Download the presentation from CANUSA EPC’s Carbon Capture Feasibility From Compressor Exhaust Streams Conference Knowledge Bar. Content includes:
The development of carbon capture, utilization, and storage (CCUS) projects presents unique opportunities and challenges for investment firms looking to deploy capital into the carbon capture space. CANUSA EPC, with its extensive experience in evaluating and developing carbon capture projects, offers valuable insights and strategies to navigate this complex landscape.
Determining the internal rate of return requires accurate Capital Expenditures as well as Operational Expenditures to determine the levelized cost of capture and transport of the CO2.
The CapEx for the facility encompasses the construction of the capture process to provide the CO2 product. A large portion of CO2 project equipment costs will be tied up in compression equipment. Typically, large compression systems are custom-fabricated and require specialized services that are not readily available. Instead, CANUSA EPC recommends deploying compression systems with smaller units in parallel designs. This solution is more likely to:
The OpEx to run the facility is predominately based on power consumption. There are important strategies to ensure the facility runs efficiently and power costs are structured appropriately. VFDs and soft starts can be used in combination to lower demand spikes and electricity bills. Read more about electrical drive approaches.
Technology Development for CO2 Capture
Capturing CO2 from sources with higher concentrations of CO2 (greater than 8%) leads to lower separation costs and less energy consumption. High concentrations of CO2 present de-risked capture technology, as they can rely on traditional methods. Recent technological deployments for engine emission applications are trending towards $40 per metric ton of CO2. CANUSA EPC highlights that CO2 emissions from amine plants and ethanol facilities are relatively pure and can be economically delivered to pipeline or beverage grade specifications. Read a detailed case study: CO2 Injection & Amine Emissions Capture.
Transportation: Best By Truck, Rail, or Pipeline?
Transporting CO2 from the capture site can be done via truck, rail, or pipeline, similar to oil or bulk goods. Trucking is suitable for smaller projects, topping out around 150 metric tons per day (MTPD) due to logistical complexities. Rail applications are viable for projects approaching 400 MTPD when there is an existing train line near the facility. Pipelines are the most efficient way to transport large amounts of CO2 to hubs for injection or distribution to industrial users. CANUSA EPC advises focusing on injecting CO2 into saline reservoirs close to the emitter source in states with primacy over Class II injection wells, as these projects are quicker to approve1.
What Government Incentives are Applicable to CO2 Capture?
The long-term commercial use of CO2 as an emission removal tool is still developing. Government programs, such as those funded under the Inflation Reduction Act (IRA), support many active projects through reimbursement programs like 45Q or 45Z. CANUSA EPC emphasizes the importance of executing projects in a manner that meets IRA requirements to take advantage of these incentives. This approach provides flexibility to adapt to any changes in the program. Read more about rebates for your project.
Approaching Carbon Developments Wisely
To successfully navigate the complexities of CO2 project development, it’s crucial to consider:
By implementing these strategies, investment firms can enhance the efficiency and profitability of their CO2 projects while contributing to a sustainable future.
Let’s work together to help build a financial model for your CO2 project. With just a few data points, we will provide a report that will bring clarity to your project’s feasibility – request a free Class V Estimate.
Source: 1 https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0
Managing water in CO2 streams is critical to avoid corrosion, downtime & delays. A dehydration study provides an analysis to select the proper technology to mitigate risk & meet project goals. Dehydration technology selection often involves trade-offs between cost, efficiency, and future expandability.
A comprehensive and unbiased study gives you the confidence to choose the right solution without surprises. What factors are essential in a valuable dehy study? Read more inside.
CANUSA EPC has prepared the following analysis related to the feasibility of carbon capture from the exhaust streams of natural gas driven compressors at a compressor station located in North America. This analysis is based on CANUSA EPC’s experience with carbon capture technologies, applying those existing technologies to exhaust gas from post-combustion processes, and leveraging our project expertise with compressor stations.
The basis of the analysis considered 27 metric tons per day (MTPD) from a single engine unit, 189 MTPD from seven (7) units, and 300 MTPD with an exhaust stream of 5.59 mol % CO2. Available technologies allow for a recovery of 90 mol % CO2 and a purity of 98 mol % CO2. The findings of the white paper identify the normalized value of CO2 for the various flow rates to develop the economics of these projects. *Based on 2023 industry developments.
