Carbon Capture and Storage  Low Emissions Combustor

Carbon Capture and Storage


Carbon Capture and Storage

Carbon capture and storage (CCS) technologies allow emissions of carbon dioxide to be 'captured' and 'stored' – preventing them from entering the atmosphere. CCS presents one of the most promising options for large-scale reductions in CO2 emissions from energy use.

CO2 capture is possible from fossil fuel power stations or from other large CO2 sources, such as the chemical, steel or cement industries or from natural gas production. CO2 can be stored in geological formations such as saline aquifers or expired oil and gas reservoirs.

The technologies for geological CCS are all proven and there are a number of large-scale CCS projects in operation today.

Carbon Capture

Using current technology, the cost of capturing and storing CO2 emitted from a new coal-fired power plant can add 30-40% to the capital cost, and approximately 60-80% to the operating costs of the plant. Approximately 2/3 of this additional cost and expense is attributable to the CO2 capture system.

The other 1/3 of the cost is tied directly to compressing the CO2. Carbon dioxide is a relatively heavy gas and this places aerodynamic constraints on conventional compressor designs that cause them to be very large and very expensive.

There are a number of carbon capture concepts being developed in an effort to reduce the associated cost and performance penalties. In all cases, CO2 is delivered to a compression system for use or storage, and the need for a CO2 compression is common to all these processes.


The inlet conditions to the compressor vary somewhat depending on the type of power plant and the specific capture process used. The discharge pressures range from 1200 psia to 2900 psia depending on intended use or storage requirements. The capacities differ, of course, depending on the size of the point source and the intended use for the CO2.

Compressors are used to compress the gas mixture to a level at which all its constituents are fully supercritical, at which point pumps may be applied to raise the mixture to the 2200 psia pipeline levels. CO2, itself, is supercritical at 1070 psia, but the impact of impurities can raise this value to 100-110 bar or 1500-1600 psia for the mixture. Typically, the CO2 is compressed to the nominal pipeline value of 2200 psia and pumps are used on the pipeline service.

Pulverized Coal (PC) - Virtually all of the existing coal-fired power plants in the world use a form of pulverized coal as their primary energy conversion process, and the only effective means of capturing the CO2 from these facilities is broadly classified into “post combustion” techniques. Modern PC plants are classified as super critical and ultra-supercritical, and based upon Rankin Cycle (steam cycle) thermodynamics with 40 and 45% HHV efficiency objectives at maturity.

There are two capture technologies being applied to these PC plants.

Amine processes, commonly used in the oil & gas industry have become the default selection because of that experience. These systems do need to be demonstrated at a power plant scale which is significantly larger than the oil & gas application requires. Post combustion capture systems typically deliver CO2 to the compressor system at pressures between 16-22 psia, and the compressor power required for these PC units range between 8-12% of the plant output, depending on capture percent, type of coal and power plant efficiency. The CO2 compressor compression ratio is 100-140:1.

Amine systems require 1200-1550 Btu/lbm-CO2 to regenerate the amines in a distillation column, to release the CO2. This regeneration heat requirement is significant and approximately ½ the main steam flow by-passes the LP turbine in order to satisfy the requirement. The LP turbine typically generates ½ the power, and by-passing ½ the steam to it, will reduce the plant output by 25%.

Ammonia-based processes, either chilled ammonia or aqueous ammonia operate at elevated pressures and the CO2 is typically released at pressure between 200-300 psia. The CO2 compressor power required is approximately 4-5% or ½ of the amine processes, and the compression ration is 8-10:1. The regeneration heat requirement is approximately 500-600 Btu/lbm-CO2, and the power plant derate is proportionately reduced. The ammonia processes are in the early stages of field demonstration at pilot scale.

Integrated Gasification & Combined Cycle (IGCC) The advanced coal power plants, referred to as FutureGen, or IGCC and Zero Emissions, all employ some form of coal gasification and reformation process to convert coal fuel into a synthesis gas mixture of H2 and CO, most often referred to as syngas.

These units would then utilize this gaseous fuel in a Brayton Cycle (gas turbine) and benefit from the inherently higher cycle efficiency of the Combined Cycle Gas Turbine at 60% LHV (54% HHV).

The principal difference, as it relates to the CO2 compressor, is that the CO2 concentration is higher reducing the cost of the capture system, and the CO2 is delivered to the compressor system at a higher inlet pressure. The concentration level and pressure are developer specific and determined by the gasifier operating pressure as well as other process variables.

The capture is typically done in a UOP-based Selexol, or a Lurgi-based Restisol process where CO2 compressor inlet pressures of 30-50 psia are common. CO2 compressor power consumption is 5-6% depending upon discharge pressure. Any of the gasification processes will require a larger-scale Air Separation Unit (ASU) that adds substantial cost and parasitic power load to the plant.

Oxy-fuel Systems – Oxy-fuel systems also use a gasification process to generate a coal syngas which is then is burned with oxygen to generate a relatively mixture of CO2 and water. Power is extracted by expanding this mixture through a gas turbine. The CO2 is then purified for storage.

