Natural gas is yet again making headlines for its role in providing reliable power to maintain grid stability.

Amid federal and state mandates driving the sector toward cleaner and more efficient solutions, natural gas has emerged once again as a crucial player in the transition to a more sustainable energy landscape. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

Regulatory drivers aside, the need for energy-dense, dispatchable electricity is fueled by the continuous retirement of coal facilities, the burgeoning of data centers, the rapid development of AI technologies and the onshoring of manufacturing trends. By 2028, the growth of data centers, supercharged by the development of AI, could consume 7.5% of all electricity in the U.S. This calls for an urgent need for the U.S. to enhance its infrastructure to accommodate this significant load growth in addition to what’s currently planned. These factors highlight the challenge that renewable energy sources alone face in supplying the necessary power capacity to meet escalating energy demands. 

The demand for new gas generation builds is back 

Given the prevailing demand, the lifecycle of gas projects is now being significantly prolonged. Essentially, if you haven’t started proactive project planning yet, you may be already running behind.

A reoccurring conversation we’ve been having with customers is about the need to build new gas generation in addition to renewables. With simple-cycle and combined-cycle gas turbines in such high demand, buyers of F-Class, advanced-class and aeroderivative gas turbines are experiencing lead times not seen since the gas boom of the early 2000s.

Historically, the steps for developing a new gas generation project included front-end studies, siting and permitting and interconnecting to the grid before buying the equipment needed for the project. In the current market, securing long-lead equipment and entering the interconnection queue has become the main priority. 

Yes, the gas boom is back. Its resurgence in the market highlights its indispensable role in today’s energy transition. Natural gas facilities can provide the critical path forward to support and solve the challenge of increasing load growth. Nearly half of the coal-generating capacity seen in 2011 is expected to be retired by the end of 2026 as the U.S. continues its sustainable efforts. 

Signs of a booming market for simple-cycle, combined-cycle and recips are prominent across the United States. It may be too early to tell what it will bring and how long it will last, but keep an eye on signs such as lead times for major equipment, craft labor availability and changes in project development processes as indicators of the ongoing longevity of the gas boom. 

About the Author: Joey Mashek is the U.S. sales and strategy director for the Power Group at Burns & McDonnell. With nearly 20 years of experience, he discusses, develops and negotiates generation needs for utilities, independent power producers (IPPs), cooperatives, municipalities and end users across North America.

Located across 1,900 acres, the Muskegon Solar Energy Center is expected to be completed in 2026. The project is a key part of Consumers Energy‘s plan to add 8 gigawatts of utility-scale solar power by 2040.

“Consumers Energy has some of the most ambitious clean energy goals in the nation and advancing projects like this put us on a clear path to achieving them,” said David Hicks, vice president of clean energy development for Consumers Energy. “Every project we bring online helps lower bills for our customers in the long term while also providing significant tax revenue for the community and better serving our planet. That’s a win for everyone, and we’re proud to be partnering with Burns & McDonnell to see this project come to fruition.”

“We are excited to work with local trades and union halls across Michigan to build out solar within the state,” said Drew Powers, construction project manager at Burns & McDonnell. “This project not only helps Consumers Energy advance in renewable energy but also supports the local economy.”

“We are excited to help build out solar and drive the low cost of energy and renewable penetration into the great state of Michigan,” added Scott Newland, senior vice president of infrastructure at Burns & McDonnell.

Burns & McDonnell is using an integrated engineer-procure-construct (EPC) approach on the project. The integrated EPC scope of the firm also includes site permitting, substation construction, and the interconnection generation tie. The Burns & McDonnell team consists of the firm’s union self-perform construction arm, AZCO, working closely with local and other Michigan-based union labor.

Some key components of the project include First Solar Series 7 modules, Array Technology trackers, Siemens Gamesa inverters, and Shoals Technologies Group and CAB Solar Cable Management tools.

Last year, Michigan passed a law limiting the ability of local governments to block solar and wind projects. Opponents under the name “Citizens for Local Choice” responded by launching a campaign to put a referendum on the ballot that would repeal the law, but last week they ran out of time to gather enough signatures. The organization said they will continue their campaign, working to secure placement on the 2026 ballot.

In the meantime, renewable energy projects are taking root across the Great Lakes state.

This week, DTE Energy announced it will convert a portion of its retired Trenton Channel coal power plant site to house a 220-MW battery energy storage center. When completed in 2026, the energy storage center is expected to be the largest standalone battery energy storage project in the Great Lakes region.

DTE Energy is currently seeking proposals for renewable energy projects totaling approximately 1,075 MW and 120 MW in battery energy storage projects to support DTE Electric’s CleanVision Integrated Resource Plan (IRP), the company’s MIGreenPower program, and Michigan’s new renewable energy standard of 60% by 2030.

Originally published by Paul Gerke on Renewable Energy World.

Editor’s note: This article was originally published by Burns & McDonnell.

According to The Global CCS Institute, the number of active carbon capture projects is dramatically increasing across a number of heavy industrial sectors. 

Reading behind the data, we see that the total number of projects in development from 2021 to 2023 has remained relatively steady, though capacity has increased due to much larger projects being developed in North America, Southeast Asia and the U.K.

In the U.S., recent federal incentives are priming the pump for carbon capture across many industrial sectors. Both the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) are injecting billions of dollars into the capture marketplace. The IIJA will jump-start investment through various matching grant programs administered by the Department of Energy (DOE), while the IRA provides a pathway to monetize carbon capture investments through increased 45Q tax credits.

As the Treasury Department finishes guidance on exactly how the IRA tax credits will work, it is becoming clear that the tax code will become an economic engine that drives many billions in investment dollars out into the market for carbon capture projects over the coming decades.

Power sector

New greenhouse gas standards and guidelines issued by the EPA in May 2023 are likely to make some form of carbon capture a reality for some fossil-fuel generation plants. Unless the standards are significantly modified, they will affect development of combined-cycle plants and certain existing coal- and gas-fired plants. The new standards are subject to a public comment period and are unlikely to be finalized before 2024 at the earliest.

No matter how the final rules shake out, a better understanding of the entire process chain of carbon capture utilization and storage (CCUS) and carbon capture and sequestration (CCS) projects will be helpful.

