Optimizing Post-Combustion Carbon Capture

By John Gà¼len and Chris Hall

Carbon dioxide (CO2) constitutes the largest fraction of greenhouse gases, which are widely believed to be a major contributor to climate change. Even though some coal projects in India and China have been halted and the projected renewables share of the global energy mix by 2030 is expected to grow, fossil fuels will be a significant source of electric generation-about 44 percent. These trends show there is still more to be done if we are to achieve significant reductions in global carbon emissions.

There is a method (patent application pending) for efficient and cost-effective removal of CO2 from a gas turbine combined-cycle power plant. The proposed solution applies two techniques in an innovative manner: high supplementary firing in a heat recovery steam generator (HRSG) and recirculation of a portion of its stack gas. The advantage of the invention is to reduce the CO2 capture penalty-power diverted away from generation-by almost 65 percent and the overall capital cost ($/kW) by about 35 percent. For a power plant with CO2 capture rated at 800 megawatts electrical (MWe), this translates into significant reduction in capital cost while producing 75 MWe extra power output. The end result is significant reduction in carbon footprint in the most cost-effective manner. Before discussing the new technology in more detail, let us evaluate how carbon capture takes place presently.

Current Post-Combustion Capture Methods

To date, post-combustion CO2 removal from the stack gases via deployment of aqueous amine-based absorber-stripper technology is the only commercially available option, which is applicable to new units as well as to retrofitting the existing plants and has been demonstrated in several pilot projects. The stack gas of a modern gas turbine combined cycle (GTCC) power plant with advanced F, H or J class units contains about 4 percent CO2 by volume at near-atmospheric pressure (about 4.5% on a dry basis). Low flue gas pressure and density result in large volume flows requiring large piping, ducts and equipment, which are reflected in plant footprint and total installed cost. The only commercially available absorbents active enough for recovery of dilute CO2 at very low partial pressures are aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), methyl-diethanolamine (MDEA) and the newly developed sterically hindered amines (e.g., piperazine).

In a fossil fuel-fired power plant with post-combustion capture, a continuous scrubbing system is used to separate the CO2 from the flue gas stream by chemical absorption. As shown in Figure 1, the system consists of two main components:

  • an absorber in which the CO2 is removed, and
  • a regenerator (stripper) in which the CO2 is released in a concentrated form and the solvent is recovered.
Carbon dioxide capture from flue gas via aqueous amine-based absorption

Prior to the CO2 removal, the flue gas (at around 90°C at the heat recovery steam generator stack for the most efficient GTCC power plants) is typically cooled to about 50°C (e.g., in a direct contact cooler or “quench tower”) and then treated to reduce particulates and other impurities, which would otherwise cause operational problems and costly loss of the solvent. The solvent absorbs the CO2 (together with traces of NOx) by chemical reaction to form a loosely-bound compound. A booster fan is requisite to overcome the pressure loss in the capture plant and is a significant power consumer.

The largest power reduction caused by the CO2 capture system is due to the large amount of heat required to regenerate the solvent. The temperature level for regeneration is normally around 120°C. This heat is typically supplied by steam extracted from the bottoming cycle and reduces steam turbine power output and, consequently, net efficiency of the GTCC significantly. In addition, as for all other carbon capture technologies, electrical power is consumed to compress the captured CO2 for transportation to the storage site and injection into the storage cavern.

Technologies for gas sweetening and syngas purification using alkanolamines and other absorbents have been extensively utilized in chemical process industry (CPI) over the past century. Nevertheless, large-scale recovery of CO2 from flue gas poses several serious challenges. Most important of these challenges (in a GTCC context) have already been mentioned: low CO2 partial pressure and high regeneration energy. In addition, oxygen in the flue gas (about 12percent by volume at the HRSG stack) can cause corrosion and solvent degradation. Due to the absence of many impurities, which are amply present in coal-fired power plant flue gases, e.g., SOx (negligible), soot, fly ash, and mercury, the only significant degrading agent to worry about in GTCC flue gas is oxygen. While inhibitors have been reasonably effective in mitigating these effects, the need for continuous removal of unavoidable solution contaminants adds to the operating costs.