The Oxy-fuel systems require a large scale ASU and the turbine exhaust pressure needs to be optimized in consideration of the CO2 compressor inlet. Turbine efficiency improves as the exhaust pressure is reduced, but compressor size and power is increased as its inlet pressure drops. Current inlet pressures are approximately atmospheric and the power consumption is approx 12% of plant rating

Regardless of the capture technology used, once captured, the intent is to sell the CO2 as a commodity or sequester it in a variety of geological formations.

There are two large-scale productive uses for CO2, one proven and one in development.

The use of CO2 for enhanced oil recovery is well-documented, proven and valuable, and there is a belief that a similar opportunity exists to recover and replace coal bed methane with CO2. The current thinking on geological CO2 sequestration is that deep saline aquifers, salt caverns and fractured basalts offer excellent opportunities for long term safe and stable storage. The planning process has and will continue to look for opportunities where CO2 sources and sinks are economically compatible.

It is clear that a lower cost and more efficient technology for compressing CO2 has become a key enabling technology to realize energy security and address global warming through carbon capture and storage.

Ramgen is in continuous contact with many of these system developers as they attempt to refine their offerings, and it is likely that those who emerge with viable commercial offerings will also become customers for Ramgen.

Carbon Storage Options
There are four general storage options currently under evaluation. Two of these represent a productive use and two are strictly methods of long term storage.

1. Enhanced Oil Recovery (EOR)
2. Enhanced Coal Bed Methane Recovery (ECBM)
3. Geological Storage in depleted oil & gas reservoirs
4. Geological Storage deep saline formations

Enhanced Oil Recovery (EOR) is by far the most important near term productive use of CO2. Not all reservoirs are amenable to CO2 injection, but the productive life of those that are can be extended by as much as 25 years and effective CO2 injection can deliver an additional 8-15% of the original oil in place. The graph shown below is a projection for Canada’s Weyburn Project and illustrates the impact.

 

The current net U.S. CO2 consumption for EOR applications is estimated at 30-35 Mega-tons/year, almost all of which comes from naturally occurring sources, either as CO2 itself or as a CO2 natural gas mix. Fifty to seventy-five percent remains sequestered, depending on who you talk with, while the balance is captured and re-injected.

Source: Meltzer Consulting

The current thinking is that the EOR applications will offer the near term and funded opportunities to further the development of the utility scale storage techniques. CO2 is currently used effectively to extend the life of current fields and yields an economic payback at the current relative pricing of CO2 and oil.

Enhanced Coal Bed Methane Recovery (ECBM) is less developed, but under investigation with the hope that similar results can be realized, and, there are important new initiatives to deploy CO2 methods to moderate the in-situ combustion as an oil shale recovery technique.

While these two productive uses will certainly be important to the development of CCS methods, large scale fossil-fuel based power generation mandates the use of large scale storage, whether saline aquifers or spent gas reservoirs, as the only effective means to deal with the huge volumes of CO2 that will be generated.


The following IPCC graphic is a representation of the entire CC&S system currently envisioned.

Schematic diagram of possible CCS systems. It shows the sources for which CCSmight be relevant, transport of CO2, and storage options (Courtesy of CO2CRC)

In addition to the ongoing and valuable EOR use, the Norwegian Government has been underwriting a demonstration project that has incorporated CO2 storage in its saline aquifers and spent oil and gas reservoirs under the North Sea. This effort has been ongoing for a decade with rigorous monitoring of the reservoir to assess the effects. This has been done to examine environmental and safety issues associated with such long term storage concepts, but just as importantly, it is seen as a proving ground for Norway’s announced goal of accepting all of Europe’s CO2 for sequestration in what they see as a vast North Sea resource.

We estimate that there will be approximately one hundred (100) 500MW coal-fired power plants built each year for the foreseeable future, representing an annual . The compressor power to compress the CO2 produced by various size and type plant is indicated below:

    1. Advanced pulverize coal - 8-12%
      1. 500MW -> 60MW -> 80,000 hp
    2. IGCC - 5%
      1. 600MW -> 30MW -> 40,000 hp
    3. CCGT - 8%
      1. 400MW -> 32MW -> 43,000 hp

     

One hundred (100) new 500MW advanced PC power plants annually will generate an $8.0 billion market for CO2 compressors at current state of the art price levels.

There are approximately 650 coal-fired power plants built after 1980 that are larger than 400MW. If half of these were ultimately converted to CC&S, the CO2 compressor potential that will result is $50 billion at current state of the art price levels.

Current Market Status

CO2 sequestration is still considered to be an emerging technology designed to address global warming concerns. The Norwegian Government, in combination with Statoil, has been successfully sequestering CO2 since 1996 and has plans to continue this effort with the addition of a major new project. At the request of the Department of Energy’s Fossil Fuel Organization, Ramgen has been an active participant in the US-Norway Bi-lateral Energy conference dealing with this issue.

 Statoil Sleipner CO2 Sequestration Project

Some form of market-based Cap & Trade System will need to be imposed, however, to create the necessary impetus for the market to evolve. The embedded assumption is that this will occur at some reasonable point and within the planning horizon, as the interest and concern over Global Warming accelerates.

Copyright © 2008 Ramgen Power Systems, LLC