The testing took place this week at ESG’s 4 MW power generation site in Holyoke, Massachusetts. Using calibrated humidity sensors positioned at both the beginning and the end of the exhaust stream, ESG says the results exceeded the modeled forecast of 83% that was developed during the initial design phase of its carbon capture process.

“This will work to our benefit as we scale to meet the demands of fossil fuel consumption in small and large power facilities, and eventually the transportation industry,” said Nick Scuderi, president of ESG Clean Energy.

ESG has plans to build a second gas-fired plant in Holyoke. The 4.2 MW plant would also be powered by Caterpillar engines.

ESG Clean Energy says it plans on implementing its CO2 capture technology across all its planned facilities and has licensed the technology to a subsidiary of Camber Energy for all of Canada and multiple locations in the United States.

The company says its system treats the exhaust stream to remove the water vapor before it is treated for capturing CO2. The system consists of a ceramic membrane that has been incorporated into a mechanical cooling system.

There’s a problem with traditional carbon capture, ESG Clean Energy says: separting and capturing carbon dioxide from a mixture of nitrogen, oxygen, carbon dioxide, nitrogen oxides, carbon monoxide, and water vapor can be difficult, and while some materials have been developed that can “selectively attach or react with the CO2 while letting the other gases pass by,” the water vapor remains. Water molecules interfere with the carbon capture process, ESG Clean Energy says, citing several scientific studies showing how water negatively affects CO2 capture.

The Environmental Protection Agency (EPA) is expected to propose updated carbon emission regulations for gas-fired plants in 2022, per comments from EPA head Michael Regan in March.

The agency recently took another step in that direction, publishing a white paper detailing ways gas-plants can reduce their CO2 emissions.

The paper presents opportunities for emission cuts, like the co-firing of natural gas with alternative fuels such as hydrogen; using carbon capture, utilization, and storage (CCUS) technologies; and the co-location with energy storage. Although it doesn’t set policy or establish standards, the EPA “anticipates that the white paper may be useful to inform future rulemaking efforts.”

The Clean Air Act requires new engines and equipment sold or distributed in the United States to be certified to meet EPA-established emissions requirements to protect public health and the environment from air pollution.

Under the latest standards from 2015, new natural gas power plants can emit no more than 1,000 pounds of carbon dioxide per MW of electricity produced. New coal-fired power plants can emit no more than 1,400 lbs CO2/MWh. The standards apply to sources on or after the date of publication of the proposed standards, June 18, 2014.

It’s not clear to what extent the new EPA rules will rely on CCUS technology. The agency’s white paper notes while there is increased interest in carbon capture for natural gas-fired plants, most CCUS efforts have focused on coal plants.

Examples of carbon capture installed on coal plants include the slip stream capture facilities AES Warrior Run in Maryland and AES Shady Point in Oklahoma. In both cases, the captured CO2 is used in the food processing industry. The EPA also cited Southern Company’s Plant Barry in Alabama and AEP’s Mountaineer in West Virginia as having CCUS technology.

Use of CCUS on combined cycle plants include the Bellingham, Massachusetts plant, which used Fluor’s Econamine FG PlusSM capture system. The 40 MW slipstream capture facility operated from 1991 to 2005 and captured 85 to 95 percent of the CO2 for use in the food industry.

The paper notes some emission control technologies that are currently available and some still in the research and development phase.

EPA officials noted the U.S. Department of Energy (DOE), utilities and other organizations are developing processes that use solvents, polymeric membranes, a combination of the two, or solid sorbents for separating and capturing CO2.

Fuel cells configured for emissions capture have also emerged as a CCUS technology. In this process, the flue gas from a plant is “routed through a molten carbonate fuel cell that concentrates the CO2 as a side reaction during the electric generation process in the fuel cell.”

The white paper also mentions oxygen combustion, the use of a mixture of oxygen and recycled flue gas in place of ambient air for combustion. An oxy-combustion power plant consists of an air separation unit (ASU), which generally requires a significant amount of energy. However, alternative oxygen separation methods are being researched for possible commercial-scale development. These include ion transport membranes (ITM), ceramic autothermal recovery, oxygen transport membranes, and chemical looping.