Technology pathways

There are unique technology options that are available when designing a capture plan for power facilities. A number of newer, developmental technologies are entering the market alongside older, proven technologies.

For post-combustion carbon capture from flue gas, the amine absorption process has the longest track record in the market. It’s been demonstrated at commercial scale and can deliver approximately 95% CO₂ capture (and sometimes higher). The main drawback is that amine capture in an energy-intensive process using both thermal and electric energy that diverts significant megawatts of auxiliary power from the plant, reducing total capacity available for dispatch to the grid.

Carbon Capture and Sequestration (CCS) will be a key topic as part of the Carbon Capture and Emission Controls educational track at POWERGEN International. The event takes place is January 23-25, 2024 at the Ernest N. Morial Convention Center in New Orleans, Louisiana. REGISTER TODAY.

Cryogenic processes for post-combustion capture also are attracting some interest. This pathway involves cooling flue gas to approximately -120 to -130 degrees F, which reduces volume by 98% and results in phase-change of gaseous CO₂ for removal from the flue gas. As a process similar to liquefying natural gas, it too requires significant megawatts of auxiliary electrical energy.

Another capture process involving sorbent adsorption technology is also used in power plant applications. This technology pathway is also used in direct-air capture systems. This process captures the CO₂ and binds it within the sorbent media until it is released via heating and then stored for transport or sequestration.

Membrane systems are another technology pathway. In this process, the CO₂ binds to the membrane and is released into a storage unit when saturated. The process requires high pressure and works best under conditions with high concentrations of CO₂. The auxiliary power requirements are not as high for membrane systems, though capture rates are somewhat lower, ranging between 60% and 80%.

The evaluation of any capture technology will depend on the type of plant it will serve and will have potential high auxiliary loads to consider. However, with the new tax credits and other incentives, high energy cost burdens may be offset.

Connecting the dots

Project elements must go beyond capture to incorporate separation, dehydration, compression, transport, geological sequestration or beneficial use.

For projects where a CO₂ injection field is not in close proximity to the plant, a pipeline component will be necessary. As we have seen in many states, permitting for new pipelines can be particularly onerous with objections over siting a commonplace obstacle. Eminent domain rights for pipeline corridors are uncertain at best, so carbon pipelines are a risk consideration for successful carbon capture projects.  

The sequestration component can also be complex. Both utilization of CO₂ for enhanced oil recovery and dedicated geological sequestration wells are incentivized by the IRA. The geology of a given region will dictate whether a Class VI well for geological sequestration is feasible. In an injection well, the CO₂ can transition to geospatial voids deep underground. In some geologic formations, the CO₂ gas may react with surrounding mineral deposits and turn into a solid that will be perpetually locked in place. A detailed geotechnical investigation will be necessary as part of the permitting process, as this is a highly location- and geology-specific determination.

Jurisdictional considerations will also be a factor in Class VI injection well permitting. Currently, North Dakota and Wyoming have obtained state primacy to approve wells instead of the federal EPA, with Louisiana anticipating primacy by end of the year. The EPA maintains jurisdictional authority within the remaining states, although Arizona, Illinois, New Mexico, Texas, West Virginia and others are similarly seeking primacy.

For states that defer to the EPA for Class VI well approval, the targeted permitting time by EPA staff is around two years; however, some locations may see much longer durations. This rigorous process will follow the established steps of feasibility and geotechnical studies, desktop simulations, public hearings and more. Unless expedited approvals become the new norm, it is likely that well permitting will become a limiting factor in determining how fast a carbon capture project can come online.

Start planning now

Regardless of the final form of this rule, we should expect some form of carbon capture to be possible in the future for large, frequently operated, combined-cycle natural gas plants. The financial incentives available under both the IIJA and IRA appear to hold potential to soften the blow and jump-start investment. The Section 45Q credits under the IRA give developers 10 years to begin construction of carbon capture projects (with commencement of construction required prior to Jan. 1, 2033) and will serve to generate lucrative tax benefits for 12 years of operation following that.

Though these units will often reach or exceed $1 billion of capital investment, there are many opportunities to value-engineer the design to optimize a number of processes. For example, opportunities exist for more efficient exhaust gas recirculation to allow higher volumes of CO₂ to be sent to capture units. This increases the CO₂ concentration in exhaust gas and allows for more efficient and cost-effective removal of the CO₂.  

Other design advances can improve constructability, making capture units easier to clone with standardized fabrication and on-site construction. With the enormous investment tied up in these vessels, even incremental efficiencies can pay off with big returns.

Utilizing hydrogen in future fuel blends also could be a consideration to drive further efficiencies. Tax credits for clean hydrogen production — either from methane reformation with carbon capture or electrolysis utilizing renewable energy — are available under the IRA’s Section 45V. This can lead to a complicated evaluation, however, as the IRS tax code does not allow for double-dipping to simultaneously take advantage of both a carbon capture credit and a hydrogen production credit.
The bottom line is we’re about to enter an interesting new era that will call for careful evaluation and due diligence to reap the rewards of new carbon capture investments in power facilities.

About the Author: Patricia Scroggin-Wicker is director of process technology for the Energy Group at Burns & McDonnell. With nearly 20 years of industry experience, Tisha helps lead initiatives focusing on new and emerging technologies, including hydrogen-fueled generation, flow batteries, carbon capture and other forms of long-duration energy storage. As a process engineer with deep knowledge of the regulatory landscape, she has become a sought-after resource within the power industry.

Originally published by Burns & McDonnell. More here.

The renewable natural gas (RNG) market is rapidly growing along with burgeoning interest in all forms of clean energy. Timing-based incentives for the market, such as those included in the Inflation Reduction Act of 2022, put a premium on designs that are adaptable, reliable, affordable and constructable.

Because RNG remains an emerging market, many owners and operators of RNG facilities are designing and developing them for the first time. Reliability is critical for RNG facilities — including biogas generation, upgrading and processing, as well as pipeline interconnects — because any downtime will require flaring of biogas, leading to additional emissions and loss of potential revenue. Keeping total installation costs low is also vital to justifying the business case for building a facility.

