Petra Nova

World’s Largest Post-combustion Carbon Capture Project Nearing Completion

By Anthony Armpriester and Ted McMahon

The Petra Nova project applies carbon capture technology to an existing coal-fired power plant to capture 1.6 million tons of CO₂ per year. The project, which is expected to be completed by the end of 2016, will capture 90 percent of CO₂ from the power plant. Photo courtesy: NRG Energy

When construction is completed, expected by the end of 2016, Petra Nova Parish Holdings, LLC (Petra Nova) will become the largest post-combustion carbon capture project installed on an existing coal-fired power plant. It is designed to capture 90 percent of the carbon dioxide (CO₂) from a 240 MWe slipstream of coal-fired flue gas-approximately 5,000 tons of CO₂ each day, or 1.6 million per year. Funded in part by the U.S. Department of Energy (DOE), Petra Nova is a joint venture between NRG Energy, Inc. (NRG) and JX Nippon Oil and Gas Exploration (JX) at the W.A. Parish Plant (WAP) in Thompsons, Texas, southwest of Houston.

DOE regards addressing climate change-from the development of new, clean energy technology to the mitigation of the effects of carbon emissions-as a top priority. And, as part of the DOE’s national laboratory system, the National Energy Technology Laboratory (NETL) is deeply committed to furthering the department’s mission, thereby advancing the security and energy future of our nation. NETL has extensive experience in developing technologies to help mitigate the environmental effects of fossil fuel combustion for power generation, including carbon capture.

NRG realizes climate change is a significant environmental challenge, and is working to be part of the solution. As the nation’s largest independent power producer, NRG is leading the industry with a goal at the forefront of sustainability efforts across the country-to reduce carbon emissions 50 percent by 2030 and 90 percent by 2050. Moving forward on these goals, In addition to moving forward on schedule and on budget on construction of Petra Nova, NRG has commenced construction on numerous community solar projects, including the largest in the U.S., converted multiple large coal-fired generating units to natural gas and is developing several energy storage and preferred resources projects.

NETL is using their expertise to provide project management support to NRG and JX for the execution of the Petra Nova project. This large-scale demonstration, the largest of its kind to date, will show how carbon capture technologies can have a meaningful and positive impact on the environment, while allowing fossil fuels like coal to remain a viable energy source for many more years. The project will also demonstrate technological advances aimed at lowering the energy requirement of the capture process; demonstrate the concept of integrating a cogeneration system into the carbon capture process, which provides energy to operate the system; and establish the impact of CO₂ capture and storage operations on the cost of electricity.

Carbon Capture Process

The Kansai Mitsubishi Carbon Dioxide Recovery (KM-CDR Process) resembles other amine-based gas treating processes, which have been used for many years in the natural gas, petrochemical, and refining industries, but MHI has adapted and scaled this process to recover CO₂ from low-pressure, oxygen containing streams, such as power plant flue gas.

Simplified Process Flow Diagram (Generic) 1

The MHI process uses a proprietary KS-1 high-performance solvent for CO₂ absorption and desorption that was jointly developed by MHI and the Kansai Electric Power Co., Inc. Figure 1 represents a simplified overview of the process with a description of how it works below.

The process consists of three main columns: a Quencher, where the flue gas is conditioned and prepared for the absorption process; an Absorber column, where CO₂ is absorbed into the amine-based solvent through a chemical reaction; and a Regenerator (or Stripper) vessel, where the concentrated CO₂ is released and the original solvent is recovered and recycled back through the process.

The flue gas is first routed to the Quencher for flue gas conditioning (i.e., cooling, dehydration, and trim acid gas removal). The flue gas is cooled because the absorption reaction is affected by the temperature of the flue gas (i.e., absorption of CO₂ in the solvent is an exothermic process that favors lower temperatures). This cooling process causes the water to condense out of the wet flue gas; hence, the dehydration. Next, certain constituents entrained in the flue gas, if not removed, will contaminate the solvent so the gas is scrubbed of these contaminating constituents in a deep polishing scrubber.

The cooled and cleaned gas exits the top of the cooler column where it is pulled through the blower. The blower, located downstream of the Quencher, is used to pull the slipstream off of the host unit and overcome the pressure drop through the plant as it passes up through the Absorber column.