Table 1 shows performance and cost impact of a post-combustion absorption system with MEA. Performance (efficiency and output), and cost data was calculated and estimated based on its wide use in CPI applications, albeit at much smaller scales. The original (base) case is a state-of-the-art GTCC power plant (note the vintage, ca. 2000). Construction of a new plant based on existing technology is assumed. The difference in plant size chosen in the studies made by IEA GHG and SINTEF and inflation (at least to some extent) should be responsible for the differences in the specific investments. (The former obviously uses a 2x2x1 GTCC as a basis whereas the latter uses a 1x1x1 configuration.) Nevertheless, the economies of scale between the two, 410/625 = 0.656, is too optimistic. Based on the published budgetary prices, 0.9 seems to be a more appropriate factor. In other words, the “original” GTCC specific investment for the IEAGHG (year 2000) plant in Table 1 would, in all likelihood, be around 550 €/kWe. This would imply a with-capture cost of (790/410) x550 = 1,060 €/kWe.

Comparison of efficiencies and costs for post-combustion CO2 capture from natural gas fired power plants

To summarize, in a natural gas-fired GTCC framework, post-combustion CO2 capture plant design challenges are as follows:

– to minimize regeneration energy by selecting a solvent with a relatively low reaction energy
– to use the lowest possible exergy steam extraction to provide the requisite energy
– to cool the gas turbine exhaust gas to the lowest possible temperature in the HRSG
– to maximize the CO2 content of the HRSG stack gas

Proposed Solution

The solution that addresses these challenges proposed herein meets three key design challenges of post-combustion CO2 capture from the stack gas of a GTCC power plant using aqueous amine-based scrubbing method by offering the following:

– Low HRSG stack gas temperature
– Increased HRSG stack gas CO2 content
– Decreased HRSG stack gas O2 content

This is achieved by combining two bottoming cycle modifications in an inventive manner:

– High supplementary (duct) firing in the HRSG
– Recirculation of the HRSG stack gas

A detailed system diagram is shown in Figure 2. This diagram is used to explain the key features of the GTCC with carbon capture (henceforth GTC4) per the earlier discussion and how they are implemented to result in a final coherent system. Furthermore, a detailed sample calculation with all the pertinent numbers will be presented in the following section to demonstrate the significance of GTC4 vis-à -vis current state-of-the-art.

System diagram of the GTCC optimize for carbon capture

The gas turbine combined cycle system of GTC4 comprises the following major components:

(i) Main gas turbine generator (Main GTG)
(ii) Single-pressure HRSG with reheat and supplementary firing.
(iii) Steam turbine generator (STG)
(iv) Recirculation gas turbine generator (Recirculation GTG)

Main GTG, HRSG, and STG comprise the current state-of-the-art in terms of gas turbine combined cycle plant arrangement. HRSG stack gas is forwarded to a post-combustion carbon dioxide capture plant (CCP).

The proposed system, GTC4, is based on the diversion of a portion of HRSG stack gas from the CCP. Diverted gas is mixed with ambient air cooled in a heat exchanger (i.e., evaporative cooler, electric chiller, etc.). The remaining gas is forwarded to the CCP. The combined air-gas flow is the motive air of the recirculation GTG, which generates further electric power. The exhaust gas from the recirculation GTG is mixed with the exhaust gas from the main GTG. The combined exhaust gas enters the HRSG and its energy is increased by the duct burner. The rest of the steam cycle is similar to the current state-of-the-art.

The carbon capture plant can be based on any post-combustion capture technology and has the following features:

  • It is inclusive of CO2 compression and conditioning for pipeline transportation to the final storage or usage location (e.g., sequestration cavern, oil field for enhanced oil recovery, etc.).
  • It includes electric motor-driven equipment such as compressors, pumps, etc., whose power consumption is debited to the gross power generation of the GTCC power plant.
  • It utilizes steam at specified pressures and temperatures to provide energy requisite for capture processes (e.g., the reboiler of the stripper/regenerator column of the aqueous amine-based capture plant in Figure 1).

Steam requirements of the CCP are met by steam extracted from suitable locations in the bottoming cycle of the GTCC, e.g., the HRSG and/or the STG. One example is low pressure steam extraction from the STG, which is shown in Figure 2. Another option is to supply the low pressure reboiler steam from an auxiliary boiler. Final selection is subject to a cost-performance trade-off and operability impact study, which can be done on a case-by-case basis.

The recirculation GTG supplementary air flow requires cooling for optimal gas turbine performance. This is especially important for plant operation on hot days. The inlet cooler in Figure 2 can be an evaporative cooler, which is projected to be the most cost-effective option in most cases. However, it can also be one of myriad possibilities including electric chiller, absorption chiller (utilizing steam or hot water extracted from the HRSG or the STG) among others. The final selection should be determined on a case-by-case basis via diligent cost-performance trade-off.

