest?

A: We are, just like other companies, assessing those opportunities. We’re working through our project and definition, and we will certainly do our part. I will not quote a specific number. We are working through that, as you can imagine. But the key is that policy to attract public and private investment in supporting this is put in place. And that’s why we talk about the value of carbon, which is essential.

Q: Can you tell me what percentage of the Houston Ship Channel project costs Exxon would likely contribute?

A: I will not give you the percentage, it’s obviously too early. Actually a meeting is scheduled in the next few days to talk about how to get organized, do governance, and so on. And then each company is actually looking at its own capture project, if you will, and the specific details. So more to come on that.

Q: Was this plan created in response to investor concerns about climate change?

A: We started this CCS venture about three years ago and actually that is now included in my business. And so we brought that to a stage that we could start thinking about how to really bring that to scale.

This was actually already quite quite well progressed, culminating in the creation of a (carbon capture) business that is now 30 this year, and we already had a portfolio of ideas. It’s just the right time for us.

Q: If Exxon believes this is important, why not dramatically reduce oil and gas production and invest more in renewable energy?

A: I fully appreciate this perspective on the issue, and I would come back to what I said earlier in terms of meeting the goals of the Paris accord and meeting energy and product demands that modern life requires, particularly when you think about the growth of society, 2 billion more people by 2050.

That energy mix will change, but that will still require energy sources from fossil fuels. That’s why it is actually so important to have technologies like CCS so that you can meet the energy supplies that the world needs in a way that the emissions are being abated, and that you can do that at the lowest cost possible to society. And you can do that now.

We’re buying renewable power. We do that through our power purchase agreements. We believe our strength really comes to the forefront through the deployment of technologies like CCS, like hydrogen, like biofuels. And those are technologies that are being recognized by the Intergovernmental Panel on Climate Change and the International Energy Agency as technologies that society needs to meet modern life requirements.

E2S Power and SNC-Lavalin signed the non-binding memorandum to collaborate on the rapidly growing energy storage market as a potential option for retiring power plants. Research firm Wood Mackenzie has forecast that global energy storage deployments will triple year over year and reached 21 GW before this year is done.

“New energy storage technology is revolutionizing the energy system, and this collaboration is driven by our common desire to improve reliability and sustainability of our clients’ energy systems well into the future,” said Nick Johnson, Vice-President, Power, Grid & Industrial Solutions, SNC-Lavalin. “Combining E2S’ solutions that extend the life cycle of current infrastructure and our global engineering expertise, we’ll introduce new technologies to deliver carbon-free, sustainable utilities solutions.” 

E2S Power CEO Sasha Savic noted that more than 200 GW of coal-fired North American capacity is expected to be decommissioned in the coming years. E2S Power is a joint venture between SS&A Power Developer and WIKA Group.

E2S Power and SNC-Lavalin will work with utilities and power generators in North America to evaluate and offer optimized integrated thermal energy solutions for their existing plants and facilities being phased out. The goal is retrofitting and repurposing the existing coal-fired power plant sites.

SNC-Lavalin historically has worked with power generators, including Canadian utilities Bruce Power and Ontario Power Generation at their respective nuclear power plant facilities. Nuclear energy does not emit greenhouse gases.

A new report by the federal Energy Information Administration, utilizing recent data, forecasts that coal-fired turbines will pick up the slack amidst higher natural gas prices. Gas-fired generation currently accounts for nearly 40 percent of the U.S. electricity resource mix, while coal was at about 20 percent last year.

Because natural gas-fired power plants convert fuel to electricity more efficiently than coal-fired plants, natural gas-fired generation can have an economic advantage even if natural gas prices are slightly higher than coal prices. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable.

This year, however, natural gas prices have been much higher than in recent years, according to the EIA. The year-to-date delivered cost of natural gas to U.S. power plants has averaged $4.93 per million British thermal units (MMBtu), more than double last year’s price.

Globally, many nations are in an energy crisis due to gas availability and weather impacts on renewables. Although rising natural gas prices have resulted in more U.S. coal-fired generation than last year, this increase in coal generation will most likely not continue, the EIA report noted.

Related stories

Coal Financing in Asia and Africa shows upward trend

Increase in coal-fired power generation draws down power plant stockpiles

The electric power sector has retired about 30% of its generating capacity at coal plants since 2010, and no new coal-fired capacity has come online in the United States since 2013.