Building each new facility without consideration of previous or future projects is a recipe for inefficiency — both for the project and operations. By implementing a standardized design approach, owners stand to reap numerous rewards in terms of improved safety, lower costs and reduced project schedules.

Minimizing risks and improving safety

While the potential cost and schedule savings for natural gas facility projects has been discussed elsewhere, the safety benefits merit additional discussion. Any rework during construction of an RNG facility increases the potential for accidents. New designs are more likely to require rework due to unforeseen site conditions, unfamiliarity with vendor equipment and lack of established standards. Rework requiring additional welds, cuts and more manual labor exposes construction personnel to greater risk of injury.

Repeatable designs reduce rework in several ways. By incorporating modular design techniques, some piping sections can be identical across multiple designs, allowing shop fabrication of several blocks at once. Standardized designs can incorporate lessons learned from past construction phases, improving constructability over time. Because they use and reuse similar equipment and materials, repeatable designs support operator and maintenance familiarity, further minimizing risks. Uniform designs simplify those activities and boost efficiency.

4 steps toward standardization

The path to standardizing RNG facility designs will be smoother if the following four steps are kept in mind throughout the design and construction process:

• Collect high-level information. Planning is the key to successful standardized design. It is important to understand all variables, including the number of RNG facilities that will be planned, the locations and variances among sites, and operational preferences for each site. These details can be used to identify similarities and potential blocks or modules that could be standardized. This is also the right time to gather feedback from all operators and interested parties to understand their requirements for the facilities; waiting to get feedback later will negate some of the benefits of standardized design. It is helpful to create a construction schedule of all facilities within the program and identify groups of sites that can be constructed together. Staggering construction between groups enables implementation of lessons learned, leading to more efficient designs through iterative steps.
• Identify standardizable blocks. The next step is to identify elements that could be standardized across the facilities. Are there any piping configurations that could be identical across sites? Are there any pieces of equipment or materials that could be standardized across designs? If design conditions are similar between sites but not identical, are there options that could accommodate both sites? Once potential blocks are identified and agreed upon, they should be designed, reviewed and locked in.
• Create site-specific designs. Gather site-specific information for the first group of facilities and locate the blocks on the sites. It is useful to generate a list of requirements based on previously gathered feedback, then aim for alignment through plan or model reviews on a site-by-site basis. Take note of any similarities that could be used for a more efficient design in the next batch of facilities.
• Incorporate lessons learned. During construction, keep track of findings that could be incorporated into the next group of facilities. Plan to meet with all relevant parties to identify any additional changes needed. Upon achieving alignment, use strict change management procedures to update the standardized blocks for future projects.

RNG facilities represent significant investments. Those investments are increasingly being made as the market demand for cleaner energy intensifies. Developing standardized designs requires some upfront effort, but the benefits in terms of project cost, schedule and safety are well worth that expense.

About the Author: Phil Zsiga, PE, is a project engineer at Burns & McDonnell for pipeline and facilities projects. He has more than a decade of experience in mechanical and project engineering. His background includes work on RNG facilities, compressor stations, storage facilities, pipeline improvements, booster stations and dock improvement projects.

By Tisha Scroggin-Wicker, PE, Director, Process Technology, Burns & McDonnell

Carbon capture, utilization and storage (CCUS) technologies make it possible to prevent up to 95% or more of a power plant’s carbon dioxide emissions from entering the atmosphere. The Inflation Reduction Act (IRA) of 2022 established a significant revenue stream that carbon capture facilities can leverage, leading to a successful project economic pro forma.

Faced with renewable energy requirements and carbon dioxide (CO₂) reduction goals and mandates, utilities with aging coal-fired power plants or industrial hydrogen producers have had few choices other than to plan their plants’ retirements. Carbon capture provides an opportunity for these facilities to support decarbonization goals, generate lower carbon intensity power and reinvent their purpose by generating revenue through the capture of carbon.

Carbon capture technologies make it possible to remove CO₂ from plant emissions. Existing power plants retrofitted, and new plants outfitted with carbon capture systems have the potential to continue supporting jobs in their communities and extending their operating lives by a decade or more.

When installing carbon capture systems, utilities must consider how they will dispose of and benefit from the large amounts of captured CO₂. Currently, there are two predominant options. One is geological sequestration, which involves injecting the CO₂ into very large underground geological formations for permanent storage and sequestration. That means disposing of CO₂ as a waste product, which requires costly infrastructure and permitting, along with overcoming potential public opposition. This option is highly location-dependent, likely requiring a facility to be near the required geologic formation or a CO₂ transport pipeline to remain economically feasible. Leveraging existing or new pipeline networks for the transport of CO₂ is a potential transportation avenue. Securing permits for new CO₂ pipelines, especially interstate pipelines, has thus far been challenging but pipeline development continues to progress and advance.

Another option is to sell the CO₂ to the oil industry for enhanced oil recovery (EOR). Oil companies utilizing CO₂ for EOR are typically willing to pay for the CO₂, since they currently rely on natural CO₂ sources found underground. Captured CO₂ can be used to replace and supplement these resources. The potential supply of CO₂, however, greatly exceeds likely demand from EOR utilization. This option is also highly dependent on the proximity of the plant to CO₂ pipelines or oil fields with sufficient capacity to transport the captured gas.

Does the installation of a carbon capture system make economic sense? This is the question a growing number of utility and power producers are asking, and projects in development are expected to provide the answer.

DOE funding initiative

As a result of recent legislation, the U.S. Department of Energy (DOE) has been able to offer unprecedented levels of funding for carbon capture projects. Within the Infrastructure Investment and Jobs Act (IIJA) passed in 2021, the DOE allocated $3.5 billion combined for demonstrations and pilots along with $2.5 billion for the development of large-scale carbon storage commercial projects. Additionally, $310 million for carbon utilization applications and $100 million for technology and front-end engineering and design (FEED) projects were allotted.

Additional funding was made available through IIJA for direct air capture (DAC), involving $3.5 billion for multiple hubs across the country to capture and either store or make use of CO₂. Prizes worth $115 million are also obtainable in technology competitions for creative processes seeking to develop DAC as a viable approach for carbon removal.

