1 Copyright 2010. Hart Energy Publishing, LP.

VOLUME 13 ISSUE 31November 24, 2010

A new study jointly authored by 11 major automakers, five major oil refiners, two electric utilities, seven industrial hydrogen producers and the European Climate Foundation concludes that hydrogen fuel cell electric vehicles (FCEVs) and battery electric vehicles (BEVs) must replace nearly all diesel/gasoline cars in order to meet the European Union target of cutting road transport “greenhouse” emissions 95% by 2050.

The study, produced (but not written) by consulting group McKinsey & Co. (see: link to document), compares the eco-nomics and “greenhouse” impact of conventional internal combustion engines (ICEs) running on petroleum and biofu-els blends versus BEVs, FCEVs and plug-in hybrid electric vehicles (PHEVs) for various vehicle segments (from small cars to large sport-utility vehicles).

Automaker study sponsors include BMW, Daimler, Ford, General Motors, Honda, Hyundai, Kia, Nissan, Renault, Toy-ota and Volkswagen.

Oil refiner sponsors include Eni, Galp, OMV, Shell and Total.Electric utility sponsors include EnBW Baden-Wuerttem-

berg AG and Vattenfall.Industrial hydrogen sponsors include Air Liquide, Air

Products, Linde Group (all of which employ steam-methane

reforming) as well as water-electrolysis hydrogen producers ELT Elektrolyse Technik, Hydrogenics, Hydrogen Technolo-gies and Proton Energy Systems.

Biofuels Can’t Meet ChallengeThe study finds that conventional ICE-cars using blends of pe-troleum and biofuels cannot meet the EU “greenhouse” targets for transportation in part because of likely shortfalls in biofuel supply – especially given likely competition for biomass feed-stock from electric power, aviation and other industries.

In this Week’s Edition of Gasification News

FEATURE: Special Report: Automaker/Refiner Study Finds EVs, Fuel-Cells Only Feasible CO2 Path

FeatureSpecial Report: Automaker/Refiner Study Finds EVs, Fuel-Cells Only Feasible CO2 Path

Integrated Gasification Combined Cycle & Synthetic Natural GasQueensland OK to Wandoan Coal Boosts IGCC Prospects

Labor Cost Hikes Pinch Duke’s IGCC Indiana Project

Saras Posts Net Loss for Q3 2010

Eneabba: Power Station Would Start on Natural Gas, Switch to UCG Syngas Later

ERG Posts €14 Million Net Loss for 3Q 2010

Mitsubishi: ‘ZeroGen’ IGCC Moving to FEED Next Year

EmberClear Reveals Global Gasification Projects, Technologies

BGL Gasifier Technology Gaining More Commercial Contracts

Gas to Liquids & Coal to LiquidsGuizhou Plans Big CTL Project

‘OMB’ Gasification Grows to 17 Projects

Cougar: No BTEX in UCG Monitoring Wells

Carbon Energy Wins Enviro OK at UCG Site

CVR Restarts UAN Unit Following Turnaround

Biomass to Liquids & Waste to EnergyU.S. TDA Looking for Bidders on Colombia WTE Project

Swedish Biomass Gasification Plant Debuts

Lack of Public Support Sinks WTE Gasification Project

EPI Wins Biomass Gasification Energy Project in Georgia

Clenergen Inks Biomass Gasification Power MoU with Yuken India

TechnologyMarket Snapshot

Gasification Hot Spots

RTI Explains Warm-Gas Cleanup Demo at Tampa Electric IGCC Plant

LanzaTech Inks Butanediol-to-Jet-Fuel R&D Deal with PNNL

Nuke-Driven CO2 Recycling Scheme: Economic ‘Green’ FT Fuel Seen

MHI Launching ‘J-Series’ Gas Turbine Tests in 2011

Regulation & LegislationAlberta Would Take Liability for Long-Term CO2 Storage

Tenaska: Voters Support IGCC-SNG Project

Carbon Capture & StorageU.S. EPA Finalizes CCS Rules; ‘Greens’ Praise Move

CO2 Leaks into Drinking Water Possible but Avoidable: Duke Study

Siemens Touts Amino-Acid CO2 Post-Capture Scheme

Plenty of Nordic CCS Capacity, but Power Cost Doubles: Study

Hydrogen Fuel Cell Car/Source: Mercedes

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However, PHEVs using biofuels blends would have a much “greener” footprint than conventional ICEs – assuming the electric portion of the vehicle’s duty cycle taps relatively “green” power recharge.

