FEED Study Introduction
The US Department of Energy (DOE), through its Office of Fossil Energy and Carbon Management (FECM) has funded several Front-End Engineering and Design (FEED) studies for retrofitting existing fossil fuel power plants with carbon capture technology. These comprehensive studies are publicly available on the US DOE Office of Scientific and Technical Information (OSTI) website as part of the knowledge sharing requirements associated with the funding.
This study is our effort to help stakeholders quickly understand the key findings in lengthy reports highlighting methodologies, and unique design aspects that could shape future carbon capture plant designs. Our objective is to highlight the most relevant sections of each study.
Linde-BASF Advanced Post-Combustion CO2 Capture Technology at a Southern Company Natural Gas-Fired Power Plant
Overview
The FEED study, conducted by Southern Company Services with Linde, BASF, and other partners, examines adding a carbon capture facility to an existing natural gas fired combined cycle (NGCC) power plant. The host facility is Unit #4 of Mississippi Power’s Plant Daniel, a power generation unit with a capacity of 525 megawatts electric (MWe). This study includes detailed design developments, utility integration, and cost estimations to support large-scale deployment of the Linde-BASF post-combustion capture technology (i.e. BASF’s OASE® blue solvent).
Total CO2 captured: Approximately 1.46 MM tonnes/yr (value was not stated in FEED report and was estimated based on heat and material balance and an assumed 90% capacity factor)
Total As-Spent CAPEX ($MM USD in 2021): $752 (excludes financing costs).
Objective
This summary highlights the unique design and planning aspects from this FEED study which include:
- Use of BASF’s OASE® blue solvent
- Selection of two absorbers feeding one stripper
- Selection of two trains for carbon capture and compression
- Selection of a stripper interstage heater
- Elimination of diverter dampers after the heat recovery steam generator (HRSG) stages
- Investigation of solvent regeneration heat from multiple steam sources
- Use of modularization approach for key inside battery limit (ISBL) process units
- Use of duct burning and steam injection to mitigate gas turbine thermal lapse
Use of BASF’s OASE® Blue Solvent
What is it:
BASF’s OASE® blue is an advanced amine-based solvent used in post-combustion carbon capture processes. The OASE® blue improves the thermal efficiency of a capture process as it is designed to significantly reduce the steam duty needed for solvent regeneration. This reduction in energy demand lowers the operating costs of a capture system and minimizes the amount of steam extracted from the host plant (i.e. reducing the impact on host plant performance). The solvent has been validated through multiple pilot campaigns from 2009 to 2017, demonstrating good performance across a variety of flue gas conditions, including those with impurities such as oxygen (O2), nitrogen oxide (NOx), sulfur oxides (SOx), particulate matter, and variations in moisture content.
In this study:
In the FEED study, the OASE® blue solvent was selected to capture carbon dioxide (CO2).
The table below summarizes the OASE® blue solvent capability.
| Energy Use (GJ / tonne CO2) |
The solvent is selected for its lower regeneration energy demand compared to conventional amines. However, specific values were not provided in the FEED study. |
|
CO2 Loading Capacity |
No specific rich/lean CO2 loading values or capacities were provided in the study. |
| Solvent Stability and Degradation | Carbon filters and a reclaiming system are mentioned, which implies degradation products are expected and managed. However, quantitative data on solvent stability and degradation are not provided in the study. |
| Emissions | The design includes wash sections as well as an emissions control section to limit amine carryover. However, no emission data is reported. |
| Material Compatibility | No specific material compatibility matrix is included in the study. There is no indication of unusual corrosion concerns. |
Additional Information:
While the FEED study presents a comprehensive engineering design and integration plan, it does not include key quantitative solvent performance metrics, such as regeneration energy demand, rich/lean CO2 loading capacities, or solvent degradation rates. This data is critical for validating process efficiency, sizing of process equipment, estimating utility consumption, and assessing long-term operating expenses.