From the blower, the flue gas enters the bottom of the Absorber column and flows upward through the packed column beds where it chemically reacts with the solvent (loading the solvent with CO₂). Counter-current flow, through multiple stages of structured packing, maximizes contacting surface areas and mass transfer rates of the CO₂ into the solvent. The CO₂-depleted gases are then washed and vented to the atmosphere.

The CO₂-rich solvent leaves the bottom of the Absorber and is pumped through a heat exchanger, heating the solvent as it is routed to the solvent regeneration section of the plant. This is the section where the weakly bonded compound is broken down with the application of heat, in the form of steam, to liberate the CO₂ and leave reusable solvent behind. The liberated CO₂ is sent to a compressor to compress it up to supercritical phase (resembling a liquid but expanding to fill space like a gas), for pipeline transport. The CO₂-lean solvent is routed back to the absorber, through a heat exchanger (for cooling), to repeat the process. A portion of the cooled lean solvent is diverted through a solvent filtration system to remove solution contaminants.

System Arrangement 2

Some of the solvent is lost during the process because of a variety of reasons, including mechanical, vaporization, and degradation. Furthermore, some contaminants, such as heat stable salts (sulfates, nitrates, and oxalates of amine) and thermal/oxidation degradation products, cannot be removed in the solvent filtration package and must be removed through a periodic reclaiming operation. Fresh solvent is added to make up for these losses incurred in the process.

This process is energy intensive and requires heat in the form of steam to release the CO₂ from the solvent and power to run the equipment, including the very large CO₂ compressor. A cogeneration unit (cogen) was constructed to supply these utilities. This standalone cogen approach simplifies retrofit, does not change basic combustion technology on the host unit, provides the flexibility to match the specific parasitic energy demands required, and allows for the safe operation of the system without disrupting existing operations. Finally, cooling is required (flue gas cooler, absorber wash sections, compressor) that needs to be served with the construction of a new cooling tower.

Design Considerations

The CO₂ capture plant is designed to process a portion of WAP Unit 8’s coal combusted flue gas to provide the capture capacity equivalent to a 240 MW gross unit. The original design team started with a 60 MW equivalent project, but it became clear early in the development cycle that having a robust CO₂ initial injection rate for Enhanced Oil Recovery (EOR) is essential to promoting a meaningful field response. After balancing the risks, technical limitations, and finite resources with the economies of scale decided to expand the project to a 240 MW equivalent.

With the system size determined, it is preferred to process the flue gas downstream of an installed FGD system because sulfur dioxide (SO₂) in the flue gas has an adverse effect on the amine absorption process. The team selected WA Parish Unit 8 for the project; however, the vintage FGD on Unit 8 was designed to be only 82 percent efficient, which does not achieve outlet concentrations at the levels necessary to minimize solvent contamination, so a polishing sodium scrubber within the KM-CDR Process is still required.

With Unit 8 the selected host unit, the interconnecting take-off point required evaluation. Several locations were considered and. various iterations of computational fluid dynamic (CFD) allowed the team to determine that the bottom of the Unit 8 stack breeching duct is the optimum takeoff location for the carbon capture system (CCS) flue gas supply duct.

Another challenge the team addressed was where to locate the CCS on the congested site. Based on the existing site constraints and general footprint requirements of the MHI process, the optimal location for the CCS was identified to be just west of (behind) the Unit 7 baghouse. This space was the largest area adjacent to Unit 8 that required the least amount of facility relocation/disruption. A warehouse occupied the space and needed to be relocated, but otherwise the location was determined to be reasonably open for a brownfield retrofit.

An interesting piece of the project is the large CO₂ compressor. It is generally recognized that pipelines are the most economical and safest method for transporting large volumes of CO₂, and the most efficient state for pipeline transport is a dense-phase liquid. In this ‘supercritical’ mode, the captured CO₂ has to be compressed to a pressure above the critical pressure prior to transport [which occurs at a pressure higher than 1,100 pounds per square inch (psi) above 90°F for pure CO₂]. Accordingly and given the high flow volumes for this project, centrifugal compressors are typically used in these applications.

