Advanced Cryogenics, Ltd


Ahead to the Future - 
Other Source Types of Sequestration


Advanced Cryogenics, Ltd. is also a supplier of consulting services to emerging commercial CO2 source – types, such as current and future developments of fuel cell technologies, which in some cases, yield a CO2 by-product stream.

As for the issue of CO2 sequestration, as related to emissions reduction efforts and mandates; the company provides consulting services in the definition of all viable CO2 sinks which may be applicable to the carbon dioxide source in question. Please contact us for further information on your requirements, whether they involve emissions reduction tasks or questions, or if they should involve issues related to the refinement, production, marketing, and infrastructure which is related to the successful recovery, purification, and application of CO2 in any industry or process which may occur. The requirements for consulting services can also include expert witness requirements associated with carbon dioxide plants, markets, and businesses.


Equipment Source to the CO2 Liquid Nitrogen Trades


Advanced Cryogenics, Ltd. is also a supplier of new and surplus process, production, application, freezing, and storage equipment to the CO2 and liquid nitrogen industries. Please contact us for a current list, or state your specific equipment needs.


Changes In CO2 Sources Could Benefit New Ethanol Plants


The U.S. ethanol industry has always worked to get the most value out of all of the co-products that ethanol production creates – producers carefully watch markets for DDG, Corn Gluten and other products. Now, changes in the fertilizer industry may open a door for increased profitability from carbon dioxide (CO2) sales from ethanol plants, especially those new facilities that are now being built and planned.

A significant portion of the raw CO2 used for liquefaction/purification has traditionally come from the fertilizer industry, specifically anhydrous ammonia plants, but that is changing. The anhydrous ammonia industry is going through a period of consolidations and plant closings driven by high natural gas prices and low fertilizer import prices, explained Sam Rushing, president of Tavernier, Fl.-based Advanced Cryogenics Ltd. Capturing CO2 created during ethanol production "is a viable alternative for replacement of these lost ammonia by-product sources, particularly in light of today's many proposed ethanol projects," Rushing said.

In addition to the closing of many anhydrous ammonia plants, the CO2 industry itself is still going through a period of consolidation, noted Rushing. This process could mean even greater opportunities for new ethanol plants to maximize their CO2 revenue streams by creating new CO2 operators looking for new product sources, he said.

The CO2 market which currently have the greatest need of new product sources, and therefore offer the highest selling prices, are in the Northeast and Middle Atlantic regions. The Midwest and West Coast are also very strong markets for new production, Rushing noted. "CO2 sales represent a long-term revenue stream that should be maximized with full evaluation early in the development of any ethanol production project," he stressed.

Different Options Offer Different Returns

There are several different ways an ethanol plant can become involved in the CO2 industry, ranging from a supplier of raw material to finishing the processing and selling refined CO2 to end-users. The more processing done by the ethanol producer the bigger share of the profits they can expect, but the project costs will also increase, Rushing said.

The "easiest, care free form of marketing CO2" is by selling the raw material to a nearby processor, Rushing said. "The raw CO2 product from an ethanol project can yield a price, to an "over the fence" refiner, of between $4 and $15/ton, depending upon region," Rushing said. "This form of CO2 sale is generally sold on long – term contracts, in the order of 10 – 15 years."

Another option for some ethanol plants could be alternative buyers for the CO2 that do not require the same high level of processing. "There may be niche, captive, or emerging CO2 markets nearby the ethanol plant, which may require a less expensive CO2 production facility," said Rushing. "These nearby captive markets (such as large greenhouse operations, chemical manufacturing facilities, and enhanced oil recovery projects) may take the CO2 product with less purification, than the traditional food or beverage customer, thereby simplifying the process." In addition to simplification, the reduction in processing also results in lower building and operating costs, Rushing said.

To truly maximize the revenue potential of CO2 requires the investment in a full purification system, but that means the greatest capital and operating costs as well. "For an ethanol firm with an established infrastructure for maintenance, plant operation, marketing and distribution of the ethanol product; it may be entirely possible to produce, refine, and sell the CO2 directly to the actual consumer," according to Rushing. "The raw CO2 price is a small, when considering the typical consumer selling price in the U.S., ranging from $40/ton to well over $100/ton."