The EPA noted because oxy-combustion produces a flue gas that contains primarily CO₂ and water vapor, minimal post-combustion cleanup is required prior to compression, transportation, and injection for use in geological storage, enhanced oil or gas recovery, or some other use. However, a potential constraint of oxy-combustion is the ability of the air separation unit to respond to variable loads.

The Allam-Fetvedt Cycle, which combusts natural gas with oxygen instead of air, uses supercritical carbon dioxide as a working fluid to drive a turbine instead of steam. This theoretically eliminates all air emissions and inherently produces pipeline-quality CO₂ that can be sequestered.

There are several announced commercial projects proposing to use the Allam-Fetvedt cycle. These include the 280-MW Broadwing Clean Energy Complex in Illinois and the 280-MW Coyote Clean Power Project on the Southern Ute Indian Reservation in Colorado. Final investment decisions on the U.S. projects are expected in 2022 and commercial operations could commence by 2025.

EPA is asking for public comment on the white paper through June 6, 2022.

The agreement would accelerate development of the largest fully permitted carbon storage site in the United States.

Minnkota Power Cooperative and Summit Carbon Solutions have agreed to co-develop carbon dioxide storage facilities near Center, North Dakota.

The partnership builds on development already in the works. Minnkota and Summit have been working independently on developing their respective carbon capture and storage projects.

Minnkota’s Project Tundra aims to install carbon capture technologies at the Milton R. Young Station in North Dakota. The station is a two-unit, 705-MW lignite coal-burning plant. Unit 1 became operational 50 years ago, while Unit 2 began generating electricity seven years later. It is a primary generating facility for Minnkota, which hopes carbon capture could contain up to 90 percent of the carbon dioxide emissions from the Unit 2 generation.

Iowa-based Summit Carbon Solutions aims to capture and permanently store CO₂ from dozens of ethanol plants across five states in the Upper Midwest.

The agreement gives Summit access to Minnkota’s already permitted 100-million-ton capacity CO₂ storage site, the largest of only three such permitted sites in the United States. It also creates the framework to jointly develop additional CO₂ storage resources nearby, which could hold more than 200 million tons.

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. 

Less than 20% of data generated by industrial companies is actually used. Even less is analyzed. This means up to 80% of data is lost for analytics and decision-making.

Heavy industries have been slow to take advantage of the digital revolution, causing these crucial sectors to miss out on the hidden efficiencies and asset protections provided by artificial intelligence and a data-driven world.

One size doesn’t fit all.

ABB executives joined Power Engineering for an exclusive Q&A to talk about the ABB Ability Genix Industrial Analytics and AI Suite, the digital revolution for industry, and how to navigate the energy transition using your own data.

Power Engineering: How has the digital revolution evolved in recent years for industry?

Rajesh Ramachandran, Chief Digital Officer, ABB Process Automation: With the advent of digitalization, vast amounts of real-time sensor and operational data, transaction data, and engineering design data is at our disposal from various sources. Our opportunity is to collect and contextualize this data to develop analytics that use artificial intelligence to help users make better business decisions.

Less than 20% of data generated by industrial companies is actually used. Even less is analyzed. This means up to 80% of data is lost for analytics and decision-making. Unless technology is deeply integrated with operational processes, the path to Industry 4.0 value realization will remain slow.

PE: And how about the impact of A.I.?

RR: The proliferation of artificial intelligence and machine-learning techniques using sensors, digital data, and remote inputs allows us combine information from a variety of sources, analyze it instantly, and act on the insights derived. With improvements in storage systems, processing speeds and analytical techniques, we are greatly improving analysis and decision making.

We have been using artificial intelligence and machine learning to bring a higher degree of prediction accuracy to optimize operations, processes, and assets. Applying AI to industries that one understands and in which one has significant experience enables safer, smarter, and more sustainable operations.

PE: How has A.I. influenced remote monitoring?

RR: Traditional condition monitoring ascertains the health of an asset based on hard-coded alarms and experienced analysts. This approach however can lead to false alarms or late diagnosis of abnormal behaviors or faults. This approach also looks at signals from a single sensor (maybe two) and fails to provide a holistic picture of asset health.

Data analytics, artificial intelligence and machine-learning methods overcome these gaps and diagnose the health of an asset based on a combination of sensor signals to generate prescriptive advice. Additionally, AI techniques can be used to predict future health and calculate the remaining life of an asset. This can reduce maintenance costs and improve production uptime by allowing users to apply reliability-centered maintenance instead of traditional time-based maintenance that may add unnecessary interactions and induce failures.