Selection of Two Absorbers Feeding One Stripper
What is it:
In a typical amine-based post-combustion carbon capture system, each absorber is paired with a dedicated stripper, forming a 1:1 configuration. However, alternative configurations exist, such as a 2:1 configuration, where two absorbers feed into a single shared stripper. This alternative configuration can offer advantages such as more compact layouts, capital cost savings, and operational flexibility.
- More compact layouts are facilitated by this configuration, helping to mitigate spatial design challenges.
- Capital cost savings stem primarily from reducing the number of stripper columns, which are typically large pressure vessels with significant material and fabrication costs. Additionally, consolidating regeneration equipment can reduce auxiliary systems (e.g., reboilers, pumps, and controls), leading to further cost and space savings.
- Operational flexibility is enhanced by enabling one absorber to remain operational while the other undergoes maintenance.
In this study:
In this FEED study, each of the two capture trains includes two parallel absorbers that capture CO2 from the flue gas of a single HRSG. The captured CO2-rich solvent from both absorbers is then routed to a single stripper column per process train. The stripper regenerates the solvent, and the captured CO2 is then sent for compression and dehydration prior to transport.
Additional Information:
This configuration leads to operational dependency between the absorbers and the shared regeneration system, which means even though one absorber can be operational at a time, any issues in the stripper can impact both absorbers simultaneously. To mitigate this risk, it is important to incorporate proper instrumentation and control strategies into the design. For example, the system can include sensors that monitor temperature and pressure, along with automated controls for shutdown sequences and bypass controls that allow solvent flow to be safely diverted or to isolate the steam supply if the stripper becomes unavailable.
Selection of Two Trains for Carbon Capture and Compression
What is it:
Single-train and multi-train systems are both viable options for capture projects, and an evaluation of each design’s cost versus benefits is often necessary to determine the best option for a project. The figures shown illustrate a comparison of a single-train and multi-train system. It is important to note that there are variations of the multi-train system, and the figures shown here reflect the configuration used in this FEED study (e.g. multiple absorbers feeding into a single stripper).
In this study:
Two identical process trains were selected in this study, each serving one of the two HRSG units. Each train consists of two absorbers, one stripper, and one CO2 compression system. There is dedicated ductwork to route the path of flue gas from each HRSG to the two absorbers.
Additional Information:
The choice between these systems is influenced by both site-specific and project-specific factors. Below, we provide a comparison of multi-train vs. single-train systems.
Comparison of Multi-Train vs. Single-Train Carbon Capture Systems
|
Aspect |
Multi-Train System | Single-Train System |
|---|---|---|
| Configuration (in this FEED study) | Two carbon capture and compression trains | One capture system handling all the flue gases |
| Prefabrication Potential | Higher – Allows for extensive off-site fabrication | Lower – Larger system components may limit prefabrication options |
| Construction Efficiency | Higher – Faster on-site construction due to shop fabrication | Lower – Longer on-site construction due to size and complexity |
| Project Schedule Certainty | Higher – Due to off-site fabrication of components | Lower – Due to on-site assembly and integration challenges |
| Transportation and Installation | Easier – Due to smaller, pre-assembled modules | More complex – due to size and integration of large equipment |
| Operational Flexibility | Higher – Independent operation of each train allows more turndown flexibility | Lower – Single system may limit flexible operation |
| Reliability and Maintenance | Higher – Online maintenance possible, increased uptime | Lower – Maintenance may require full system shutdown |
| Physical Footprint | Larger – Two systems require more space on site | Smaller – Consolidated system uses space more efficiently |
| Capital Cost | Higher- Due to more equipment and piping | Lower – Due to less equipment and piping |
Selection of a Stripper Interstage Heater
What is it:
To improve thermal efficiency and enhance CO2 stripping capability (i.e. releasing the CO2 from the solvent), the regeneration system integrates a stripper interstage heater. This heater allows thermal energy from the hot lean solvent exiting the bottom of the stripper to be reused by preheating the partially rich amine collected within the stripper. By increasing the temperature of the partially rich amine within the stripper, the system’s solvent regeneration is improved and the steam demand for the reboiler is reduced.
