User:Bettyhuu/sandbox

Hello, This is for the feedback portion of the assignment. Everything looks pretty decent. I will perhaps advise that you look more into the technical implications, where the technology falls shorts and a detailed comparison to other technologies. Cheers! -D

= Integrated Gasification Combined Cycle (article draft) =

An integrated gasification combined cycle (IGCC) is a technology that uses a high pressure gasifier to turn coal and other carbon based fuels into pressurized gas—synthesis gas (syngas). It can then remove impurities from the syngas prior to the power generation cycle. Some of these pollutants, such as sulfur, can be turned into re-usable byproducts through the Claus process. This results in lower emissions of sulfur dioxide, particulates, mercury, and in some cases carbon dioxide. With additional process equipment, a water-gas shift reaction can increase gasification efficiency and reduce carbon monoxide emissions by converting it to carbon dioxide. The resulting carbon dioxide from the shift reaction can be separated, compressed, and stored through sequestration. Excess heat from the primary combustion and syngas fired generation is then passed to a steam cycle, similar to a combined cycle gas turbine. This process results in improved thermodynamic efficiency compared to conventional pulverized coal.

Significance
Coal can be found in abundance in the USA and many other countries and its price has remained relatively constant in recent years. Out of traditional fossil fuels like oil, coal, and natural gas, coal is used as a feedstock for 40% of global electricity generation. Fossil fuel consumption and its contribution to large-scale, detrimental environmental changes is becoming a pressing issue, especially in light of the Paris Agreement. In particular, coal contains more CO2 per BTU than oil or natural gas and is responsible for 43% of CO2 emissions from fuel combustion. Thus, the lower emissions that IGCC technology allows through gasification and pre-combustion carbon capture is crucial to addressing aforementioned concerns.

Operations
IGCC plants are advantageous in comparison to conventional coal power plants due to their high thermal efficiency, low non-carbon greenhouse gas emissions and capability to process low grade coal. The key disadvantage is the amount of CO2 released without pre-combustion capture.

Process Overview
(1) Syngas Production by Gasification: Syngas is synthesized by gasifying coal in a closed pressurized reactor with a shortage of oxygen. The shortage of oxygen ensures that coal is broken down by the heat and pressure as opposed to burning completely. The chemical reaction between coal and oxygen produces a product that is a mixture of carbon and hydrogen, or syngas.

CxHy + (x/2) O2 → x CO +(y/2) H2 (incomplete combustion produces syngas)

The purity of H2 fuel is increased by subjecting syngas to a water-gas shift reaction:

CO + (x/2) H2O → x CO2 + H2

(2) The carbon dioxide is captured and impurities are removed.

(3) The resulting syngas fuels a combustion generator that produces electricity.

(4) Steam generated from cooling syngas with cooling water as well as from the gasification process is used to produce more electricity in a steam turbine.

Installations
The DOE Clean Coal Demonstration Project helped construct 3 IGCC plants: Wabash River Power Station in West Terre Haute, Indiana, Polk Power Station in Tampa, Florida (online 1996), and Pinon Pine in Reno, Nevada. In the Reno demonstration project, researchers found that then-current IGCC technology would not work more than 300 feet (100m) above sea level.[2] The DOE report in reference 3 however makes no mention of any altitude effect, and most of the problems were associated with the solid waste extraction system. The Wabash River and Polk Power stations are currently operating, following resolution of demonstration start-up problems, but the Piñon Pine project encountered significant problems and was abandoned.

The US DOE's Clean Coal Power Initiative (CCPI Phase 2) selected the Kemper Project as one of two projects to demonstrate the feasibility of low emission coal-fired power plants. Mississippi Power began construction on the Kemper Project in Kemper County, Missippi, in 2010 and is poised to begin operation in 2016, though there have been many delays. The electrical plant is a flagship Carbon Capture and Storage (CCS) project that burns lignite coal and utilizes pre-combustion IGCC technology with a projected 65% emission capture rate.

The first generation of IGCC plants polluted less than contemporary coal-based technology, but also polluted water; for example, the Wabash River Plant was out of compliance with its water permit during 1998–2001[3] because it emitted arsenic, selenium and cyanide. The Wabash River Generating Station is now wholly owned and operated by the Wabash River Power Association.

