Air Pollution Control Equipment Services, Emissions

Carbon Capture Project Passes 100,000 Ton Milestone

Issue 11 and Volume 116.

by Andrew Maxson & Richard Rhudy, EPRI; Marian Stone & Richard Myhre, BKi

The carbon dioxide (CO2) capture plant at Plant Barry near Mobile, Ala., has passed the major milestone of 100,000 tons of CO2 captured successfully.

Built by Southern Company and Mitsubishi Heavy Industries America, with technology and co-funding from Mitsubishi Heavy Industries, Ltd. (MHI) in Japan, the CO2 capture plant receives flue gas from a 25 MW equivalent slipstream ducted from Unit 5 of Alabama Power’s James M. Barry Electric Generating Plant, the host facility for the project. That unit was chosen, in part, because it had been retrofitted with a high-performance Chiyoda Thoroughbred 121 sulfur dioxide (SO2) scrubber, minimizing the need for flue gas pre-treatment prior to CO2 capture.

The experience that Southern Company and Plant Barry engineers and operators gained with the SO2 scrubber retrofit helped prepare them for work on the design, construction, startup, and operation of the CO2 capture plant, which commenced operation in June 2011.

Already a significant achievement in its own right, the CO2 capture plant became part of world’s largest carbon capture and storage (CCS) demonstration project on coal flue gas with the start of CO2 injection operations by the Southeast Regional Carbon Sequestration Partnership on August 20, 2012.

Capture Plant Design Overview

“Energy innovation projects like this are critical to providing meaningful solutions for our energy future,” said Chris Hobson, Southern Company senior vice president for research and environmental affairs and chief environmental officer.”The work we are doing with our partners at Plant Barry to reduce greenhouse gas emissions reflects our commitment to lead the industry with a robust research and development portfolio.”

At the core of the CO2 capture plant is one of those new innovative technologies, the KM-CDR CO2 recovery process developed by MHI and Kansai Electric Power Company using the regenerable KS-1 sterically hindered amine solvent in an aqueous solution. At a design capture rate of 90 percent of flue gas CO2 and a nominal capacity of 550 U.S. short tons per day, MHI said the CO2 capture plant is providing a real-world demonstration of low-carbon coal-fired power generation.

The CO2 capture process starts with a quencher that cools the incoming flue gas via counterflow contact with a water spray in a packed tower. Lower flue gas temperatures increase the efficiency of the exothermic CO2 absorption reaction and minimize solvent loss due to gas-phase equilibrium increases. The optimum temperature range for CO2 recovery is 95–113°F (35–45°C), although temperatures outside of this window may be accommodated if needed. The quencher tower and packing are engineered to accomplish the necessary flue gas cooling while minimizing pressure drop to limit the flue gas blower load. The quencher also removes trace impurities such as FGD limestone slurry and dust.

The cooled flue gas from the quencher is routed to the bottom of the CO2 absorber, another packed tower designed for counterflow contact, this time with the KS-1 solvent. The packing in the absorber promotes even gas-liquid contact and sufficient residence time for the CO2 in the flue gas to absorb into the KS-1 solvent. The flue gas then moves up into a water-washing section at the top of the tower, which scrubs any solvent carry-over and condenses some moisture to maintain the water balance within the system. The treated flue gas exits the top of the absorber/wash column via a small stack. With the heaviest flue gas constituent—CO2—now removed from the gas stream, no reheat is necessary to achieve sufficient buoyancy for dispersion.

The regenerator tower at the carbon capture and storage project at Alabama Power's Plant Barry. The plant began capturing CO<sub>2</sub> in June 2011. Photo courtesy of Southern Co.
The regenerator tower at the carbon capture and storage project at Alabama Power’s Plant Barry. The plant began capturing CO2 in June 2011. Photo courtesy of Southern Co.