“By 2020 biofuels are blended [in the EU], delivering a 6% well-to-wheel reduction in CO2 emissions for gasoline and diesel-engine vehicles, in line with the EU Fuel Quality Directive,” according to the study.

“By 2050, this increases to 24% to reflect growing sup-plies. [However,] the biofuels market for passenger cars will face increasing competition from other sectors – especially goods vehicles, aviation, marine, electric power and heavy industry to meet the needs of these sectors and a global pas-senger car fleet of 2.5 billion cars in 2050.”

FCEV Costs Drastically DeclineAnother key study assumption: “green” FCEVs eventually would be cheaper (measured in total cost of ownership) than ICE or conventional hybrid vehicles – especially in the larger vehicle classes – from 2030 onward.

“BEVs and FCEVs are expected to have a higher purchase price than ICEs (battery and fuel cell related) and a lower fuel cost (due to greater efficiency and no use of oil) and a lower maintenance cost (fewer rotating parts),” according to the study.

“The cost of fuel cell systems is expected to decrease by 90% and component costs for BEVs by 80% by 2020, due to economies of scale and incremental improvements in technol-ogy. Around 30% of technology improvements in BEVs and PHEVs also apply to FCEVs and vice versa.

“This assumes that FCEVs and BEVs will be mass pro-duced, with infrastructure a key prerequisite to be in place. The cost of hydrogen also reduces by 70% by 2025 due to higher utilization of the refueling infrastructure and econo-mies of scale.

“PHEVs are more economic than BEVs and FCEVs in the short term. The gap gradually closes and by 2030 PHEVs are cost-competitive with BEVs for smaller cars, with both BEVs and FCEVs for medium cars and less competitive than FCEVs for larger cars.

“While the fuel economy of ICEs is expected to improve by an average of 30% by 2020, costs also increase due to full hybridization and further measures such as the use of lighter weight materials.

“For larger cars, the TCO [total cost of ownership] of FCEVs is expected to be lower than PHEVs and BEVs as of 2030. By 2050, it is also significantly lower than the ICE. For medium-sized cars, the TCOs for all technologies converge by 2050. BEVs have a small TCO advantage over FCEVs in the smaller car segments.

“Costs for a hydrogen infrastructure are approximately 5% of the overall cost of FCEVs (€1,000-2,000 [US$1,350 to $2,700] per car),” according to the study.

Staggering Investment RequirementsBuying all these “green” cars and building the required hy-drogen and “green” electric production and distribution in-frastructure would cost hundreds of billions of dollars, the study shows.

Just the hydrogen infrastructure requirements in Europe (preferably just in Germany, to start, according to the study) between now and 2020 would require €3 billion (US$4 bil-lion) to support 1 million FCEV cars, according to the study.

Between now and 2050, the hydrogen supply infrastructure in Europe to meet targeted FCEV requirements “is estimated at €100 billion [US$135 billion] over 40 years,” according to the study.

“Initial [hydrogen] investment before 2020 is relatively low as it will be concentrated in areas of high density, such as large cities. Investment in retail [hydrogen] stations is re-quired in order to reach sufficient coverage of the territory, while being initially under-utilized. Retail cost then decreases as more vehicles are deployed, with a higher utilization of the retail [hydrogen] station.

“Retail [hydrogen] investors face a first-mover disadvan-tage [but] hydrogen manufacturers have an incentive – as soon as the economics work – to race to beat their rivals. While financial incentives are required to persuade consum-ers to appreciate FCEVs, there is nothing to hold the hydro-gen manufacturers back – as long as the retail infrastructure is in place.

“In the case of infrastructure support, some form of under-writing or sharing by government of investment risk may be more appropriate – the issue being not so much the cost of building the infrastructure as the risk that the market does not develop, leaving the infrastructure a stranded asset.

“After 2030, it can be assumed that the majority of the [FCEV-buying] consumers will be financially driven, mak-ing their choice of car in response to an established tax and legislative regime. Provided these are stable and clear, car manufacturers, hydrogen manufacturers and infrastructure providers should all be able to make investments on the basis of well-understood risks and projected returns.”