IGCC is now touted as capture ready and could potentially capture and store carbon dioxide.[4][5] (See FutureGen)Poland's Kędzierzyn will soon host a Zero-Emission Power & Chemical Plant that combines coal gasification technology with Carbon Capture & Storage (CCS). This installation had been planned, but there has been no information about it since 2009. Other operating IGCC plants in existence around the world are the Alexander (formerly Buggenum) in the Netherlands, Puertollano in Spain, and JGC in Japan.

The Texas Clean Energy project plans to build a 400 MW IGCC facility that will incorporate carbon capture, utilization and storage (CCUS) technology. The project will be the first coal power plant in the United States to combine IGCC and 90% carbon capture and storage. Commercial operation is due to start in 2018.[6]

There are several advantages and disadvantages when compared to conventional post combustion carbon capture and various variations and these are fully discussed at reference 6.[7]

Cost and Reliability
The main problem for IGCC is its high capital cost that prevents it from competing with other power plants. Currently, PC plants are the lowest cost power plant option. The advantage of IGCC comes from the ease of retrofitting existing power plants that could offset the high capital cost. In a 2007 model, IGCC with CCS is the lowest-cost system in all cases. This model estimated IGCC with CCS to cost 71.9 $US2005/MWh compared to pulverized coal with CCS that cost 88 $US2005/MWh and natural gas combined cycle with CCS that cost 80.6 $US2005/MWh. The cost of electricity value estimated was noticeable sensitive to the price of natural gas and the inclusion of carbon storage and transport costs.

The potential benefit of retrofitting has so far, not offset the cost of IGCC with carbon capture technology. A 2013 report by the U.S. Energy Information Administration demonstrates that the overnight cost of IGCC with CCS has increased 19% since 2010. Amongst the three power plant types, pulverized coal with CCS has an overnight capital cost of $5,227 (2012 dollars)/kW, IGCC with CCS has an overnight capital cost of $6,599 (2012 dollars)/kW, and natural gas combined cycle with CCS has an overnight capital cost of $2,095 (2012 dollars)/kW. Pulverized coal and NGCC costs did not change significantly since 2010. The report further relates that the 19% increase in IGCC cost is due to recent information from IGCC projects that have gone over budget and cost more than expected.

Recent testimony in regulatory proceedings show the cost of IGCC to be twice that predicted by Goddell, from $96 to 104/MWhr.[14][15] That's before addition of carbon capture and sequestration (sequestration has been a mature technology at both Weyburn in Canada (for enhanced oil recovery) and Sleipner in the North Sea at a commercial scale for the past ten years)—capture at a 90% rate is expected to have a $30/MWh additional cost.[16]

The high cost of IGCC is the biggest obstacle to its integration in the power market; however, most energy executives recognize that carbon regulation is coming soon. Bills requiring carbon reduction are being proposed again both the House and the Senate, and with the Democratic majority it seems likely that with the next President there will be a greater push for carbon regulation. The Supreme Court decision requiring the EPA to regulate carbon (Commonwealth of Massachusetts et al. v. Environmental Protection Agency et al.)[20] also speaks to the likelihood of future carbon regulations coming sooner, rather than later. With carbon capture, the cost of electricity from an IGCC plant would increase approximately 33%. For a natural gas CC, the increase is approximately 46%. For a pulverized coal plant, the increase is approximately 57%. This potential for less expensive carbon capture makes IGCC an attractive choice for keeping low cost coal an available fuel source in a carbon constrained world. However, the industry needs a lot more experience to reduce the risk premium. IGCC with CCS requires some sort of mandate, higher carbon market price, or regulatory framework to properly incentivize the industry.

CO2 Capture in IGCC
Pre-combustion CO2 removal is much easier than CO2 removal from flue gas in post-combustion capture due to the very high concentration of CO2 after the water-gas-shift reaction. During pre-combustion in IGCC, the partial pressure of CO2 is nearly 1000 times higher than in post-combustion flue gas. Due to the high concentration of CO2 pre-combustion, physical solvents are preferred for the removal of CO2 vs that of chemical solvents. The biggest obstacle with this is the need for the syngas to be cooled before separation and reheated afterwards for combustion. This requires energy and decreases overall plant efficiency. Other absorption, adsorption and membrane technologies can be used but the greatest problem with these other methods is these technologies are typically developed for purity, while compromising recovering. But the the purpose of IGCC recovery, purity can more so be compromised, with a greater importance on recovery. In other power plants, CO2 is only capture in the flue gas after combustion has occurred. This can be more difficult due to the lower concentration of CO2 in the flue gas.