The physics to compress CO₂ in a centrifugal compressor is the same as that for any other gas; however, CO₂ has many unique characteristics (comparatively higher molecular weight gas) that must be considered in the compressor design. The team investigated the best solution from existing turbo machinery providers and concluded, based on economics, efficiency, and power consumption, that integrally geared (IG) turbo compressors incorporate the optimum design concept for CO₂ compression. This is because IG machines have the ability to operate their impellers in close proximity to their optimum speeds. Couple this with the reduction in inter-stage pressure loss and ability to perform inter-stage cooling, the IG machine provides an overall efficiency improvement over similar inline machines. Consequently, the CO₂ Compression System selected for this project is an 8-stage IG machine split into a low pressure (LP) side and a high pressure (HP) side, with a triethylene glycol (TEG) dehydration unit in between, which removes moisture from the CO₂. The CO₂ Compressor package selected for this project has a large (27,000hp) motor to increase the CO₂ up to supercritical conditions for pipeline transport.

Cogen Facility and BOP Systems

In addition to locating the CCS process, the team needed to locate Balance of Plant (BOP) equipment to service the CCS. The following systems were needed:

Combustion turbine generator (CTG)/heat recovery boiler (HRB) cogeneration system
Cooling tower
Water treatment facilities (deminerlized water “demin” and waste water treatment)
BOP piperack
Integration of existing facility site services (i.e., raw water, potable water, firewater, ammonia, etc.)

All of the above-listed components needed for the integration of the BOP systems are commercially available and well-proven. Previous study work determined the type and location of the cogeneration system to be within an underutilized area northwest of the CCS island. The other system components: cooling tower, water treatment facilities, and associated interconnections (between the islands as well as existing site facilities), were identified and laid out in a prudent best-fit arrangement. For example, to minimize the large-diameter cooling water piping runs, the cooling tower was eventually sited within the CCS island because it is the user of cooling water. Figure 2 illustrates the BOP and CCS general arrangement of the systems at Parish.

For the cogen unit, the team explored a wide array of combinations capable of producing the range of steam required, including various configurations of frame machines, aeroderivatives, micro turbines, and package boilers to flexibly serve the unique parasitic energy needs of CCS. As a result of this work, the prime mover of the cogeneration facility was identified to be GE 7EA combustion turbine (CT)-which was installed in a separate exercise in 2013. With the early installation of this equipment in simple cycle peaking configuration, a critical piece of infrastructure was already in place and offered a near-term source of revenue in advance of carbon capture integration.

Then, during construction of the CCS island, the existing CT exhaust stack was removed and a Heat Recovery Boiler (HRB) was installed. The exhaust gas from the CTG will be directed through the HRB to raise single pressure steam at the conditions needed by gas treatment process. Duct burners were also installed to supplement the exhaust gases and to help control steam production as required by the CCS system. The HRB design includes environmental controls to minimize emissions of carbon monoxide and nitrogen oxides from the Cogen unit.

Conclusion

Coal is an abundant and domestic fuel that provides about 38 percent of the electricity generated in the U.S. Demand for electricity, vital to the nation’s economy and global competitiveness, is projected to increase by 25 percent by 2040. The continued use of coal is essential for providing an energy supply that supports sustainable economic growth. Unfortunately, the average generating unit age is nearly 42 years old and these units are in need of substantial refurbishment or replacement. Additional capacity must also be put in service to keep pace with the nation’s ever-growing demand for electricity.

However, coal is also a carbon-intensive fuel. Development of post-combustion capture is necessary to ensure we can continue to develop this abundant energy resource responsibly and sustainably. Additional development and demonstration is needed to improve the cost and efficiency of technologies that capture and store CO₂ emissions. Carbon capture technologies offer great potential for reducing CO₂ emissions and mitigating global climate change, while minimizing the economic impacts of the solution.

The Petra Nova Project represents an important step in advancing the commercialization of technologies that capture CO₂ from the flue gas of existing power plants. Once the plant becomes operational, its success could become the model for future coal-fired power generation facilities. The addition of CO₂ capture capability to the existing fleet of power plants will enable those plants to continue to produce clean electricity and simultaneously reduce the impact of CO₂ emissions.

Authors:

Anthony Armpriester is director of Engineering at NRG Energy, Inc. Ted McMahon is project manager at the National Energy Technology Laboratory.

Tags PE Volume 120 Issue 12