AI in the future will supplement traditional condition monitoring by establishing an expert system to provide early warning of potential faults, generate prescriptions to address them, and accurately estimate the remaining life of the asset.

PE: What types of other industries are requesting this technology?

RR: All asset-intensive industries can use this kind of technology, including:

• Oil & gas
• Chemicals
• Refining
• Metals
• Pulp & paper
• Cement
• Mining
• Power generation
• Water
• Food & Beverage
• Life Sciences
• Manufacturing

PE: How can Genix improve performance and extend asset lifetime?

Gino Hernandez, Head of Global Digital Business for ABB Energy Industries: One of the key solutions developed in the Genix Industrial Analytics and AI suite is the Genix APM Suite. “APM” stands for “Asset Performance Management.” Genix APM collects and organizes data from operating assets through information and operational technology such as Enterprise Resource Planning, Computerized Maintenance Management and Enterprise Asset Management systems. 

Next, Genix APM calculates expected performance, models faults, and contextualizes data using past performance, AI, and prescriptive and predictive analytics. Key to this contextualization is domain knowledge from both ABB and end-user subject matter experts.  Leading technology in knowledgeable, experienced hands helps users to decide when and how to maintain assets, improve asset performance, extend asset life, and plan asset replacement.

PE: Conventional power generators are under mounting pressure from corporations and investors, often constraining budgets.  Is asset performance and monitoring, within digitization, being appropriately prioritized by asset owners?

GH: Asset optimization and health continues to be a high priority in all industrial operations. Digitalization and sustainability interests have accelerated business strategies and corporate initiatives toward better asset utilization. This leads to better cost control in the short term, and delivers strategic advantages over the long term as maintenance schedules are tuned, faults predicted, and issues mitigated before they become problems. Economic conditions are no longer the same as when users originally purchased their assets.  The focus is now on maintaining existing assets in order to retain cash. Maintenance is evolving from reactive or preventive to condition-based, with the next steps being prescriptive maintenance strategies using advanced predictive techniques.

Demand volatility causes end users to operate in a way that was not planned for; therefore, better understanding and control of asset performance is more important than ever. This approach also helps reinforce sustainability by retaining existing assets instead of buying new ones.

PE: What have you heard from customers who have implemented the Genix platform?

Tariq Farooqui, Group Vice President and Head of Digital Portfolio Management, PA Digital: A large customer from the power sector is using Genix APM for predictive analytics. Genix APM combines data science and physical modeling to all production assets regardless of manufacturer. The solution helps customers make more informed decisions for maintaining and operating their assets, providing warning of critical failures and health diagnostics of assets while providing performance and efficiency KPIs.

Another large customer that is operating data centers around the world uses Genix to reduce energy usage in cooling systems, which consumes the most electrical power in a data center next to the IT equipment. Optimizing cooling efficiency in turn improves power usage effectiveness and reduces the carbon footprint, with an estimated reduction of 1,100 tons of carbon in the atmosphere for every 10MW of IT load utilized. This is equivalent to saving approximately 18,000 trees. With the ability to glean AI-generated insights, this customer can effectively capture, contextualize, track, and analyze data generated by various systems in the data center, and better facilitate dynamic cooling optimization to reduce costs.

A large mining customer can extract and contextualize data from their operational, information and engineering systems using Genix. With Genix, the user applies advanced analytics to track important KPIs, find root causes wherever there are deviations, and perform predictive and prescriptive analytics.

PE: What about industrial customers who have to adhere to strict sustainability goals or regulations?

Dave Lincoln, Head of Global Digital Business for ABB Measurement & Analytics: Sustainability goals require accurate measurement of the environmental impact of a particular process, site, or company. At its most simple level, digitalization enables aggregation and visualization of a range of measurement data coming from potentially disparate systems, and converts that data into relevant units such as CO2 output, KWH consumed, Megaliters of water treated, etc.  Live sustainability data allows companies to immediately understand how they are performing against specific KPIs and to take informed action where required. A more intelligent system connects sustainability data with process data to predict future outputs, and can even automatically tune processes to reduce environmental impact.