To jump-start the commercialization of carbon capture technologies, the DOE recently announced $189 million in available awards for nine FEED studies associated with carbon capture demonstration projects. These studies involve an assortment of carbon capture technologies and sites, including coal, integrated gasification combined-cycle, natural gas combined-cycle, cement and cogeneration facilities. DOE funding has been earmarked for projects designed to accelerate the deployment of existing carbon capture technologies and the development and refinement of new ones, as well as the assessment and verification of commercial‑scale CO₂ storage. By deploying a variety of large-scale CCUS pilot and demonstration projects, the DOE expects to build the knowledge base needed to test and further prove the viability of carbon capture technologies on a commercial scale.

45Q tax credits

The new 45Q tax credits set forth in the IRA of 2022 form the economic engine propelling this market forward. Section 45Q of the Internal Revenue Service tax code has been substantially updated to increase incentives per metric ton of CO₂ to $60 for utilization or EOR, and $85 for sequestration, if apprenticeship and prevailing wage requirements are met. The minimum carbon capture requirements that power plants need to meet to be eligible for these tax credits include capturing at least 75% of CO₂ emissions and 18,750 metric tons of CO₂ annually. Similar to the 2018 update, these credits would be accessible for 12 years after a project begins operation. DAC sites must capture at least 1,000 metric tons of CO₂ annually in order to qualify for tax credits assessed per metric ton of CO₂ that are $130 for utilization or EOR and $180 for sequestration if applicable conditions for apprenticeship and prevailing wages are reached.

The IRA also provides the option for these tax credits to be issued through direct payments to for-profit entities (for up to five years after the initial operation date) and tax-exempt organizations (for up to the full 12 years after the initial operation date). Additionally, there is potential for transfer or sale of part or all of these tax credits.

The 45Q rule lays out the relevant qualification requirements. To receive the tax credit for geologic storage, a utility must meet the U.S. Environmental Protection Agency’s (EPA) sequestration reporting rules (40 CFR Part 98, Subpart RR), which include a monitoring, reporting and verification plan that documents the amount of carbon injected and stored. Entities seeking credits for EOR have the choice of satisfying either EPA regulations governing geological CO₂ sequestration or the CO₂ storage guidelines developed by the International Organization for Standardization (ISO) and the American National Standards Institute (ANSI) (CSA/ANSI ISO 27916:19).

The rules also outline that the IRS can recapture the credit if the carbon is intentionally leaked or withdrawn from storage. Once the carbon capture system begins commercial operation, the IRS can reclaim the credit up to the earlier date of three years after the date the tax credit is last claimed or the date when monitoring ends.

Together, these 45Q changes make implementation of carbon capture technology a more economically attractive proposition for utilities while not limiting the industry with a tax credit cap. There is, however, a catch: To be eligible, construction of these projects must commence by Jan. 1, 2033.

Carbon capture and storage technologies

Utilities and others contemplating post-combustion carbon capture projects have several options to choose from that are in varying stages of development. Processes in this space include membranes, adsorption with solid state sorbents, cryogenics, enzymes and chilled ammonia. Absorption through liquid solvents, primarily amines, is the most common carbon capture method currently being assessed and deployed.

Originally developed in the 1930s, amine technology has been used for decades in a variety of applications, including post-combustion carbon capture. Amine processes have become the primary method used by power plants, with proven capabilities of removing 95% or more of CO₂ from emissions. Amines are chemical solvents that undergo a reversible reaction with CO₂ and other acidic gases. During the amine-based process, when exhaust gas containing CO₂ comes in contact with a liquid amine solution, the CO₂ chemically binds to the amine molecules and is removed from the gas stream. This amine solution can be pumped into a separate column where heat is used to reverse the process, stripping the high-quality CO₂ from the amine. The CO₂ can then be compressed for EOR use or injected into a suitable geological formation for storage.

Many DOE-funded carbon capture projects to date employ amine-based processes. The differences between individual processes are primarily in their “secret sauce” — the proprietary chemicals used to increase the efficiency of the amine solution. Researchers continue to seek solutions that reduce the amount of auxiliary power and water amine-based systems need to capture and recover carbon, as well as the volume of steam and heat these processes consume during regeneration.

Efforts are also underway to minimize their relatively high capital, operating and installation costs. Non-aqueous solvents (NAS) are emerging as potential avenues to lower steam and auxiliary load demands of these facilities by utilizing less water in the capture process. Applying lessons learned in research and operational settings will support future advancements with these and other carbon capture technologies.

Opportunities and challenges ahead

Operators of power plants will need to determine not only the right carbon capture solutions for their operation, but also how to efficiently integrate them into their existing systems. Current carbon capture technologies can potentially impact power generation operations and efficiency. An experienced integrator that understands power plant operations and can model carbon capture processes is essential to minimizing potential power production losses and identifying opportunities for process optimization.

Before CCUS systems can be fully commercialized, additional challenges must be addressed:

• Reduced capacity factors — The economic feasibility of a carbon capture facility depends on the relative amount of CO₂ captured from the flue gas that can generate an adequate revenue stream. As a result, the carbon intensity of the plant is reduced, which increases the value of the electricity generated at the site for consumers looking to decrease their carbon footprint. This poses special challenges to coal plants facing reduced run times in areas with high renewable energy penetration. Since the early 2000s, the capacity factor of many coal plants has dropped significantly, reducing the economic benefit of the capital investment by over half in many cases. A retrofitted plant may be economical to bid into power markets at similar negative power prices as wind currently enters the market.
• Sequestration vs. EOR concerns — Given the increase in 45Q tax credits, power plants appear at first glance to have the most revenue to gain by sequestering recovered CO₂ in geological formations. But that may not be the case, as power plants that can obtain additional incremental revenue selling captured CO₂ to an EOR off-taker have the potential for similar or greater total revenue generation. Plants located near oil fields are likely in a better position to market their captured carbon for EOR use than those that must transport it hundreds of miles or more for sale.
• Competitive markets — Independent system operators (ISOs) recognize the potential impact CO₂ reduction strategies can have on the competitive markets the ISOs design and operate. Those markets optimally run with minimal out-of-market influences, such as subsidies or carbon taxes. ISOs, however, must also create markets that properly reflect the economic impact of state and federal regulations, even without the benefit of any oversight of those regulations.
• Pathway to blue hydrogen — CCUS provides a pathway to reduced carbon emissions for a variety of industrial processes. In the context of conventional hydrogen production methods, CCUS gives existing hydrogen producers the option to invest in a reduced-carbon future via blue hydrogen. CO₂ from combustion heating processes can be captured using various technologies from these point sources before being utilized for geologic sequestration, EOR, fertilizer synthesis or commercial use. In general, CO₂ is collected, then separated in a cleanup step, transported and delivered to end users.
• Regulatory support — Identifying and understanding the requirements of the relevant governing permitting entities is a crucial part of the development process for CCUS projects. The EPA governs CCUS permitting on the federal level, which applies to states without primacy, or the ability to manage their own permitting programs for geological sequestration. North Dakota, Wyoming and Louisiana have received primacy approvals from the EPA, which allows them to administer their own CCUS permitting systems within their respective states. Additional states are involved in various stages of the EPA’s primacy application process. It is also important to note that 45Q requires a monitoring period of geological formations for any leaks that may occur where vested parties could be liable for reimbursement of investment tax credits to the Treasury department. Awareness of the intricacies associated with CCUS permitting and monitoring is key to optimizing value in the set up and operation of CCUS facilities.