25% FCEV Penetration by 2050While main conclusions in the study are based on 25% pen-etration of FCEVs in Europe by 2050, “to achieve a 50% [FCEV] penetration, the cost of infrastructure would rise by another €75 billion [US$101 billion], but there would be no significant difference in TCO [total cost of ownership] per vehicle,” according to the study.

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To achieve the greenhouse transport goals, “green” electric-ity including coal-fired integrated gasification combined cycle (IGCC) power (and hydrogen) combined with carbon capture and storage (CCS), plus other “green” hydrogen (including electrolysis-derived hydrogen) for FCEVs will have to replace most diesel and gasoline cars, according to the study.

The study analyzed scenarios where FCEVs would grab between 25% to 50% market share in Europe by 2050 (mostly in larger-car segments and for long-distance drivers), with BEVs taking another 25-35% (mostly in smaller-car seg-ments and mostly for city-only driving) and PHEVs (partly using biofuels) taking the remaining 20% to 35% share.

Following that multi-scenario analysis, the main conclu-sions in the study are based upon a “balanced scenario” where FCEVs grab a 25% market share, BEVs get 35%, PHEVs get another 35% and conventional ICEs get just 5% by 2050.

EV Infrastructure Cost“Owing to their modular nature, electrical infrastructures are easier to build up, but after 2020, infrastructure costs for FCEVs are less than those for BEVs as the number of public charging stations remains commensurate with the number of cars, due to thelengthy recharging time [for BEVs],” accord-ing to the study.

“In contrast, once the territory is covered, no further in-vestment is needed in hydrogen infrastructure – regardless of the number of cars – due to the [relatively] fast refueling time. By 2030, infrastructure for BEVs therefore costs 1.5 to 2.5¢ per kilometer, compared to 1.5¢ per kilometer for FCEVs.

“One could argue that it is inefficient to build an additional vehicle refueling infrastructure on top of existing infrastruc-tures. However, the additional costs of a hydrogen infrastruc-ture are relatively low compared to the total costs of FCEVs and comparable to other fuels and technologies, such as a charging infrastructure for BEVs and PHEVs.

“Current costs for an electric charging infrastructure range from €1,500 - €2,500 [US$2,025 to $3,375] per vehicle. The higher end of the range assumes 50% home charging (invest-ment of €200 - €400 [US$270 to $540] per charging station) and 50% public charging at €5,000 [US$6,750] for a charg-ing station that serves two cars (€10,000/US$13,500 in the first years).

“Potential additional investments in the power distribution networks are not included, but could be material, depending on the local situation.”

In contrast, “costs for a hydrogen distribution and retail in-frastructure are around 5% of the overall cost of FCEVs – the vast majority lies in the purchase price,” according to the study.

A “roll-out” scenario in the study “assumes 100,000 FCEVs in 2015, 1 million in 2020 and a 25% share of the

total EU passenger car market in 2050,” but this scenario “re-sults in a cumulative economic gap of €25 billion [US$33.7 billion] by 2020” – in other words, EU vehicle buyers (or EU taxpayers) would face €25 billion higher costs for FCEVs than cheaper ICE vehicles.

“Almost 90% of this [extra cost] relates to the relatively higher cost of the FCEV in the next decade,” according to the study.

“The CO2 abatement cost is expected to range between €150 and €200 [US$202 to $270] per metric ton in 2030 and becomes negative for larger cars after 2030.

“An incentive to ramp up [FCEV] production therefore only exists if most car manufacturers commit and coordi-nate, and government provides temporary funding support. This report assumes complete tax neutrality among the four power-trains, which allows clean comparison of technologies, but may not be realistic where practical policy is concerned. [However,] gasoline is heavily taxed throughout the EU and various green incentives are in place” that could help auto-makers hurdle the cost problem with FCEVs.

“The cost of shifting from ICEs to FCEVs may amount to €4 billion to €5 billion [US$5.4 billion to $6.7 billion] per year for Europe (€500/US$675 per new car), with the eco-nomic gap beginning to close after 2030.”

However, between now and 2020, “FCEVs face a cumu-lative economic gap (cars + infrastructure) of €25 billion [US$33.7 billion] (mainly due to a higher purchase price) and an additional €75 billion [US$101 billion] up to 2030,” according to the study.

“The TCO of FCEVs vs. ICEs falls dramatically by 2020 and is competitive with ICEs by 2030 for medium/larger cars, at which point it is anticipated that the economic gap per vehicle may be passed on to the consumer. However, the economic gap continues to rise due to increased sales.”