Many regulatory-driven measurements are required in industry, including chimney stack emissions and water effluent discharge. Measurements are often taken continuously, and require the data to be securely stored for many years. These systems are often complex and require regular maintenance to ensure that accurate and reliable data is collected. Digitalization enables remote management of these systems, thus reducing downtime and easing efforts to operate and manage them. This in turn allows plants to focus on process performance to eliminate emissions, as well as to reduce energy and water consumption.

A large industrial plant could potentially have many continuous emission monitoring systems. These complex systems require skilled onsite personnel to ensure that they are operating accurately with the very high availability requirements demanded. Routine inspection and measurement validation of each system consumes many hours per month, which may not directly benefit the company or the environment in terms of emissions reduction. Digitalization is creating new opportunities to reduce and even remove this manual inspection effort.

Remote monitoring of emission monitoring systems using Genix Datalyzer automates data collection and enables full remote management. Diagnostic data is used to identify potential failure mechanisms before they occur, reducing risk of downtime. Additionally, Datalyzer provides a validation report (known as QAL3 in Europe) of the measurement accuracy that can be given to the local regulatory organization to provide evidence that the system is performing correctly. These features reduce many hours of work each month. This solution provides data-driven insights that are shifting business models toward CEMS-as-a-Service and outcome-based agreements.

PE: How does Genix allow ABB to maximize data from existing clients?

Rajesh Ramachandran, Chief Digital Officer, ABB Process Automation: ABB Ability™ Genix is an enterprise-grade, open architecture-based platform and suite, which harnesses the power of industrial analytics and artificial intelligence to transform cross-functional data into actionable insights. Data used extends across diverse systems: operational, information, and engineering technology. We designed ABB Ability™ Genix with scalability in mind to have a platform that extends from the asset level through asset ecosystems at plants and enterprises, addressing the needs of multiple stakeholders. The basic value proposition is the collection, collation, and contextualization of large amounts of asset data.

Genix offers a key advantage: many of the assets used by ABB customers in their operations come from ABB, such as analyzers, control systems, drives, generators, motors, PLCs, robots, switchgear, and more. ABB is positioned, then, to know how to extract data from these assets, to understand what the data indicates, and to identify opportunities to improve the performance of these assets.

Gino Hernandez, Head of Global Digital Business for ABB Energy Industries:

Every industry has a unique way of operating assets depending on the desired outcome.  For example, a feed pump serving a distillation column is a very different application from a pump circulating cooling water in a power plant.  The digital model for these pumps may be similar, and even display similar information in a dashboard. However, because the application of the model is so different, they require current, accurate, application-specific use cases and models for precise use.  Genix APM can be configured for specific industries, including power generation. Existing uses of Genix APM include diagnosing discrepancies across gas turbine compressors, revealing a leakage problem in an HRSG, and early detection of unbalance in a hydro turbine. 

PE: What is the biggest pain point that you hear from customers who are making the digital transformation?

Tariq Farooqui, Head of Sales, ABB Process Automation Digital: Some of the bigger pain points that customers are facing in their digital transformation journey include:

• Inability to leverage the vast amount of data generated in the organization since the data is in silos; that is, different operational, information and engineering technology systems, and not in a form that can be used for further analysis and decision-making. In fact, many customers see that nearly 80% of their data is not usable.
• Inability to find dependencies between data points from different sources. Even where the data is available, it is not contextualized.
• Inability to develop AI models and deploy them at scale. Customers are able to deploy small AI pilots, but are not able to scale in a full production deployment.
• Inability to develop and deploy analytics applications rapidly with lower time to value.
• Inability to find suppliers that can bring data, domain and analytics expertise together. Suppliers who are good in AI and analytics often are not able to bring the domain understanding to apply the analytics in the right industrial context. Also, vendors are not able to solve end-to-end requirements.

PE: How does digitization fit into cybersecurity and risk management planning?

Robert Putman, Global Manager, Cyber Security Services: To harness digitalization’s full capability and benefits, one must have confidence that previously unconnected systems won’t add risk to the organization’s overall goals. The advantages of digitalization are improved productivity, less environmental impact and accelerated innovation. The risk of digitalization and system interconnectivity is low when managed correctly using available security controls and strategies, making the decision of digitalization and its benefits simple.