Despite its challenges, carbon capture has substantial political, regulatory and academic support that will likely continue to be incentivized through federal legislation, DOE support and state mandates. This provides opportunities for new plants to be designed with carbon capture capabilities in mind and existing sites to have a second life as carbon capture facilities.

The project will be Basin Electric’s largest single-site generation project since the 1980s. It will include two Siemens STG6-5000F simple-cycle combustion turbines and six Wärtsilä W18V50SG reciprocating engines.

Basin Electric said preliminary estimates place the budget at approximately $780 million, which includes both generation and transmission assets. The co-op said load forecasts have showed the need for more electricity by 2025 to serve the Bakken region’s rapidly growing demand.

Burns & McDonnell is the EPC for the project.

Identifying the right options for the decommissioning and demolition (D&D) of a power plant requires extensive upfront planning and coordination. Special permits are likely needed for everything from demolition and waste disposal to asbestos abatement and stack lighting. Utilities and other energy sources may need to be isolated.

The project scope will need to be clearly defined to minimize changes so that activities stay within permit requirements and budget. Through it all, expectations will need to be managed as utilities coordinate with a range of operations, safety, security, environmental and management stakeholders.

D&D projects typically follow a three-phase process. Critical components of this process include assembling a team to carry out the decommissioning project from start to finish, as well as identifying common challenges utilities can expect to face — and work to avoid — along the way. Utilities must also understand the processes essential to bidding and implementing the project safely and within budget.

Phase One: Plan development

Assemble a project team

A power plant D&D project team typically includes representatives of the utility’s own in-house project team, the specialty engineering team and those involved in stakeholder engagement. The utility’s own in-house project team is responsible for determining the project scope and defining the end-state conditions for the site when decommissioning is complete. This may include engineering, operations, energy delivery, security, safety, telecommunications, environmental, real estate and legal services. The specialty engineering team uses the retirement scope to define the permitting and technical requirements that will be used to develop bid documents. Those involved in stakeholder engagement are responsible for presenting the D&D team’s conceptual approach to outside stakeholders, including government and environmental agencies, and obtaining feedback prior to implementation.

Select a retirement model

One of the D&D team’s most consequential decisions is its choice of a retirement model for the project. A variety of economic factors drive power plant retirements. Long-term cost, safety and environmental considerations typically influence a utility’s decision on whether to demolish the decommissioned plant or retire it in place until demolition can occur at a future date.

When a utility chooses to retire a plant in place, it retains ownership of the property and facilities. While lower in upfront costs than demolition, a retire‑in‑place plant accrues security, maintenance and other expenses over time. This option is generally preferred by utilities with multiple units at a plant, each on a different retirement timeline due the cost of isolating and removing individual units.

With a full demolition approach, all plant assets are demolished and removed from the site. The approach offers the benefit of fixed, upfront capital costs, while also making it possible to sell the site and assets, such as scrap metal. It also opens the door to potential redevelopment or new power generation at the site.

Conduct a regulated materials assessment

Before selecting a retirement model, it is important to conduct a thorough assessment of regulated materials at the plant. Asbestos, mercury, PCBs, chemicals, toxic gases, fuel, refrigerants, and lead-based paint are among the regulated materials that are often found inside and outside these facilities. Mercury can be found in fluorescent lamps, some switches and thermostats, heating and cooling equipment, gas ranges, and barometers. The quantity and location of asbestos and other materials can significantly impact plant retirement costs.

FIGURE 1: Retirement in place versus full demolition cost estimate.

Retrieve critical facility information

This is an appropriate time to collect facility construction drawings, environmental reports, permits and lists of construction materials — all of which will be valuable when project development begins. Information gathering will likely also include interviews with on‑site operators and maintenance staff to obtain institutional knowledge of historical site conditions and changes, as well as other information not shown on construction or as-built drawings. Interviews can help identify the locations of spills, underground tanks or other environmental concerns not included in reports. Staff may also be able to offer insight on the alloys used in retrofitted boiler and condenser tubes that may bring greater scrap value.

Determine permit requirements

D&D projects require multiple permits, including those for asbestos abatement, demolition, stormwater management, Federal Aviation Administration (FAA) lighting on stacks, and intake/discharge closure on rivers or lakes, among others. Both the budget and schedule can be impacted by these requirements. It is imperative to understand both the technical requirements that may be imposed by a permit as well as the expected timeline to issue the permit.

Develop a cost estimate

Prior to moving to the next phase of retirement, a planning level cost estimate should be developed to understand the costs of the planned activities. It can also be used to determine which approach will be used. All of the information obtained during this phase is central to the development of a detailed cost evaluation comparing retirement options over a specific time frame.

Figure 1 shows an example plant cost estimate for a retire‑in‑place approach that would save the utility approximately $6.5 million in the first year, compared to demolition. By year six, the cost for retirement would be equal to initial demolition. By year 10, however, the utility will have paid $5 million more for retirement in place than it would have paid had it demolished the plant at the start, principally due to ongoing costs for maintenance, security, insurance and taxes.