For producers without the financing to go all the way with setting up their own CO2 processing facility as part of the plant, options still exist. "Other forms of CO2 sales include a joint venture arrangement with a consortium, refiner, or CO2 firm, whereby certain expenses and revenues are divided, such that the end result is substantially more favorable than a raw gas sale," Rushing noted.

The key to making the most out of an ethanol plant’s CO2 stream is carefully considering the options and not become complacent with arrangements. "It is wise to fully examine all available markets, costs, and requirements for the carbon dioxide by-product, prior to concluding an arrangement with any one CO2 partner or purchaser," said Rushing. "It is also highly recommended that all existing raw gas sales contracts be reviewed periodically, relative to CO2 market value and options, prior to renewing with a standing wholesale purchaser."


Carbon dioxide recovery from cogeneration projects


There is a ready market for carbon dioxide for use in industrial processes as well as in food and beverage production. Recovering this gas from flue gas exhausts can provide extra income for cogeneration projects – as well as reducing emissions – as SAM A. RUSHING writes.

Numerous, very successful carbon-dioxide-from-cogeneration projects exist in the United States and other world markets today. These projects can be the best – and often, only strategically located – source for raw, and ultimately refined, carbon dioxide. That is to say, recovery facilities located at power projects are often closer to the actual CO2 markets than sources such as ammonia plants and refineries. Furthermore, in certain world markets such as the US, major, alternative commercial sources of CO2 are finding difficulty staying open today. High natural gas prices are causing problems in such areas as the ammonia industry; many anhydrous ammonia plants, typically alternative sources of CO2, are closing or reducing their production capabilities because of this. This is naturally driving up the price of CO2 from such sources.

Cogeneration is one of the most ‘portable’ means of establishing a new carbon dioxide source, and this source in turn represents a valuable revenue stream for the total cogeneration project. Otherwise, CO2 is usually sourced from anhydrous ammonia, fermentation, titanium dioxide, ethylene oxide and natural gas industries. The mergers and acquisitions that are now taking place in these areas mean that there are few options for CO2 sourcing left. In addition to creating a new revenue stream in the form of CO2 sales, the reduction of emissions through the recovery of the gas, and its subsequent refinement and application in certain commercial markets, is a significant benefit with respect to the Kyoto Protocol and other mandates for emissions reduction.

Recovery processes

Various technologies for the successful recovery of CO2 from cogeneration-based flue gas have been explored. However, the one specific technology used more frequently today, and which is the most reliable, is a modified monoethanolamine (MEA) solvent technology (shown in Figure 1). Most existing projects use MEA or a similar amine solution for recovery. Other technologies have been tried, and sometimes used less successfully, using solvents such as diethanolamine (DEA) and hot potassium carbonate. A hybrid membrane/cryogenic separation process is a possibility as well, though the CO2 content in the raw feedstock is often too low for flue gas sources.

More specifically, it is an MEA solution that has proved the most successful in recovery processes. Depending upon the licenser (i.e. Fluor Daniel) or the process, this contains proprietary inhibitors and additives to improve performance. There are minimal environmental consequences, other than a sludge by-product produced from the MEA with inhibitors used, sometimes containing metals. However, this is not generally considered a serious pollutant. Furthermore, the MEA is not maintained entirely in the system – some is lost as a vapour, and there is generally a need for additives to the amine, ranging from 1–4 lbs per ton of CO2 produced, to inhibit corrosion, foaming and other reactions.

Projects in practice

Three operating projects which recover CO2 from cogeneration-based flue gas now exist in the US, and have successfully operated since their inception. These plants supply the merchant market with a refined, liquid CO2, as well as dry ice requirements for industry. The three plants use an inhibited MEA solvent technology for the recovery of CO2 from flue gas, ranging from 3–14% (vol.) carbon dioxide in the raw flue gas. Over 70% of this CO2 is then recovered.