The EIA expects the Henry Hub spot price for natural gas will average $5.80 per MMBtu in the fourth quarter, nearly 50 percent higher than the federal agency predicted one month earlier. Henry Hub prices may reach a monthly average peak of $5.90/MMBtu in January 2022, according to the EIA forecast.

Coal production should total nearly 600 million short tons for 2021, 53 MMst than in 2020, the EIA report reads. The electric power sector’s demand for coal should rise by 84 million short tons this year compared to 2020, according to the EIA.

The order by the state’s Public Service Commission gives new leases on life for the Amos, Mountaineer and Mitchell generating stations, which altogether total close to 6 GW in generation capacity. Two other states, Virginia and Kentucky, had refused to approve effluent limitation guideline (ELG) upgrades required for the plants’ continued operations.

By contrast, the West Virginia PSC ruled, those states will not be permitted to use any of the capacity or energy generated by the coal-fired plants since they will not share in the cost of the improvements.

The utilities, Appalachian Power Co. and Wheeling Power Co., must file separate requests for cost recovery to pay for ELG and coal combustion residue (CCR) upgrade work. Some estimates have those expenses as potential raising customers’ bills by about $2.64 per month.

Overall, the estimated total cost of bringing all three coal-fired plants into environmental compliance is nearly $450 million. The cost of replacing the collective generation at Amos, Mountaineer and Mitchell with other means was estimated at $2 billion or more if they were prematurely retired, according to the PSC report.

“The order points out that benefits of the plants’ continued operation to the state’s economy are considerable,” reads the PSC release about the decision. “Direct employment at the plants; use of West Virginia coal; state, county and local taxes related to operating generation plants; and related employment in businesses supporting the plants and the coal industry cannot be discounted or overlooked.”

Mountaineer Power Plant is owned by Appalachian Power parent AEP and generates close to 1,480 MW at capacity. Amos is a three-unit coal-fired plant also is owned by AEP-Appalachian and rates at 2,933-MW capacity, according to reports.

Mitchell is a 1,632-MW capacity plant.

— — — — —

The future of coal-fired generation is a key topic for sessions happening at POWERGEN International this January 26-28 in Dallas. Registration is now open for the live event.

The October 27 online POWERGEN+ series will feature sessions around carbon capture and gas-fired power’s role in the energy transition. Registration is free and sessions available live and on demand.

Capital Power is repowering Units 1 and 2 at the Genesee Generating Station, replacing coal-fired steam generators with gas-fired combined cycle technology. The utility approved its project in 2020, and Missouri-based Burns & McDonnell began design and engineering work earlier this year.

The repowering and conversion of Genesee Unit 1 is expected to reach full combined cycle operation by the end of 2023, while Unit 2 is anticipating commissioning in mid-2024.

The move could lower Genesee’s carbon emissions by 60 percent, according to the company. The repowered units will use selective catalytic reduction technology to minimize nitrogen oxide emissions.

See our full coverage of Burns & McDonnell projects in the power sector

Subscribe to PE’s free, weekly newsletter

“We are excited to help Capital Power advance its commitment to reducing carbon emissions while maintaining dependable, resilient generation for its customers,” Jeff Reid, Burns & McDonnell Energy Canada director, said in a statement last month. “Utilizing so much of the existing power plant infrastructure will make this a big win for Alberta. And the utility will benefit greatly from this best-in-class technology, setting a new standard for gas generation efficiency.”

The construction work will install two Mitsubishi M501JAC gas turbines, each of those exhausting into a Vogt triple-pressure heat recovery team generator (HRSG). The HRSG will produce the steam to power the plant’s existing Unit 1 and 2 steam turbines.

Each gas-fired turbine will have a bypass stack to allow operation in simple-cycle mode prior to combined-cycle operation. Each unit will be able to generate approximately 400 MW in simple-cycle mode for a few months while the steam turbines are taken offline to allow for modifications and new combined-cycle tie-ins.

Electrical output will be stepped up to 500-kV and interconnected with a new site substation.

The coal-fired Genesee units 1 and 2 combined for 860 MW output and were originally commissioned in the mid-1980s.

Capital Power owns more than 6,400 MW of power generation capacity at 26 facilities across North America. Projects in advanced development include 425 MW of owned renewable generation capacity in North Carolina and Alberta and 560 MW of incremental natural gas combined-cycle capacity, from the repowering of Genesee 1 and 2 in Alberta.

— — — — —

Captial Power also had made significant investments in carbon capture technology, which will be a topic during its POWERGEN+ online session later this month with Black & Veatch. The POWERGEN+ sessions are free and available live or on demand.