Take Colonial Pipeline, for example. Colonial Pipeline embraced digitalization by connecting the customer’s meters used to bill the customer for the product received. Under normal circumstances, this approach increased Colonial’s billing quality while reducing labor costs. The implementation focused on the benefits while the associated risk was not prioritized. With relatively minor modifications, benefits could have been realized without exposing the operations to the outcome of the ransomware attack.     

While risk assessments are a common practice in Information Technology, they are often overlooked in Operational Technology. OT systems share many of the same characteristics of IT systems, yet have more Health, Safety and Environmental risk. One must make sure that a compromised IT network will not propagate into the OT network. In the unlikely event of a cyber incident, one must have a documented and tested incident response plan ready to ensure correct and speedy production recovery.

The UK’s Department of Business, Energy and Industrial Strategy (BEIS) has named the East Coast Cluster (ECC) as a ‘Track-1’ cluster, putting it on course for deployment by the mid-2020s.

The Cluster is a huge carbon capture and storage proposal located on the East coast of the UK in the North Sea and is a collaboration between Northern Endurance Partnership, Net Zero Teesside and Zero Carbon Humber.

The announcement is a major step forward in establishing the first net zero-carbon industrial cluster in the UK by 2040.

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Carbon capture will be part of content happening in the October POWERGEN+ Online series

Next Week: Registration is free and sessions both live and on demand

Grete Tveit, Senior Vice President for Low Carbon Solutions at Equinor, which is a partner of Zero Carbon Humber, Net Zero Teesside and Northern Endurance Partnership said: “We’re delighted that the East Coast Cluster has reached this milestone.

“As we mark and celebrate this major step, we look forward to continuing working closely with our partners, local communities, businesses, industry, and academia to deliver this ambitious and world-leading project that will play a major role in levelling up across the country”.

The East Coast Cluster will be vital for supporting low-carbon industry and power projects across the region. Once operational, the cluster has the potential to transport and securely store nearly 50% of all UK industrial cluster CO2 emissions – up to 27 million tonnes of CO2 emissions a year by 2030.

The project aims to create and support an average of 25,000 jobs per year between 2023 and 2050, with approximately 41,000 jobs at the project’s peak in 2026.

Louise Kingham, Senior Vice President, Europe & Head of Country, UK at bp said: “The East Coast Cluster can play a critical role in the UK Government’s levelling up ambition, supporting thousands of jobs and investing in local communities. Teesside and the Humber were once the industrial heart of the UK.

“Today’s announcement paves the way for them to become the green heart of the country’s energy transition, shepherding in the next generation of industry and ways of working.”

DOE announced financing for the quartet of regional CCUS deployments last week. Some estimates indicate that CCUS could reduce CO2 emissions from industrial resources significantly and contribute to the goal of net-zero emissions by 2050.

The carbon capture projects awarded by DOE include work based out of Ohio, New Mexico, Georgia and North Dakota. Each project was awarded approximately $5 million.

“Every pocket of the country can and will benefit from the clean energy transition, and that includes our expanded use of carbon capture and storage technology to remove carbon pollution from fossil fuel use,” said Secretary of Energy Jennifer M. Granholm. “Through DOE’s Regional Initiatives projects, we are making sure states—especially those with historic ties to fossil fuel industries—can access technology innovations to abate carbon pollution and enhance their local economies so that no worker or workforce is left behind.”

The Regional Initiatives are university-led partnerships with academia, non-governmental organizations, industry leaders, and local and state governments. The initiatives identify and promote carbon storage and transport projects by addressing key technical challenges; facilitating data collection, sharing, and analysis; evaluating regional storage and transport infrastructure; and promoting regional technology transfer.

• Battelle Memorial Institute (Columbus, OH) is leading the Regional Initiative to Accelerate CCUS Deployment in the Midwestern and Northeastern USA project in 20 Midwestern and Northwestern states to review regional infrastructure and technical challenges to deploying CCUS in three sedimentary basins and the Arches province.
• New Mexico Institute of Mining and Technology (Socorro, NM) is leading the Carbon Utilization and Storage Partnership of the Western United States project in 15 Western states to focus on compiling geologic datasets in the region for storage resource analyses and identifying data gaps.
• Southern States Energy Board (Peachtree Corners, GA) is leading the Southeast Regional Carbon Utilization and Storage Partnership project in 15 Southeast states to identify at least 50 potential regional sites to evaluate storage resource potential and infrastructure needs.
• University of North Dakota Energy and Environmental Research Center (Grand Forks, ND) is leading the Plains CO2 Reduction project in 13 Northwest states and four Canadian provinces to identify and address onshore regional storage and transport challenges facing the commercial deployment of CCUS in an expanded region.