Phase Two: Scope development

Define the scope of retirement model

The scope of work for a D&D project can vary dramatically, depending on the retirement model chosen. The scope of retire-in-place projects will depend on the results of an evaluation of utility interties among the units or facilities that will remain on-site, among other factors. An assessment must also determine if remaining fire protection, sanitary and stormwater sewers, communications systems and other utilities should be isolated when not needed, and if new utilities are needed to support ongoing site activities. The scope must also account for the relocation or rerouting of utilities that pass through retired units.

Retire-in-place projects require baseline and periodic inspections of stacks/chimneys. These inspections are essential for maintaining long-term safety and regulatory compliance. The results of baseline inspections, in fact, may prompt renewed consideration of at least partial demolition, if not the full demolition alternative.

Ongoing site security requirements should also be assessed, including the need to secure doors, perimeter fencing, security cameras, a security force and other solutions to prevent unauthorized access and protect the public and environment from potential hazards.

Define the scope for demolition

Demolition projects involve removing all assets and structures from the site and remediating and restoring the site for potential reuse. The utility must first determine how the site will be left following demolition; for example, if foundations will remain in place or be removed and be replaced with a gravel or vegetated surface.

Because the property may be repurposed or sold after demolition, project development should consider current property assets. Rail access or spurs to a main line may be beneficial for shipping when redeveloping the site. Highway access may signal a site’s potential as an intermodal facility. If the site offers waterway access to a river system, it may be able to be leased or repurposed by a new owner for barge loading and unloading. Site location could be a valuable benefit since it can be difficult to obtain permits for new facilities. Similarly, if a utility has water rights, it should assess its water intake/discharge structures and permits.

Access to transmission lines is another important asset that creates the potential to repower the site with combined-cycle, simple-cycle, reciprocating engine or other type of power generation that could be used to power new generation facilities at the site. However, repowering can be limited if natural gas is not available within a reasonable distance.

Owners undertaking facility demolition must also identify any utility interties with units or facilities that will remain at the site, determining whether utilities are no longer needed and if they need to be isolated. Projects should identify if any new utilities are needed to support ongoing site activities, as well as whether utilities running through-units slated for demolition should be relocated or rerouted.

Potential environmental liabilities also must undergo evaluation. Coal piles may require removal of residuals and capping. Landfills may need to be consolidated and capped, and coal ash ponds may need to be closed in place or removed.

An overall grading plan will be needed for final site restoration. The plan should be designed to promote drainage without producing point source discharges.

Research local ordinances and permit requirements

Regardless of the retirement approach, it is important to identify and communicate information regarding local ordinances and permit requirements that could impact how bidders complete the work. This includes demolition requirements and permits needed to perform demolition or to work on or near bodies of water. Special permits may also be required for stack lighting or temporary lighting during demolition. Utility abandonment requirements and stormwater pollution prevention plans should also be communicated.

Develop bid documents

Comprehensive D&D bid documents should make it easy to evaluate and compare bidders and reduce the potential for change orders. These documents can also be used as the project plan for successful implementation. High-quality bid documents include all site and facility information and a clearly defined scope of work that minimizes ambiguity and enables a true comparison among bid responses.

The clearer the scope definition, the fewer contingencies that result. That is why bid documents should also include optional scope items or unit pricing for activities that may arise during the project. For example, projects should seek unit prices for asbestos abatement in stacks, boiler refractory and underground piping.

Unit prices for soil removal and other items may also be helpful, as will costs for alternate items, such as additional building removal, that may be added later. Labor and equipment costs need to be included during the competitive bid process so that these rates can be used as a basis for evaluation of change orders during implementation.

Upfront knowledge of these costs allows the owner to control costs and mitigate potential change orders using the competitive bid process, rather than after the project begins.

Phase Three: Project implementation

Prequalify contractors

Prior to determining which contractors receive requests for proposals (RFPs), it is imperative to prequalify potential bidders to identify contractors qualified to conduct the work. Prequalified contractors include those that have experience with projects of similar size and scope, as well as a good safety record for the three previous years as demonstrated by their experience modification rate (EMR), total recordable incident rate (TRIR) and days away, and restricted or transferred ratings (DART). The experience of the contractor staff assigned to the project also matters, as does the availability of the experienced project teams and equipment.

Identify key contractor personnel

Owners should include a full-time, on-site safety manager and superintendent among the key personnel required by the RFP. Any safety manager candidate should be a Certified Safety Professional (CSP) or Associate Safety Professional (ASP) with a minimum of five years of experience on similar projects and no other responsibilities at the site. Likewise, the superintendent’s sole focus should be on directing and conducting the work safely and effectively. Candidates should have experience with similar projects and be able to oversee both abatement and demolition activities.

Develop a preliminary execution plan

Bids are most meaningful and helpful when they arrive with preliminary execution plans that include a proposed methodology and the types of equipment to be used for activities such as abatement and demolition. These plans should describe the sequence of activities to be performed for abatement and demolition, as well as identify any zones that will be excluded from demolition activities. Information like this enables the D&D project team to determine if the contractor has prepared a site-specific bid and has a clear understanding of the expectations described in the bid documents.

Evaluate bids

Bids should undergo both technical and financial evaluations. The technical evaluation should assess each bidder’s project understanding, as addressed in its execution plan. The past three years of safety performance for subcontractors proposed for the project, along with subcontractor and project team experience on similar projects and the proposed schedule, should also scrutinized. The financial evaluation should involve not only the base bid, but also scrap credits, unit prices and alternates, with the goal of identifying overall project costs.

Prepare specific execution plans for major activities

Before major activities get underway, the contractor should be expected to provide execution plans for specific activities, including the demolition of boilers, coal bins, turbine halls, precipitators and other large structures. Pick plans are also needed for lifting equipment or structures, as are building or stack implosion plans. These plans should provide the sequence of activities, safety plans and procedures, any work exclusion zones, removal methodologies and contingency plans.

A licensed structural engineer should either develop or review proposed major activity plans to confirm that the proposed approaches can be accomplished safely. Prior to the start of a major activity, the utility, contractor and engineer should meet on-site to review the plan and set expectations for the results.