The AES Corporation operates recovery facilities at two CHP plants – both 320 MW, coal fired power facilities. One is located in Shady Point, Oklahoma (over 8 years old) and the other in Cumberland, Maryland (almost 5 years old), and these yield 200–250 TPD (tons per day) of liquid CO2 each, for the merchant market as well as dry ice. The AES facilities are particularly noteworthy in the US market, as they produce a food-grade product from coal-fired facilities. In the case of the Oklahoma plant, this product is sold primarily to Tyson Foods, for cryogenic freezing and refrigeration requirements. The Maryland CO2 product is sold through wholesale liquid and dry ice firms, for distribution throughout the mid-Eastern Seaboard region. The Maryland CO2 market prices are above the US average of $65/ton, though prices to the Oklahoma market are less.

The other project is a 400 MW gas-fired facility operated by FP&L, producing 350 TPD of liquid CO2 for the merchant markets as well. The FP&L facility has been operating for approximately 10 years, and has supplied the only regionally produced merchant CO2 for New England. The Bellingham facility is particularly important, since it was the first flue gas-based project constructed in the United States at a combined heat and power facility. This facility sells product to the regional wholesale CO2 trade, as a refined liquid product, which in this case, has a premium-priced US market, averaging well above the mean US price of $65/ton.

MEA technology – process description

The three cogeneration plants detailed above employ a downstream liquefaction/purification of the carbon dioxide recovered and concentrated by the MEA facility (see Figure 1, the simple MEA process). Typically, the product from gas-fired turbines in cogeneration has a raw carbon dioxide content ranging from 2.5% to about 3.5% (vol.). At the other end of the spectrum, coal-fired cogeneration facilities, such as the AES facilities in Oklahoma and Maryland, are typical of plants with a raw CO2 content of between 12–14% (vol.). The economics behind building CO2-recovery facilities mean that constructing them around turbine exhaust by-product can be more expensive than the cost of installing them at a coal-fired facility. However, when sulphur must be removed, the additional capital and operating cost for its removal can sometimes bring the overall capital and operating costs of gas- and coal-fired plants closer together. A further element, which is sometimes the most striking feature when comparing gas and coal plants, is the difference in size of the absorber and stripper column. The absorber, for example, is typically larger for the less concentrated feedstock gas, as found in the turbine exhaust model compared with the coal-fired one.

***Insert figure 1 here. FIGURE 1. The simple MEA process***

In the CO2 recovery process, the flue gas is typically collected from a slipstream using blowers. In the case of the turbine exhaust, the blowers are generally larger for the less concentrated, leaner CO2 source. The CO2 reacts with the MEA, and carbon dioxide collects at a recovery rate of 70–90%. Downstream of recovery, the gaseous CO2 can be liquefied and purified, for the commercial or merchant markets, such as industrial gas, food and beverage businesses. There may also be other CO2 markets to be served ‘across the fence’, such as certain chemical manufacturing facilities near cogeneration plant, which require the relatively high-content CO2 product from the MEA recovery. This might work very well with chemical projects such as methanol and urea-manufacturing plant, which may be situated near cogeneration facilities. An ‘across the fence’ method of marketing the CO2 from the MEA plant does eliminate the necessity for liquefaction/purification facilities, which are a major component of many CO2 projects serving the merchant markets.

After the flue gas is collected from the slipstream, it enters the direct contact cooler, where the temperature is reduced to an ambient level, generally through the use of cooling water. Next, the CO2 can be compressed somewhat, through a blower, which will prevent a pressure drop in the process. The gas then enters the absorber, and flows up through the absorber’s packed beds, and the MEA reacts chemically with the CO2 to remove much of it from the gas stream.

Next, the gas enters the wash area of the absorber, where water and MEA are removed and returned to the packed area. The washed gas is then vented to the atmosphere. The rich solution leaves the absorber and is sent to the lean/rich cross exchanger. In the cross exchanger, the rich stream is heated and the lean stream is cooled. The CO2 is removed from the rich solution in the stripper, which is heated in a reboiler using low-pressure steam. Then steam and MEA vapours leave the reboiler and enter the stripper below the packed section. The vapours move up the stripper, condensing as the CO2 is liberated, and the solution is heated. At this stage, steam and CO2 enter the wash section of the stripper where MEA is removed. The steam and CO2 then leave the stripper and enter the reflux condenser where steam is condensed, and the CO2 is cooled. The mixture enters the reflux drum where CO2 is separated from the condensate. The condensate is returned to the stripper. The lean solution leaves the reboiler and enters the cross exchanger where it is cooled, and is then pumped to the lean solvent cooler, where it is further cooled.