In this study:
The heater is a liquid-to-liquid heat exchanger that transfers heat from the hot lean amine exiting the bottom of the stripper to the partially stripped rich amine, which is drawn from the chimney tray located between two sections of the stripper. This preheating step reduces the thermal duty required from the reboiler, contributing to more energy-efficient regeneration. The FEED report identifies the interstage heater as a key component for reducing energy use, however, no exact figures about steam savings are provided.
Additional Information:
Aside from the approach used in this study, other common methods of heat recovery in amine-based capture systems include the use of mechanical vapor recompression (MVR) and strategic process optimizations to reduce the heat duty of reboiler. While heat recovery can improve plant efficiency and reduce energy consumption, it often comes with higher capital costs. This is because implementing a heat recovery system typically requires additional equipment, such as heat exchangers or a MVR unit.
To assess whether these investments are viable, an economic analysis is typically performed to determine the financial viability of integrating heat recovery technologies into the capture system.
Elimination of Diverter Dampers after the HRSG
What is it:
Diverter dampers are large mechanical components installed in the flue gas duct after the HRSG. Their main purpose is to give operators the option to bypass the carbon capture system and direct the flue gas through the HRSG stack when needed. This is especially useful during maintenance, unexpected shutdowns, or when the capture plant is offline or is operating at reduced capacity. By redirecting the flue gas to the stack instead of the absorber, these dampers provide valuable flexibility in plant operations.
In this study:
This study does not include diverter dampers after the HRSG stacks. This strategy was selected to mitigate the risk associated with damper design and construction – specifically, to prevent the creation of a vacuum in the flue gas transfer duct and direct contact cooler if issues arise during operation. Challenges in controlling and quantifying the amount of air ingress to reduce the vacuum were highlighted during a computational fluid dynamics (CFD) analysis. This report suggested conducting further analysis when detailed fan curves and control logics are available during the detailed design phase to determine if this configuration is consistently achievable, or if the risks and costs associated with vacuum warrant the additional complexity and risks of an “open” HRSG stack.
Additional information:
In addition to the CFD analysis, a dynamic model and transient analysis are recommended during the detailed design phase to assess whether any process pressures exceed their allowable limits during any potential transient events. A dynamic model is a simulation that represents how a system behaves over time. A transient analysis is a type of study that focuses on short-term, non-steady-state events, which can cause rapid changes in system conditions.
The dynamic model and transient analysis will help identify potential risks and inform the development of control strategies and mitigation measures to protect equipment from pressure excursions.
Investigation of Solvent Regeneration Heat from Multiple Steam Sources
What is it:
Solvent regeneration in post-combustion carbon capture requires a significant amount of low-to-medium pressure steam, typically provided by a dedicated auxiliary boiler, or extracted from the host facility’s steam turbine system. Investigating multiple steam supply options is suggested to optimize energy use, improve operations, and minimize major modifications.
In this study:
The FEED study evaluated seven potential sources to supply the steam for the reboilers, which were qualitatively screened based on performance, cost, and operational impacts.
| Option | Description* | Base Load Combined Cycle Capacity** | Capital Cost | Operational Flexibility (qualitative) | Summarized Results |
|---|---|---|---|---|---|
| 1 | Standalone Auxiliary Boiler | 0 MW | $$ | No change | Auxiliary boiler increases operational flexibility, but also increases the CO2 produced on-site. 90% CO2 capture rates are not achieved unless the incremental flue gas from the auxiliary boiler is routed to the capture facility, resulting in increased capital costs. |
| 2 | Low Pressure Steam supplemented by Auxiliary Boiler | -10 MW | $$ | Minor reduction | |
| 3 | Low Pressure Steam supplemented by Crossover Steam (modifications to the LP steam turbine) | -35 MW | $$ | Reduction | Using LP and crossover steam is the most efficient, but they incur significant capital costs to modify the LP steam turbine and LP steam section of the HRSG. |
| 3B | Low Pressure Steam supplemented by Crossover Steam (modifications to the LP steam turbine and HRSG LP pressure level) | -35 MW | $$ | Reduction | |
| 4 | Low Pressure Steam supplemented by Main Steam | -63 MW | $ | Minor reduction | With steam supplied from high energy sources, it minimizes cost but the negative impact on performance is substantial. |
| 5 | Low Pressure Steam supplemented by Cold Reheat Steam | -49 MW | $ | Minor reduction | |
| 6 | Low Pressure Steam supplemented by Hot Reheat Steam | -52 MW | $ | Minor reduction | |
| 7 | Low Pressure Steam supplemented by Crossover Steam (minimal modifications to the LP steam turbine) | -42 MW | $ | Minor reduction | This scenario was selected given the low cost, relatively low performance impact, and limited effect on operational flexibility. |
*The location of the steam extraction can be found in Figure 41 of the FEED study.