As for BEV recharge costs, the study finds an average an-nual investment of more than €13 billion (US$ billion) would be required over next 40 years. That’s “considerably larger than investment needed for FCEVs, but it serves more ve-hicles (~200 million BEVs/PHEVs compared to ~100 million FCEVs),” according to the study.

BEV car purchase costs over the next 40 years would total about €350 billion (US$473 billion), while PHEV purchases would added another €190 billion (US$257 billion).Home-recharge boxes for PHEVs and BEVs would cost another €60 billion (US$81 billion), while public recharge stations would cost another €480 billion (US$648 billion), according to the study.

As a result, “a cumulative economic gap of €80 billion [US$108 billion] exists for BEVs by 2020 and €500 billion

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[US$675 billion] by 2050,” compared to consumer/taxpayer costs for conventional ICE cars, according to the study.

Larger cars – the ones most likely to be FCEVs in future – account for about 50% of all EU vehicles and currently account for around 75% of all CO2 emissions in road traffic, according to the study.

“Based on current production methods, which involve steam reforming of natural gas, hydrogen cuts CO2 emis-sions for each kilometer driven by up to 30% compared with conventional petrol and diesel cars,” according to study co-author Linde, which produces hydrogen from steam-methane reforming (SMR).

The 95% CO2 reduction target “can be achieved by 2050 with the help of various hydrogen production methods, with an increasing share of renewable sources in the mix,” accord-ing to Linde.

“Linde is currently researching various production options aimed at gradually increasing the share of ‘green’ sources in the hydrogen landscape. One of these uses liquid biomass (glycerine), a by-product of biodiesel production, as the feed-stock,” according to Linde.

EU ‘Green’ Power/Hydrogen AssumptionsAccording to the study, a “conventional hy-drogen production mix is assumed to 2020, utilizing existing assets – industrially pro-duced hydrogen and centralized SMR – with a growing proportion of distributed units (water electrolysis and SMR). “After 2020, a balanced and economically driven scenario is assumed, including CO2 Capture and Storage (CCS), water electroly-sis (increasingly using renewable energy) and avoiding over-dependence on any single primary energy source.

“An alternative production mix was also examined, representing 100% electrolysis, with 80% renewable energy by 2050, which increases the total cost of ownership (TCO) of FCEVs by 5% by 2030 and 3.5% by 2050. However, both production scenarios achieve CO2-free hydrogen by 2050.” The energy supply scenario underlying the report taps the European Climate Foundation’s “Roadmap 2050”, which de-scribes a pathway to decarbonize the EU power mix by 2050. “In 2020, the expected share of renewable energy sources (RES) production capacity is approximately 34%,” accord-ing to the report. “This is the minimum needed to meet the 20% EU renewable energy target, as there is limited RES op-portunity outside of the power sector.“While the production of hydrogen from SMR with CCS re-mains the lowest-cost scenario, the 100% electrolysis pro-duction mix only increases the TCO of FCEVs (sedan car segment) by 5% by 2030 and 3.5% by 2050.

According to the study, 30% of the hydrogen supply start-ing in 2020 would come from IGCC plants, with the remain-der coming from water electrolysis plants and steam methane reforming (SMR) plants.– Jack Peckham

Source: McKinsey & Co.

Queensland OK to Wandoan Coal Boosts IGCC ProspectsThe government of Queensland announced November 12 that its independent Coordinator-General (CG) has conditionally approved the proposed A$3 billion (US$2.98 billion) Wan-doan Coal project in the Surat Basin.

The CG report is available here:www.dip.qld.gov.au/projects/mining-and-mineral-processing/coal/wandoan-coal-project.html.

The proponent is the Wandoan Joint Venture (WJV) com-prising partners Xstrata, ICRA Wandoan Pty Ltd and Sum-isho Coal Australia. The project is being managed by Xstrata Coal on behalf of the WJV consortium.

The project will now go to the Australian Commonwealth government for the next stage of its assessment under the Environment Protection and Biodiversity Conservation Act (EPBC).

If Federal approval is received under the EPBC, then the proj-ect is required to finalize mine lease applications under the Min-eral Resources Act Queensland, according to the government.

“The growing demand for commodities globally has renewed the focus on the development potential of the thermal coal de-posits of the Surat Basin in south-west Queensland,” Minister for Infrastructure and Planning Stirling Hinchliffe said.

