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The Current Low Carbon Power Portfolio

To address the atmospheric CO, burden, and the opportunities to successfully achieve a 2 °C temperature rise, the mix of components in the power system must be considered. The only widely available low- carbon energy sources operating in the power generation sector are limited to the following:

  • 1. Nuclear power (principally light water reactors)
  • 2. Hydroelectric, including pumped storage
  • 3. Solar—primarily photovoltaic
  • 4. Wind
  • 5. Conversion of a coal fired facility to a combined cycle (achieving nearly 60% CO, reduction)

Biomass and geothermal also qualify as low-carbon alternatives, but are available only in limited markets, and have yet to penetrate the power supply markets with greater than single digits generation (DOE/EIA, Form EIA-923, 2015). Nuclear has great potential, but a hefty financial burden. In 2018, the United States operated 100,000 MWe operating nuclear, and 2,500 MWe under construction, but as much as a third of the operating nuclear could be expected to retire in the next 10-15 years. Beyond the United States, over 50,000 MWe of new nuclear is under construction, scheduled to be online over the next decade, much of it in Asia (WNA, World Nuclear Association, 2019), but that volume is dwarfed by the additions of fossil coal expected to enter service.

Fossil fuels, and coal specifically, remain the major contributor to the global CO, emissions. Since 2000, over 1,600,000 MWe of generating capacity had been ordered, although not all that capacity appears to be fully operational as of 2018. Looking forward, the immediate order backlog of steam turbines (i.e., coal fired) is reported to be near 100,000 MWe (McCoy, 2019). Considering the various sources available, the near term continued expansion of coal generation is perhaps no less than 100,000 MWe and possibly as high as 300,000 MWe (Eudcoal.org, 2019).

This continued and rapid global buildup of even more CO, emissions from power sources seems almost irreversible just based on the near-term backlog of equipment. How the technology selection and fuel choice relate is highlighted in Figure 5. The graphic suggests that just by switching fuels, a reduction in CO, emissions occurs (based on CO, tonne/MWh as a benchmark). A typical coal plant in the U.S.,

Comparison of CO, emissions (tonne/MWh) for various fuels and technology efficiencies (Based on nominal fuel heating values and carbon content and EIA Electric Power Annual Table 8.2)

Figure 5. Comparison of CO, emissions (tonne/MWh) for various fuels and technology efficiencies (Based on nominal fuel heating values and carbon content and EIA Electric Power Annual Table 8.2).

operating at 33% cycle efficiency, would have a CO, emissions rate of approximately 0.90 tonne CO,/ MWh (depending upon the exact fuel selection) (DOE/EIA, Electric Power Annual, 2017). A combined cycle operating at a fleet average of 56% on natural gas would produce about 0.31 tonne CO,/MWh, although the actual reported efficiency is much closer to 46%. Assuming newer plants could reach the higher performance standard, coupled with a switch to gas fuel, they might yield a CO, reduction fuel equivalent to approximately 66%. This without the addition of expensive carbon capture equipment, as well as the increased operating costs associated with maintaining the more complex carbon capture equipment. And ahnost as important, since the CO, release is minimized, there is no supplemental requirement to address the technical challenge of disposing of the CO,. In the short term, this readily accessible simple solution is likely to be a top contender for a solution to reducing CO, emissions. It is also likely to establish the gas turbine as the de facto technology choice for carbon control for the next few decades. Medium term, the combined cycle may be amenable to carbon capture. Longer term, and more likely, the gas turbine cycle itself could be adapted into an oxy-fiiel system, substantially reducing the complexity of the post combustion carbon capture.

Carbon capture and CO, reduction

An overview of power generation technologies applicable for carbon capture is summarized in Figure 6. The three primary approaches include pre-combustion (in situ) and post combustion capture, except that in the case of the Oxy-Fuel, CO, is not captured directly, but isolated by removal of the FI,О from a CO,+steam mixture. Pre-combustion (IGCC) and Post Combustion carbon capture rely ahnost heavily on solvents (e.g., ethanolamine, di-ethanolamine, etc.), to extract the CO,, but then the solvents must be regenerated and recycled. There are only a few IGCC facilities operating, thousands of conventional air and vapor power cycles, and, as will be discussed next, the Oxy-Fuel design. In every case, however, proper treatment of the CO, is required prior to compression (to minimize the risk of pipeline corrosion), and ultimately the disposal of CO, in a safe reservoir.

Some current projects on coal-fired boiler retrofits include Boundary Dam (in Canada), and W.A. Parish in the United States (the Petra Nova project). Integrated Gasification Combined Cycle (IGCC)

Carbon capture in the power sector

Figure 6. Carbon capture in the power sector. CO, recovery represents one of several critical steps requued to address the CO, emission challenge. Initial fuel choice, energy conversion technology, and CO, capture method are tightly interconnected, impacting where the ultimate energy extraction occurs and the overall process efficiency.

was also expected to simplify the carbon capture process by allowing treatment of smaller volumes of carbon rich fuel prior to combustion (e.g.. Kemper and North Dakota Gasification). As of 2017, there over 25 carbon capture projects globally (CCS, 2018), although that number drops dramatically for power generation carbon capture (Kapetakia, 2017), in contrast to some 800 coal thermal plants operating in the United States alone. For those successfully operating projects, a key factor in then commercial success has been a viable storage location for the recovered CO„ as well as a revenue stream for the gas. In two projects. Petra Nova and North Dakota Gasification, CO, is sold for enhanced oil recovery. In addition, one of the original projects developed specifically to include carbon capture (Kemper) has since been converted to natural gas operation only, effectively scrapping the carbon capture elements, which contributed to much of the cost escalation (Kelly, 2018). A primary driver in this decision has been the excessive costs associated with both the gasification stages and the carbon capture components.