Isolate utilities

Utilities must be safely isolated prior to any demolition activities. The lockout/tagout method of isolation is not appropriate for these projects. Instead, owners should insist on a permanent “air gap” method because it provides visual evidence that isolation is completed. This method allows the contractor to confirm that both electrical and mechanical systems are no longer energized or pressurized prior to beginning demolition work.

The contractor should be expected to verify that all systems are de-energized by the owner prior to demolition. Written documentation of the isolation and verification should be signed off on by both the owner and the contractor.

Structure removal methods

There are multiple ways to clear structures from a site. They can be pulled over, tripped by their legs, mechanically sheared or imploded. High-reach shears, backhoes and other equipment can be used to support removal. Whatever methods are employed, safety plans must provide protocols that address the potential for materials to drop on equipment and operators as well as adjacent structures.

In cases where all or parts of structures are to be imploded, adjacent structures will require protection. A safe buffer area will need to be established and adjacent property owners will need to be notified. Coordination with those who could be impacted, as well as local police, fire and other emergency staff, is essential. Traffic control plans must be in place for before, during and after the implosion to prevent bystanders or others from entering into a blast zone. A dust control plan is also needed for the large amounts of dust generated by the implosion process.

Establish on-site field representation

Successful D&D project implementation requires full‑time on-site representation either by the owner or engineering firm. Throughout the process, an on-site field representative should be expected to provide the owner with independent verification and documentation of contractor activities. The person holding this position is responsible for reviewing contractor invoices, tracking and confirming proper waste disposal and verifying that contractor staff have secured any required certifications, such as those for asbestos abatement.

The on-site field representative’s responsibilities also include participating in daily safety meetings and notifying the contractor and owner of any unsafe situations or safety plan nonconformance. The representative is tasked with observing on-site demolition activities for conformance with the execution plans and developing a final report that assembles all documents, manifests and results in one place.

Summary

Developing a high-quality power plant retirement plan requires the cooperation and coordination of any parties. Most importantly, it requires:

• A plan development phase where a project team is organized, the property’s end use is determined, regulated materials are assessed and a cost analysis of retirement options is developed.
• A scope development phase when property assets are inventoried, permit requirements are identified, utilities are isolated and comprehensive bid documents are developed.
• A project implementation phase when contractors and subcontractors are prequalified, plans for major activities are prepared and utility isolation and on‑site field representation are executed.

This White Paper was republished with the permission of Burns & McDonnell. Link to paper here.

By Josh Massa, Associate Structural Engineer, Burns & McDonnell

See more on the company’s White Paper here.

The U.S. Energy Information Administration (EIA) estimates that the nation’s battery storage will reach 30 GW of capacity by the end of 2025, a stark increase from the 7.8 GW operating in 2022. The surge in battery energy storage systems (BESS) correlates with the need to stabilize the variability of solar and wind on the grid and provide for the retirement of baseload fossil generation as the renewables revolution continues.

Things are looking up

From the onset of the battery energy storage boom, BESS projects have been located in areas where land was readily available, market conditions were favorable, and building out and not up was the way. The result is that California and Texas currently make up more than 75% of today’s battery storage capacity nationwide. For these states, the abundance of land made BESS installations an attractive approach to harness the existing renewables developed to see that power was available when needed. 

While the demand for energy storage continues to increase, the spatial availability for new projects is finite. On the U.S. East Coast, states such as New York, Massachusetts, and Virginia have established energy storage targets that require storage solutions. These mandates will require battery energy storage systems to be installed in urban areas where many of the installation requirements are different from those BESS facilities that have been located in open areas.  Additionally, there is a growing movement to place battery storage projects near urban load centers where BESS installations can be used to address power quality and reliability at the local level.  As a result, many project stakeholders are considering how to handle BESS installations in densely populated areas. 

Unlike BESS projects in wide-open spaces developed horizontally, BESS projects located in urban areas must consider a new approach. Most urban areas do not have the luxury of space and high property costs. To meet urban utility energy demands, utilities and developers will need to look to vertically orientated BESS to address the challenges and demands of the growing energy storage market. 

Vertical BESS project planning

Whether installing BESS in an open area or a multi-story building, the components are similar but the challenges of executing the installation are very different. Unlike a vacant plot of land for conventional installations, BESS projects in urban areas must deal with space constraints, additional regulations, and a closer relationship to the public. 

All projects benefit from early, and upfront analysis and clear decision making and a building-based BESS project is no different. However, as developers explore urban BESS project development, there are several unique challenges that a building-based vertical BESS project presents, which should be carefully considered.  

Constructability  

Finding viable properties, buildings or land for BESS projects in urban areas near an interconnection point is an essential but challenging first step in the development process.  Potential properties should be located nearby or have relative access to an interconnecting point to the area grid, have favorable zoning requirements, and sufficient space for construction of a BESS facility.  Use of existing structures may be limited due to requirements for BESS facilities such fire protection, thermal management, and structural capacities.  Many times, existing structures may need to have significant retrofits completed or need to be demolished and new purpose-built BESS facilities built in their place, adding to the construction complexities and costs of development.   

When considering multi-story BESS installations, materials of construction must be considered, along with potential logistics related to how the construction will be completed.  These include use of steel vs. concrete structures for fire protection, available crane space for building construction, timing of construction deliveries, and impacts of local zoning requirements on building size and heights.  Future operation and maintenance considerations such as access ways and crane/lift access for augmentation and replacement of BESS components must be considered.  Additionally, selection of the BESS product and the specific requirements for installation as well as operation and maintenance space need to be considered in the layout of the building and the supporting ancillary systems – including the routing and location of thermal management systems, electrical collection systems, and ventilation.   

Considerations such as maximum allowable quantities (MAQs) and maximum probable loss must be considered when considering building layouts to facilitate the advancement of the project through the development and permitting stages.

Safety considerations 

BESS projects should focus on safe operation and management of the facility, including comprehensive safety systems developed in coordination with the applicable authorities having jurisdiction (AHJs) to allow for a safe response to an emergency. Whether looking to adapt an existing facility or new construction for a challenging site, technical challenges are present to provide these comprehensive safety systems. The complexity of segregating kilowatt groupings into MAQ zones, understanding structural fire ratings, designing for confined spaces, limited egress and securing fire marshal approval are increased. Consideration must also be given to the operations and maintenance impact on smoke and gas detectors, fire panels, fire suppression systems, ventilation systems, and testing and inspection schedules. Having defined and sufficient egress paths within and around the BESS facilities are also key to providing for safe operation.   