** Performance differences are provided for the reboiler steam demand only and excludes any auxiliary loads for the CO2 capture process (e.g. CO2 compression).
Additional information:
When the capture plant is operating, it requires a significant amount of steam from the host facility. During periods of partial operation or complete shutdown, whether due to reduced capture demand, maintenance, emergency shutdowns, or unexpected issues, the steam demand drops significantly (i.e. potentially to zero). Systems should be designed with flexibility, allowing it to operate between 0% and 100% capture capacity without disrupting or damaging the host facility.
To support this flexibility, several steam supply strategies were evaluated. This included using a standalone auxiliary boiler or extracting steam from various points in the host facility’s steam cycle (i.e. from low-pressure crossover between intermediate pressure and low-pressure steam turbine, cold reheat, hot reheat, and HRSG). Some configurations require minimal modifications, while some require extensive modifications. Each approach presents trade-offs such as:
- Auxiliary boiler offers operational independence but increases site emissions unless its flue gas is also captured.
- Steam extraction from the host facility, either from a steam turbine, HRSG, or both, can improve energy efficiency but may reduce power output and require costly turbine or HRSG modifications. The disruption of the host facility in supplying steam to the capture plant can also lead to operational issues in the capture system.
Use of Modularization Approach for Key Inside Battery Limit Process Units
What is it:
Modularization often refers to a design strategy to break down a facility into prefabricated sections (modules) that can be built off-site and then transported to the site location for assembly. Modular construction helps to reduce on-site labor requirements, improve schedule certainty, enhance safety, and increase quality control. The modular approach concept is commonly used for process skids, structural platforms, and preassembled pipe racks.
In this study:
The FEED report indicated that modularization was considered for the key inside battery limit (ISBL) process units, particularly those associated with the absorber systems, flue gas ductwork supports, and the CO2 compressor areas. The design team evaluated layout and footprint constraints with modular assembly in mind including considerations for equipment spacing, transportation limits, and structural segmentation. While detailed module breakdowns are not provided in the FEED study, the concept was included in early stage planning to support constructability reviews and risk mitigation.
Additional information:
The consideration for modularization reflects best practice for projects with complex ISBL configurations and site logistic challenges. Modular construction is especially useful in regions where skilled labour availability is limited or where site congestion and weather risks could delay construction.
Use of Duct Burning and Steam Injection to Mitigate Gas Turbine Thermal Lapse
What is it:
The gas turbine exhaust flow rate and temperature may vary significantly from design during upset conditions, off-design operation, periods of reduced efficiency due to fouling, or adverse ambient conditions. Since the exhaust gas temperature and flow from the gas turbine are essential for transferring thermal energy to the heat recovery system to produce steam for amine regeneration, any reduction in thermal performance can impact overall system efficiency. Meaning, thermal lapses directly contribute to a reduction in absorber performance.
In this study:
The FEED study evaluates the potential impact of thermal lapses, which could reduce the carbon capture system’s performance. While the base design does not include duct burners or steam injection equipment, the study evaluated both options as potential future upgrades to maintain or recover thermal input to the amine regeneration process.
Additional information:
Petra Nova, an existing amine-based post-combustion carbon capture plant in Texas, installed a separate natural gas-fired combined cycle plant to supply steam to the carbon capture process. This unit includes a duct burner in the HRSG. This burner is used to ensure sufficient steam production under varying load and ambient conditions.
See reference: Petra Nova Technical Report