4.1.1 Post combustion capture

Despite so few examples in the power industry, carbon capture (CO, recovery) is widely practiced in the oil and gas industry. The extensive track record in oil and gas operations (O&G) led to the expectation that this technology could be easily adapted to power generation. To date, success in the power sector has been limited, with project costs representing a major hurdle (along with plant complexity, limited capabilities to cycle, and limited turn down capabilities). Nevertheless, costs are clearly not the only hurdle. Storage of carbon remains a major stumbling block. There are no locations in the U.S. that are permitted to store the three million tonnes of CO, that could delivered annually. All in all, CO, recovery at high concentrations (and pressures) is established practice, it just isn’t well understood how to make it work cost-effectively at a power plant, of any type, without substantially degrading plant performance. Demonstrations currently operating hat e required substantial subsidies or external funding.

In spite of this, there are those examples worth considering, such as the recent retrofit at the W.A. Parrish coal plant in Texas (Patel, 2017). While the project is based on well-established chemical principles related to carbon chemical absorption (amine absorption), moving the project forward requued investment by the Department of Energy to support the project. Plant performance was minimally impacted by providing a second power source to supply much of the required energy and heat to operate the carbon capture process. Since the supplemental power source is a combined heat and power (CHP) using a gas turbine, nominal project cost estimates would be in the range of S500-$700/kWe. Ultimately, the post combustion carbon capture on the coal unit is achieved using natural gas in a second power plant. The completed project captures roughly 33% of the carbon emissions from the retrofitted coal unit but none of the CO, from the gas fried CHOP installed to support the carbon capture2 (Dubin. 2017). The 240 MWe plant total project costs were estimated at SI billion (Patel, 2017).

4.1.2 Carbon capture-natural gas

A study fr om 2017 goes into more detail on how the process might work on a clean gas stream in a combined cycle. The work was based on modelling of power plants using a conventional amine scrubber to recover CO, from the exhaust (Carapellucci, 2017). Then results underscore the crux of any post combustion capmre: performance degradation is substantial; raising the cost of electricity, and potentially making the facility less competitive.

Results for three natural gas combined cycles (NGCC) noted in Table 2 are not wholly unexpected. The high pressure drops necessary to move the exhaust gases through the amine absorption tower, and the parasitic losses associated with recovering the amine solvent drive the plant economics into noncompetitive status. Not evident in the study is the role of cycling. In the modem grids with large renewable footprints (wind and solar), power plant cycling has become the norm, possibly with starts and stops up to four times per day. The post combustion chemical processes necessaiy to make carbon capture work are much better suited for base load operation, where temperatures, pressures, and flow rates are steady, and unchanging. The evolving power markets encountered today appear to be in conflict with the demands of the basic chemistry of solvent extraction of CO,.

Table 2. Model results for post combustion retrofit of three combined cycles using amine absoiption, with targeted 90% carbon capture. Modeled results at the source only. Compression, pumping, and injection place even greater losses on total

system available capacity.

Facility

Base plant, MW rating

Change in cost of electricity, COE

Change in capacity

NGCC 1

384

+35%

-11%

NGCC 2

153

+41%

-11%

NGCC 3

49,9

+57%

-14%

4.1.3 Carbon capture-coal

Coal’s growth, and continued contribution to the atmospheric CO, burden, will likely increase substantially in the coming decades. The large number of fossil coal plants built, under construction, or planned will easily offset any coal retirements adher ed in the United States and Europe. The implication here is that some measure of carbon control adapted to coal is necessaiy in order to realize the 2 °C temperature rise. However steep the challenge for carbon capture with natural gas, it is significantly greater for coal. A landmark study earned out by Alstom used American Electric Power’s Conesville power plant as a basis. While numerous iterations were explored, none demonstrate any result where the plant performance was not substantially degraded (Nsakala, 2001).

In tins study, three cases were considered. Two with amines and one as an Oxy-Fuel. Concept A (as describe in the paper reference) was a simple monoethanolamiue post CO, capture. Concept В was essentially an oxy-fuel conventional steam system, where nitrogen is eliminated fr om the ah' supply, and the exhaust gas is a high concentration CO, product stream, effectively avoiding the need for chemical extraction of the carbon dioxide. Concept C is a modification of the first concept, where the amine is a modified version of that used in Concept A, an attempt to improve performance and efficiency.

In every case studied, performance was substantially degraded, even though the carbon capture potential was substantial. These results are typical of what has been found in virtually every post combustion capture study. For a load serving entity (LSE), this loss of performance and flexibility would har e been unacceptable. By 2019, changing market dynamics resulted in the closure of this facility, essentially eliminating all CO, emissions, with power generation now made up by a mixture of natural gas combined cycles and renewables in the region.

1 The process treats only a portion of the exhaust from unit No. 8, extracting 90% of the CO,.

Table 3. Performance comparison of existing coal fired power plant for post combustion carbon capture. Based on AEP

Conesville Unit No. 5.

Design configuration

Power, MW, net

Plant efficiency

Carbon capture

Base Plant

433.7

35%

94%

Concept A: MEA

260.7

21%

91%

Concept B: Oxy-Fuel, no annne

279.7

23%

91%

Concept C: Modified MEA solution

341.5

23%

87%

 
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