CO2-rich solvent is collected at the bottom of the absorber and pumped to the CO2 stripper column. Along the way it passes through the “lean-rich” heat exchanger, where it is pre-heated by hot solvent returning from the stripper after release of its CO2. The pre-heated rich solvent is routed to the top of the stripper column, where again it flows down through a packing and is further heated via counterflow contact with CO2 and steam at about 250°F (120°C) rising from the stripper reboiler return at the bottom of the column. The heat liberates the CO2 from the KS-1 solvent; it exits the top of the stripper where it is cooled to remove and return water to the stripper. CO2 purity is high, about 99.9% according to MHI. The heat source for the stripper reboiler is steam extracted from Unit 5’s low-pressure steam turbine. The hot CO2-lean solvent in the bottom of the stripper column is pumped through the lean-rich heat exchanger, where it is cooled, and then to a cooler, where it is further cooled to the optimum reaction temperature range (95–113°F or 35–45°C, as noted above), before being reintroduced to the top of the CO2 absorber unit. Thus, the capture and regeneration process can be envisioned as KS-1 solvent circulating in “figure 8” laps, with the absorber and stripper column in each lobe of the eight and the lean-rich heat exchanger at the apex.


Over time, impurities in the flue gas, most notably SO2 and NO2, cause undesirable side reactions with the amine solvent leading to buildup of heat-stable salts. A reclaimer unit is used to purge these salts from the solvent, somewhat akin to blowdown in recirculated cooling systems. When the salt content of the solvent builds up to preset limits, the reclaimer boils down the solvent and concentrates salts into a residue that can be easily removed. MHI sought to design the KS-1 solvent for degradation resistance, which it believes should reduce the frequency of reclaimer operation. In addition, the Plant Barry design includes a new MHI online amine analyzer, which consists of an automatic sampler and high-resolution analyzer with a computational control unit that can measure solvent and CO2 concentrations, as well as degraded amine concentrations in treated flue gas from the absorber. These data are used to verify mass and heat balances on semi-continuous basis, allowing the online system to automatically provide information on operational status, facilitating prompt and optimal operator response.

Aerial photo of CO<sub>2</sub> capture plant at Plant Barry with the flue gas inlet and quench gas conditioning column at left, the adjacent CO<sub>2</sub> absorber (lower portion) and water wash (upper portion) column; solvent tanks and management equipment at the center front; the solvent regeneration (2 stripper”) column in the center; and compression/dehydration equipment at right. Photo courtesy of Southern Co.” />
Aerial photo of CO2 capture plant at Plant Barry with the flue gas inlet and quench gas conditioning column at left, the adjacent CO2 absorber (lower portion) and water wash (upper portion) column; solvent tanks and management equipment at the center front; the solvent regeneration (“CO2 stripper”) column in the center; and compression/dehydration equipment at right. Photo courtesy of Southern Co.

Four-stage centrifugal compressors bring the captured CO2 to a compact supercritical fluid state at nominally 1500 psig (100 bar), with interstage cooling and a glycol dehydration unit between the second and third stages to dry the CO2 for pipeline transport.

Meeting Goals: Stable Operation, High Capture Rate, Low Regeneration Energy

To date, performance of the CO2 capture plant has met Southern Company and MHI expectations. They have reported plant operation to be stable both at part and full load, with a high load test pushing the nominal CO2 capture rate of 550 tons per day up 598 tons. CO2 removal efficiency at the design value of 90% has been sustained over various test periods, and a maximum capture rate of 95% has been achieved. Solvent regeneration steam consumption has been a bit lower than expected at 0.98 ton per ton of CO2 captured, with a minimum of 0.95 ton-steam/ton-CO2 and a slightly higher value of 1.02 ton-steam/ton-CO2 during the high load test. The CO2 compressors have also performed as expected. As of late 2012, the system had captured 110,000 tons of CO2.