The nature of battery energy storage presents unique risks compounded in a size-restricted space. Preparing project risk analysis and assessments such as hazard mitigation analysis (HMA) and failure mode and effects analysis (FMEA), should drive site design and enhance project safety systems.  Collaboration and coordination of all the project stakeholders will be key to a successful and safe application.  

While designing a BESS for fire protection is a key design priority, consideration must also be given to the insurability of the site.  Design aspects such as spacing of adjacent BESS racks/enclosures and segregation of areas for limitations on maximum probable loss impact the overall site layout and resulting installed energy site capacity.  Careful consideration should also be given to the selection and design of an appropriate building-based suppression system.   

Thermal management 

The safe operation of any BESS asset requires efficient management of the surrounding ambient environment as operating of battery modules outside of prescribed temperature ranges and air flows can be detrimental to the BESS, resulting in an increased possibility for a thermal runaway event.  An effective thermal management program, including mechanical cooling, heating, and ventilation, aids in maintaining operating stability while maximizing safe battery performance.  

Building-based and vertical solutions pose significant challenges to mainlining sufficient ventilation and cooling due to proximity of adjacent units and the aggregation of the exhausted heat.  Air flow modeling, including computation fluid dynamics (CFD) studies, should be completed to confirm sufficient air flow and temperatures are provided.  Additionally, the compact BESS solution of a building or vertical application open the door for centralized solutions for battery cooling such as DX air-handing units or central utility plants.  The use of direct expansion (DX) air handling units that use refrigerant liquid for cooling battery cooling represent a less expensive initial installation but can become increasingly inefficient over time. Central utility plants (CUPs) use large centrifugal chillers that distribute cooled water across multiple locations and buildings. A proven technology, CUPs offer the potential for added redundancy and greater operational flexibility and efficiency.  

BESS thermal management design options also include rack placement, equipment located in different heat zones, hot/cool aisles for air distribution and more. A thermal management approach must be determined early to safely maximize space and efficiency for building-based solutions. 

Operations and maintenance 

With every design decision for a vertical, building-based BESS comes the evaluation of operations and maintenance impacts. The analysis may be at the module level or focused more holistically across the site. Consideration should include the broader operation and maintenance of replacing modules, transformers, and inverter components within the confined area of a building where the utilization of large, heavy equipment may not be practical.  Providing sufficient maintenance areas around the BESS equipment and a “path to ground” are key considerations.   

As battery performance degrades over time, BESS augmentation, where additional battery capacity is added as the overall system ages, requires additional review during the early planning process for building-based BESS installations. How the BESS augmentation will be completed over the life of the system, including provisions for how augmentation units will be located and connected to the initial BESS ancillary systems, should be studied to confirm a constructable augmentation exists.   

All BESS projects must evaluate the operating conditions for each site. Storms, flood risks, and humid, salty coastal air can affect how the equipment will operate and can tolerate before maintenance is required. To maximize effort, the development of an operations and maintenance program should be evaluated in tandem with design, safety and equipment decisions. 

Permitting and public support  

Developers of building-based vertical BESS projects must plan on the engagement of local authorities, planners, fire departments and the local community from the early outset of the project.  

Urban centers revolve around zoning restrictions that can cause unexpected project constraints. Zoning review boards can surface challenges that might have otherwise been avoided with early engagement and planning. Local press reporting development inaccuracies can derail progress. Project planning that includes, engages and communicates with the project’s wide range of stakeholders stands a better chance of success. Similarly, paying attention to project aesthetics, such as screening, architectural features and landscaping, before being asked may make a difference to the surrounding community. 

Conclusion

Going vertical with BESS projects may be the future for energy storage. While there are benefits in dealing with a smaller footprint, there are more challenges with this type of project. Because of the inherent constraints they are facing, developers can gain an advantage by partnering with an organization experienced in the planning, design and execution of BESS services.  Burns & McDonnell has been involved in the construction of two building-based BESS projects and have been involved in the review and planning of several others, including single-story and multi-story applications.

The Robert D. Green Generating Station in Webster County, Kentucky now burns natural gas instead of coal after a recent conversion project.

The 500 MW Green plant is part of the Sebree Generating Station, owned and operated by Big Rivers Electric.

The electric co-op was required to stop using the site’s two coal-fired units by June 2022 in order to comply with environmental regulations.

Big Rivers partnered with Burns & McDonnell for the plant conversion. Burns & Mac served as the project development and detailed design engineer for the project.

The scope included project management and controls, project development and cost estimating, equipment specs, contract management for equipment and construction contracts, design of the installation packages, construction management, and startup and commissioning.

The EPC said existing systems were used to generate full capacity with minor modifications to the ductwork and windboxes without a need for pressure part replacements or a flue gas recirculation system, while still achieving steam temperature.

Green Generating Station was commissioned in the 1970s.

Engineering, procurement and construction firm Burns & McDonnell was selected to provide EPC services for a standalone battery storage project in Scurry County, Texas.

Texas Waves II is a 30 MW/30 MWh lithium-ion battery storage system that is expected to be online by the end of 2022. The project is being developed by RWE Renewables.

The project will consist of CATL EnerOne battery racks, populated with lithium iron phosphate (LFP) battery modules. Besides providing engineering services for the project, Burns & McDonnell will self-perform installation of the racks, medium-voltage power station (MVPS) and all balance of system (BOS) equipment.

The scope of work provided by the firm includes furnishing custom-designed AC auxiliary panels for battery management system and chiller power. Burns & McDonnell will also provide modifications to the existing collection substation, including installation of a new 34.5-kV vacuum breaker, interconnection details, protective relaying and metering upgrades.

The system would connect to a key local substation that collects renewable energy from the co-located existing Pyron wind farm.

Texas Waves I, which consists of two 9.9 MW short duration energy storage projects and located at the existing RWE Pyron and Inadale wind farms in West Texas, came online in 2018.

The company has more than 30 projects in operation in the U.S., totaling an installed generation capacity of more than 5,000 MW to date.