Recirculation GTG can be identical to the main GTG (most likely to be the ideal configuration) or it can be of a different type and size. The final selection should be determined on a case-by-case basis via diligent cost-performance trade-off. Gas turbine fuels can be of the same type (e.g., both natural gas) or different (i.e., one natural gas and the other distillate).

Similarly, the HRSG duct burner can use the same fuel as the GTGs or a different one.Other important design parameters and decisions subject to optimization are the duct burner exit gas temperature, the location of the duct burner and the HRSG stack gas recirculation rate (commonly referred to as exhaust gas recirculation, EGR).

Higher EGR, although beneficial from a stack gas CO2 and O2 content perspective, results in warmer motive air for the recirculation GTG (plus with reduced O2 for the combustor). The discussion herein is based on calculations with 30 percent EGR. This is believed to be roughly the optimal rate. Nevertheless, a diligent optimization study is requisite to pin down the best EGR rate on a case-by-case basis.

EGR is being considered by one OEM for their next-generation gas turbines with 1,700°C turbine inlet temperature (TIT) to reduce NOx emissions. In the system adopted by that OEM, recirculated HRSG stack gas, after being cooled and mixed with ambient air, is admitted into the compressor inlet.

Tests have been conducted in full-scale combustors at medium and high pressures to demonstrate operability and NOx reduction capability with up to nearly 30 percent EGR. Another OEM has also demonstrated the effect of EGR on operability, efficiency, and emission performance under conditions of up to 40 percent EGR. Recirculation GT compressor and turbine operability considerations due to changing gas composition and molecular weight should be evaluated by the OEM at the detailed design phase.

Performance and Cost

The significance of the GTC4 is its immense capital cost benefit of about $200 million (nominal 750 MWe net), which makes it quite attractive even at expensive fuel gas (at the same net MWe output).

The advantage of the system is demonstrated by detailed heat and mass balance simulation of the power block (using Thermoflow Inc.’s Thermoflex and GT PRO software) and the amine-based post-combustion capture system (using ProMax v3.2 with a hypothetical amine of 50 percent(wt) MDEA and 5 percent (wt) Piperazine). Comparison of GTC4 cost and performance with those of a base GTCC is summarized in Table 2.

Performance and Cost
Post-combustion capture performance and cost data for the proposed system. Base GTCC is two 1×1 plants with the same main GTG (served by one large CCP).

In particular, GTC4 has the following advantages

– $182 million lower installed cost
– 25+% lower specific cost ($/kW)
– 15+% lower capture penalty (relative basis)

Note that there is a variant of GTC4 (not discussed herein but included in the patent application), which can reduce the capture penalty by 65 percent (relative basis) with the same specific cost advantage. The benefits of GTC4, vis-à -vis state-of-the-art GTCC with conventional post-combustion capture, can be enumerated as follows:

  • Higher CO2 concentration
    • Faster reaction kinetics
    • Lower regeneration energy per mole of CO2 captured
  • Lower O2 concentration
    • Reduced solvent degradation
    • Reduced reclaiming need
    • Reduced solvent consumption
  • Lower HRSG stack gas temperature
    • Reduced booster fan power
    • Reduced direct-contact cooler (DCC) duty
  • Lower volume flow (per unit energy)
    • Smaller duct, DCC and absorber diameter

In order to provide an assessment in alignment with previously published information, a cost of electricity analysis in a recent U.S. DOE NETL report is selected as a baseline. In particular, GTCC cases without and with capture, B31A and B31B, respectively are selected.

Using the cost and performance deltas in Table 2, a new capture case is calculated on an apples-to-apples basis. (Ten percent reduction in fixed and variable O&M costs is assumed.) The results are summarized in Table 3, which indicate that, even with some sacrifice in overall net efficiency, it is possible to reduce the cost of CO2 captured to about $40/ton.

Cost of CO2 Avoided and Captured
Cost of CO2 avoided and captured (as defined in section 2.7.4 of the NETL Report “Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3,” July 6, 2015, DOE/NETL-2015/1723). TASC: Total As-Spent Cost.

As the world works together to reduce or eliminate emissions of CO2 into the atmosphere, technological solutions like the optimized post-combustion CO2 capture and repowering can go a long way to deliver results.

Bechtel is working on a number of combined-cycle plants in the U.S., including Carroll County Generating Facility in Ohio, Hummel Generating Facility in Pennsylvania, and has recently completed the Stonewall Generating Facility in Virginia.


Both authors work at Bechtel. John Gà¼len is Senior Principal Engineer and Chris Hall is Project Engineer.

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