A side stream of cool, lean amine solution passes through the carbon bed system to remove many of the solution contaminants. General process cooling is achieved sometimes by air, but primarily with water when available. The MEA process can handle a raw CO2 content in the cogeneration-based flue gas ranging from about 3–15% (vol.) (gas- as opposed to coal-fired), and yield a high-content carbon dioxide product, in excess of 98–99% (vol.). This level of content, once again, is generally sufficient for many industrial chemical manufacturing requirements, as well as all enhanced oil recovery requirements. When a food- and beverage-grade CO2 product is sought, downstream liquefaction/purification is then required, in particular to meet food, beverage, USP (US Pharmacy Code) and related standards. If the downstream, added purification is not included in the project, project cost savings of a nominal 30% are then possible.

Required elements for recovery

The major cost factors beyond capital, when considering the recovery of CO2 from cogeneration projects, are electric power and steam. The electric power requirements of the process depend on the CO2 content of the flue gas (the leaner CO2 stream will generally require more electric power, partly for the operation of the larger blowers). There is also a physical land requirement of 1–3 acres for placement of a total CO2 facility. Other requirements include a small labour demand, and certain replacement chemicals, such as the MEA solvent and inhibitors, plus activated carbon.

As for the steam requirement, usually saturated, approximately 1600–2000 btu/lb (3700–4700 kJ/kg) of CO2 is typical, which is about 3950 lbs (1800 kg) of steam per ton of CO2 recovered. The power requirement for an average CO2 content of 8% would be some 250 kWh/ton recovered. This is for the MEA plant alone. The chemical replacement primarily includes 1–5 lbs (0.45–2.27 kg) of MEA per ton of CO2 recovered, plus inhibitors.

Potential markets

Many world markets hold high merchant CO2 prices, and few alternate sources of the raw material beyond flue gas. In such cases, the economics are in favour of the CO2 recovery project, with new revenues being made available. (Furthermore, many world regions may eventually enact mandates requiring CO2 emissions controls or reductions, as with the Kyoto Protocol.)

As to the CO2 markets which best support cogeneration-based recovery projects, these can once again include niche, or ‘over the fence’ CO2 demands, such as those chemical manufacturing businesses mentioned above. Otherwise, when recovering CO2 for the commercial or merchant markets, which typically occurs when selling to or through one of the major refining or distributor organizations, the requirement for food- and beverage-grade product will almost certainly exist, requiring a liquefaction/purification plant downstream of the recovery facility.

When serving these markets, it may be possible to find a joint venture partner, who would build and/or operate the downstream liquid-producing, refining facilities, as well as oversee quality control requirements. In all US cogeneration-based CO2 projects, the owner and ultimate operator of the MEA recovery plant has been the cogeneration firm itself, and they also own both the recovery and downstream purification – not the CO2 refiner or distributor. In two cases out of three, these CO2 firms buy the product wholesale as a liquid, refined product, for distribution and marketing. In the other instance, the cogeneration plant is producing a liquid, refined CO2, which is sold to the regional poultry processing industry for use as a refrigerant.

Table 1 shows a sample production cost analysis for a small plant recovering CO2 from cogeneration, using turbine exhaust gas as a feedstock. This small plant produces 60 tons of CO2 per day from cogeneration, and the full cost of its production is near US$107.97/ton; however, the scale of economics works in favour of larger plants. In some world markets, there may also be economic, environmental and regulatory-fostered incentives for CO2 recovery – therefore, costs may sometimes be shared or partly subsidized. In the case of cost-sharing, it is possible to share the labour and maintenance requirements between the cogeneration and CO2 projects.