The Electric Power Research Institute (EPRI), which conducts independent research in the electricity sector for the benefit of the public, has been involved in two test campaigns at the Plant Barry CO2 capture plant and plans to participate in several more tests over the next year. EPRI distills and disseminates non-proprietary results and lessons learned from innovative projects around the world, and aims to provide CCS stakeholders with insights from the Plant Barry CO2 capture plant.”Our charter calls for managing collaborative R&D programs that solve technical challenges and help our members provide society with reliable, affordable, and environmentally responsible electricity,” said Tom Alley, EPRI Vice President for Generation.”This project embodies all facets of that mission.”

Plant Barry normally fires a Colombian coal, but the CO2 capture plant team was fortunate to have its test period coincide with the plant’s tests of alternative coals from the Illinois Basin and Powder River Basin.

The CO2 capture unit performed fairly consistently for all of the feedstocks, but Southern Company and MHI did observe an expected trend of higher SO3 emissions and amine aerosol with increasing coal sulfur content.

In anticipation of this issue, Southern Company and MHI included in the Plant Barry design a new MHI multi-stage washing system and proprietary demister as part of an amine emissions reduction system. Amine emissions are observed as both mist and vapor. Vaporous emissions can be controlled by an enhanced washing and absorption section. Amine mist consists of entrainment or aerosols formed by the reaction between amine vapor and CO2, which are difficult to remove by conventional methods. Research on natural gas plant KM-CDR applications led MHI to develop the special demister, which has been retrofitted to all commercial gas plant units running the KM-CDR system and is being tested on coal flue gas for the first time at Plant Barry. Southern Company and MHI have said that demister performance to date has matched their expectations.

MHI also developed a dynamic simulation model to coordinate control of the CO2 capture plant and CO2 compressors, which should help the capture system follow boiler load changes quickly.

Parameter tuning was completed during initial operations and load change data will be collected during 2012 test campaigns. Thus far, after tuning some plant-specific parameters, the simulated data trend has agreed with the actual data trend. CO2 removal efficiency remained at more than 86% during simulated load-change operations, according to MHI.

“Through participation in the world’s largest-scale CO2 capture project at Plant Barry, MHI intends to show the high-level economic feasibility and reliability of commercial-scale CO2 capture from coal-fired power plant flue gas, and looks to realize its commercialization,” said Steve Holton, Director of Business Development for the Environmental Systems Division of Mitsubishi Heavy Industries America.

Collaboration of Cultures Has Been a Key to Success

From the inception of the CO2 capture project, Southern Company’s vision was for its personnel to work in close collaboration with MHI on the design, construction, operation, and maintenance of the CO2 capture plant.

The daily exchange between operational personnel, research engineers, and technology developers is now viewed as a hallmark of the project’s success.

When Unit 5 ran less than expected due to mild weather in the winter of 2011–12, for example, the engineering and operations team took advantage, calling “all hands” team meetings to share experiences and develop procedures to hone plant operations. Productivity was high with the full knowledge base in the room at one time.

“What emerged was a learning environment that merged the experience and insights of plant operators with those of the technology developers and reaped the benefits of both perspectives,” said Nick Irvin, Southern Company Services’ Principal Research Engineer.

Irvin added that the commitment plant personnel made to mastering this new technology was especially beneficial.

“Collaboration extended to practical tasks such as equipment flushing, checkout, labeling, and verifying clearances for safety, as well as reading piping and instrumentation diagrams and other engineering drawings,” Irvin said.

Summing up the operational experience, Irvin noted that the staff likened operation of the CO2 capture plant to maintaining a drum level in multiple locations simultaneously.

More Results to Follow

By the time the CO2 capture plant test concludes, the project will have gathered information that encompasses confirmation of heat and mass balances, including mass balances for all major constituents and key trace elements and heat balances on all process equipment; monitoring of emissions and waste streams; parametric testing on all process systems for development of simulation tools to improve system control; performance optimization; dynamic response testing for load following; testing to validate equipment reliability and life; and a high impurities loading test using alternative coals.

“The information we gain here will be invaluable,” said Hobson.”We are fortunate to have the right team of partners working to move carbon capture technology forward at a time when the need for safe, clean, reliable and affordable energy more than ever requires innovative action.”