The U.S. is home to numerous carbon capture projects nationwide already in the research phase. Those include the National Carbon Capture Center (pictured) operated by Southern Co., and the Petra Nova project in Texas.

— — — — —

Carbon capture will be one of the topics of focus next week in the POWERGEN+ online series. Registration is free and sessions available on demand.

POWERGEN+ session on BTU analysis of hydrogen mix in power generation

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.

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“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.

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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.

The large-scale deployment of carbon capture and storage technology has gained wide industry support in Houston with 11 big energy players supporting the initiative.

The 11 companies include Calpine, Chevron, Dow, ExxonMobil, INEOS, Linde, LyondellBasell, Marathon Petroleum, NRG Energy, Phillips 66 and Valero agreeing to scale the deployment of the technology at their facilities.

The companies agreed to increase the amount of carbon captured and stored to 50 million tonnes per annum by 2030 and to 100 million tonnes per annum by 2040 to mitigate climate change in Houston.

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The firms plan to capture carbon at facilities that produce products consumed by society on a daily basis and that use plastic, motor fuels and packaging, materials that are harmful to the environment yet consumers heavily rely on.

Sylvester Turner, Mayor of Houston, said: “Houston can achieve our net-zero goals by working together, and it’s exciting to see so many companies have already come together to talk about making Houston the world leader in carbon capture and storage.

“We’re re-imagining what it means to be the energy capital of the world, and applying proven technology to reduce emissions is one of the best ways to get started.”

The project, if fully deployed, is expected to help Houston capture and store 75 million tonnes of carbon by 2040, helping the city to move closer to its 2050 net-zero goal.

The aim is to encourage the use of technology to grow the city’s green economy and generate thousands of clean jobs and save lives from climate change at a lower cost.

Although renewables will continue to play an important role in a lower-carbon energy future, CCS is one of the few proven technologies that could enable some industry sectors to decarbonize, such as manufacturing and heavy industry.

The International Energy Agency projects CCS could mitigate up to 15% of global emissions by 2040, and the U.N. Intergovernmental Panel on Climate Change (IPCC) estimates global decarbonization efforts could be twice as costly without CCS.

Louisville Gas & Electric Co. and Kentucky Utilities, both part of PPL Corp., announced a study partnership with the University of Kentucky Center for Applied Energy Research (CAER). The group will work together to develop net negative-CO2 and cost-effective emissions technology directly applicable to gas-fired power generation facilities.

In addition to capturing CO2, the system will produce two value-added streams, hydrogen (H2) and oxygen (O2,) which can be sold to offset the cost of CO2 capture.

This study will explore extending equipment life and maximizing fuel efficiency by keeping the plant at a constant electricity generation rate by producing H2 /O2 during periods of low power demand.

Gas-fired turbines, Carbon Capture and role in Decarbonization all part of POWERGEN International

Happening live Jan. 26-28 in Dallas

“We’re proud to once again partner with UK CAER on groundbreaking research that has the potential to create meaningful advances in power generation,” said LG&E and KU Chief Operating Officer Lonnie Bellar. “Creating collaborations like this one and exploring technology and innovation that can make a difference for the industry and our customers is part of our commitment to helping shape the energy future of our Commonwealth and the nation.”

The first phase of this research project will take place in CAER’s laboratories, with the goal of eventually moving this technology to LG&E and KU’s Cane Run Generating Station in Louisville for pilot-scale testing.

The 640-MW Cane Run gas-fired plant was commissioned in 2015. It replaced  a coal-fired power plant which had operated at the same site for 60-plus years.

Numerous energy firms and utilities are working on in-progress or developing carbon capture, utilization and storage (CCUS) projects throughout the U.S. Some of these include NRG, Southern Co., Mitsubishi Power, Kiewit, Sargent & Lundy and Prairie State Generating, among others.

Some environmentalists have disputed the potential of the carbon capture efforts. Others are touting its ability to keep fossil-fired generation reliable as many utilities aim for net-zero carbon emissions by 2050.

Allied Market Research has predicted that the CCUS market could more than triple to $7 billion by the end of the decade.