Excess water in CO2 streams can lead to severe project risks, including equipment failure, blocked pipelines, and compromised system integrity. Without accurate data and a clear strategy, saturated CO2 can cause significant operating challenges. Technology selection during a CO2 injection project impacts profitability, safety, and longevity. A comprehensive CO2 dehydration study is the key to preventing these risks. It provides the clarity you need to make informed technology decisions, ensuring your operations remain safe, reliable and efficient.
Excess water in CO2 streams poses significant risks, including:
Water content targets typically range from 10 ppm to 50 lb/MMscf, depending on your transportation strategy, materials selection, and injection goals. For projects involving long pipelines or stringent injection requirements, managing water content isn’t optional—it’s essential.
The right dehydration study transforms uncertainty into clarity. It will provide actionable insights to guide your project and give you confidence with decision-making.
Here’s how:
Selecting the right technology depends on your project’s specific needs. A breakdown of common options is below:
* Detailed characteristics have been compiled for each of these technologies and are available for review by downloading the full dehydration paper.
In a recent CO2 injection project, CANUSA EPC was asked to evaluate dehydration options for reducing water to a 25 lb limit in the gas stream prior to injection.
The framework of their evaluation can be considered a minimum viable standard for dehydration analysis.
The following dehydration solutions were evaluated to determine which technology would best meet the client’s requirements:
The result?
*A detailed comparison table is available for review by downloading the full dehydration paper.
In this client’s case, DEXPro stood out for its integration capabilities, environmental efficiency, and alignment with the client’s sustainability goals.
Access the comparison of key technologies presented in this article by downloading CANUSA EPC’s paper.
Click here to download: Maximize Efficiency & Reliability in CO2 Injection
Embarking on a CO2 injection project without a dehydration study is like flying blind. Start with this critical step and ensure the dehydration study follows the framework within the paper – before assembling your project team.
PAPER AUTHORS:
Tevin Champagne, Project Manager
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Josh Hoeft, Project Manager
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Nick Brown, Project Engineer
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Ted Zeiger, PE, Project Engineering Lead
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The Inflation Reduction Act (IRA) has been an active policy since August 16th, 2022. As the law has evolved, navigating this laws requires an understanding of how to structure projects to meet the requirements. Requirements for Inflation Reduction Act CO2 projects are governed by two sections of the law. 45Q covers the tax policies related to facilities sequestering CO2 and the rebates available to those companies based on how the CO2 is sequestered or used. Sunset timelines for 45Q are December 31st, 2032. 45Z is related to rebates for low-carbon fuel production, where CO2 capture can be used to reduce the carbon intensity of those fuels for a rebate. 45Z’s timeline is applicable for production between January 1st, 2024 and December 31st, 2027.
As the industry has sought to utilize these rebates, comments and clarifications have been provided. We are sharing how some of those clarifications should be considered in your project execution of facilities and products making use of IRA rebates.
There are two major factors in requirements for Inflation Reduction Act CO2 projects. Ensuring that your project considers these requirements and aligns with your contracting strategy for the facility is key to being able to claim the rebates for your project. Meeting these requirements can lead to 5x the rebate from the project, sometimes up to 50% of a project’s capital cost.
The prevailing wage is a locality-based wage measurement tracked by the Department of Labor.
“A prevailing wage is the combination of the basic hourly wage rate and any fringe benefits rate, paid to workers in a specific classification of laborer or mechanic in the geographic area where construction, alteration, or repair is performed, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40 of the United States Code, also known as the Davis-Bacon Act.”
“Taxpayers shall ensure that, with respect to the construction of any qualified facility, not less than the applicable percentage of the total labor hours of the construction, alteration, or repair work (including such work performed by any contractor or subcontractor) with respect to such facility shall, subject to subparagraph (B), be performed by qualified apprentices.
In the case of a qualified facility the construction of which begins after December 31, 2023, 15 percent.”
Execution strategy can be used to limit exposure and ensure compliance for successful rebates. Focusing on the definition of a “qualified site” and a secondary site will allow projects to limit the scope that applies to the requirements. Clarifications to this were provided on June 25th by the Department of the Treasury.
The structure of the contract terms, including penalty clauses and remediation for the failure to meet and document the requirements should be another focus of the project execution plan. Secure legal counsel who is familiar with this law and industrial contract negotiations for the review of the contracts. GrantThorton has some summaries on their website that convey they are experts in the matter and there are many other legal firms out there that can help.