Table 1. Production cost analysis for a 60 TPD CO2 plant from cogeneration-based flue gas. Assumed capital investment cost US$3.8 million***



Price (US$/ton CO2)


Raw materials

Flue gas

No cost


Steam (3.8 tons/ton CO2)



Cooling water (105,000 gal/ton CO2)



Power (250 kWh/ton CO2)



Catalysts and chemicals


Total variable costs




Operating labour

4 @ $30,000/year



100% of operating labour



4% of capital cost


Property taxes and insurance

1% of capital cost



15 years @ 9%


Total fixed costs




Total production cost



Technology applications

As outlined above, there are three US cogeneration plants that recover CO2 for the regional commercial markets using the MEA technology. In the case of both coal- and natural gas-fired plants, there are advantages and disadvantages, from both a capital cost and operating point of view. In the case of gas, it has traditionally been more environmentally acceptable to build a cogeneration plant that is not fired by coal; however, the raw CO2 content is quite lean, in the 3.0–3.5% (vol.) range. It can cost somewhat more to build a CO2 plant processing the leaner flue gas, due to the need for larger absorbers and a greater flue gas collecting capability, as opposed to the more enriched CO2 from coal. On the other hand, this latter may generally require sulphur removal, adding to the cost of construction and operation. Therefore, the potential for increased cost of operation/labour is found in both cases, gas- and coal-fired.

There are several CO2 recovery plants outside the US, which include the following:

  • Altona, Australia 66 TPD – food-grade CO2 sold to wholesale trade
  • Botany, Australia 66 TPD –food-grade CO2 sold to wholesale trade
  • Manila, Quezon City, San Fernando, Philippines 6.6 TPD each – for captive use in soft drink bottling
  • San Fernanco, Philippines 45 TPD – food-grade CO2 product
  • Uttar Pradesh, India 165 TPD – chemical usage in urea production
  • Sechuan Province, PRC 176 TPD – chemical usage in urea production.



The US market price has traditionally averaged $65/ton, on a delivered basis. Prices today are, however, higher, due to ammonia plant closures. Prices in Europe are traditionally higher anyway, and there are select markets with premium prices in regions of Asia and Latin America, for example. The plants are generally depreciated over a 15–20 year term, and the desired rate of return will vary widely, depending upon the operator.

Today, the US projects have utilized the former QF status (qualifying status), which under the former US Federal Energy Act required a steam host, hence, the utilization of CO2 recovery via steam use in the MEA process; in turn, the capital cost of the plant was included in the present-day operating projects.

The cost of production for these plants primarily comprises labour, steam, power, chemical replacement and other overheads, outside of depreciation. This form of plant operation, less the cost of depreciation, is relatively close to the cost of producing CO2 from other sources, such as ammonia. The MEA plant serves the role of concentrating the CO2 with CHP facilities, since such concentration is not actually needed for non-flue gas sources. On the other hand, environmental issues will have a greater influence on sourcing decisions over time, to the benefit of recovery facilities at flue gas sites. The benefits of sourcing from a more convenient or better located power project can sometimes outweigh the occasionally cheaper non-flue gas source, simply due to logistics and the added cost of transportation.

The cost of producing CO2 from non-flue gas sources can often range from around $20 to $30 or more per ton, fully loaded. This, however, must be looked at in the light of environmental and emissions reduction issues ahead, as well as the often poorly located options for CO2 sourcing available outside of a – frequently more convenient – flue gas source. Many factors outside of straight economics come into play, including emissions issues, and strategic location of alternative CO2 sources.


When considering a CO2 recovery project from cogeneration facilities, it is essential to evaluate the potential for niche/captive or merchant markets, plus the potential location of joint venture participants or companies which refine, market and distribute the ultimate merchant CO2. If a CO2 market is sufficient to support the project, through carbon dioxide tonnage requirements and pricing, the CO2 revenue stream gained and the possible reduction in emissions can, individually or together, produce a true added value for the cogeneration project. CO2 recovery options from cogeneration will likely improve over the coming years, with new and improved solvents and technologies; and in the end, carbon dioxide recovery from flue gas, including the exhausts from cogeneration, will be the carbon dioxide source of the future, both for economic and environmental reasons.


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