All projects have similar milestones for evaluation, selection, funding, definition, and execution. During the project evaluation and selection process, discuss the IRA requirements. At CANUSA EPC, being transparent with the project stakeholders throughout the project allows the team to progress with the execution while staying aligned with the goals of the client. We don’t claim to provide problem free projects, but we do hold the expectations of our team and clients to work through the problems in a transparent manner.
Reach out if you have any questions or comments, and we will be happy to provide our expertise to your team. Project experience from CANUSA EPC related to CO2 can be found at our expertise page.
CO2 capture and liquefaction is a process that converts gaseous carbon dioxide into liquid form, which can then be stored or transported for various applications. CO2 capture and liquefaction is an important technology for reducing greenhouse gas emissions and meeting lower carbon products. However, CO2 capture and liquefaction also require a significant amount of energy, especially for the compression of CO2 gas. Therefore, it is important pick the proper drive and compression technology to manage the “parasitic load” associated with processing the CO2.
Screw compressors are widely used in CO2 liquefaction and capture facilities, as they can handle large volumes of gas and are common in refrigeration loops for the liquefaction process. Screw compressors typically use slide valves for unloading and capacity control, which adjust the internal volume of the compressor to match the process demand. However, using slide valves does not reduce the power requirements of the compressor as much as reducing the speed of the compressor would. Therefore, at reduced throughput, using variable frequency drives (VFDs) to control the speed of the screw compressors compared to slide valves provides lower energy usage.
In this analysis, we will present a case study of a 1000 metric ton per day (MTPD) CO2 liquefaction facility that used screw compression as the main driver and for cooling of the process. We will compare the performance and energy consumption of the screw compressors using slide valves and VFDs and show how VFDs can offer significant benefits in terms of:
We analyzed the data of a 1000 MTPD CO2 liquefaction facility that used electric driven screw compressors for the main compression and cooling stages of the process. The facility had a total of ~6500 kW of screw compressor load, consisting of three main compressors and 3 cooling compressors. The main compressors were designed to compress CO2 gas, and the cooling compressors were designed to provide refrigeration for the process.
We compared the performance and energy consumption of the screw compressors using two different methods of capacity control: slide valves and VFDs.
We assumed that the facility is operating at 75% of its design capacity, which is a possible scenario for CO2 liquefaction and capture facilities based on the cycling that happens with fermentation.
We also estimated the capital cost and the operating cost of the screw compressors using slide valves and VFDs. For using slide valves, it was assumed that the compressors would be started with soft-starts. We assumed that the operating cost of the screw compressors was mainly determined by the electricity cost, which was $0.13 USD per kWh.
The results of our analysis are summarized in the table below.
As shown in the table, using VFDs to control the capacity of the screw compressors resulted in a 18% reduction in power consumption, compared to using slide valves. This translates to a 18% reduction in operating cost, which amounts to $3,248 USD per day in savings from lower power demands. On the other hand, using VFDs increased the capital cost of the screw compressors by 50%, which amounts to $1,000,000 USD.
The results of our case study demonstrate that using VFDs to control the capacity of the screw compressors in CO2 liquefaction and capture facilities is economical if reduced capacity is anticipated. What determines the economics will be the duration of the reduced operations and the CO2e of the kWh.
Although VFDs have a higher capital cost than slide valves, the payback period of the VFDs is relatively short, as the operating cost savings are significant. Moreover, VFDs can help CO2 liquefaction and capture facilities achieve their environmental and social goals (45Z) as a low carbon fuel product, as they can reduce the greenhouse gas emissions and the energy intensity of the process.
Are VFDs right for your facility? Using VFDs on screw compressors for CO2 liquefaction facilities can offer significant benefits in terms of efficiency and cost savings, compared to using slide valves. VFDs can reduce the power consumption and the operating cost of the screw compressors by 18%. In a reduced operating scenario of 75%, the payback period of the VFDs is only 308 days. Additional revenue increases can be recognized as well based on the CO2e of the kWh used in the liquefaction, as it will affect the multiplier of the government credits for 45Z.
Therefore, we recommend that when considering CO2 liquefaction, engineering should work to determine the anticipated average flow of CO2 product compared to the maximum capacity of the facility to determine the drive technology.
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CANUSA EPC provides engineering, procurement, and construction management for CO2 liquefaction and capture facilities across North America. We focus on aligning the processing requirements with operational strategies to optimize your return on investment in these facilities. If you are interested, please contact us.