INTEGRATED GASIFICATION COMBINED CYCLE & SYNTHETIC NATURAL GAS

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The proposed project includes an open-cut thermal coal mine, a coal handling and preparation plant and support fa-cilities. The project proponent anticipates construction of the mine and its associated facilities could commence at the end of 2011, with first coal exports forecast to begin as early as 2014.

The Wandoan Coal project also boosts prospects for the nearby Wandoan integrated gasification combined cycle (IGCC) power project, according to Stanwell Corp.’s Wan-doan power project manager Chris Walker.

“If, following the government’s conditional approval and other required approvals, the Wandoan Coal Project is devel-oped as a major export mine, then this would provide a good basis for also meeting Wandoan Power’s fuel requirements,” Walker told Gasification News.

That project would produce 400 megaWatts of power and up to 90% of byproduct CO2 emissions for geologic storage (see Gasification News 11/10/2010). – Jack Peckham

Labor Cost Hikes Pinch Duke’s IGCC Indiana ProjectLabor cost hikes threaten to absorb the entire US$89.6 mil-lion contingency fund in Duke Energy’s 630-megaWatt Ed-wardsport, Indiana, integrated gasification combined cycle (IGCC) project.

According to a November 5 Duke filing with Indiana Util-ity Regulatory Commission (IURC) cited in an Indianapolis Business Journal (Indiana) report last week, the labor cost hikes potentially could leave “no contingency for unexpected costs during startup and testing.”

Two months ago, the Indiana Office of Utility Consumer Counselor (OUCC) and industrial customers reached a settle-ment with Duke that would cap the amount ratepayers could be charged for escalating costs at the plant. The settlement,

pending before the IURC, would place a “hard cap” of $2.96 billion on construction costs.

“Our office has been concerned about the project’s contin-gencies and cost overruns for some time. Even though the pend-ing settlement includes the cap … we are still very concerned and continue to monitor the costs closely,” the report quoted Anthony Swinger, spokesman for the OUCC, as saying.

Critics of the IGCC project (including Citizens Action Co-alition) claim it would be cheaper to cancel the project even though it’s about 75% complete, according to the report.

“The new plant is projected to eventually boost the price of electricity for Duke’s Indiana customers by 16%, or an aver-age 14% for residential ratepayers,” according to the report.

Saras Posts Net Loss for Q3 2010Italy-based oil refiner/integrated gasification combined cycle (IGCC) power producer Saras reported a net loss of €13 mil-lion (US$17.8 million) for third-quarter 2010, an improve-ment compared to the €37.6 million (US$51.5 million) net loss for third-quarter 2009.

“Third-quarter 2010 has been yet again a difficult period for the refining business,” said Saras Chairman Gian Marco Moratti.

“ Margins came under pressure because of renewed con-cerns about the economic recovery, and persistently high oil inventories.”

Benchmark crude margins for Mediterranean refiners fell to a negative US$0.20/barrel in the latest quarter, he said.

“Despite such an uninspiring scenario, Saras operations were smooth and reliable, and we made further progress to-wards higher production efficiency, operations effectiveness and cost control,” Moratti said.

“The fourth quarter [2010] started with healthy margins, driven by a decrease in middle distillate inventories. This ef-fect came with a combination of higher demand and lower production, due to maintenance across refineries in Europe and USA, as well as French strikes.

“Finally, with winter approaching, the high exposure to middle distillates of the Sarroch refinery makes Saras well-positioned to capture a potential margin rebound.”

The Saras refinery in Sarroch (on the southwestern coast of Sardinia) has a production capacity of 15 million tons per year, or about 15% of Italy’s total refining capacity.

Commenting on financial results for January through Sep-tember 2010, Moratti cited “low consumer confidence, high unemployment, and reduced household incomes. Predictably, oil products’ demand followed the same patterns and, in Eu-rope, refining margins remained well below the already low levels recorded in 2009. The performance of Saras refining segment was clearly influenced by the weak market scenario.”

Refinery runs for nine-months 2010 totaled 10.5 million tons (or 76.4 million barrels, corresponding to 280,000 bar-rels per day), according to Saras.

This operating performance was 6% higher than same period last year, because the scheduled maintenance activities carried out on the crude distillation units in the first nine months of 2009 were “significantly heavier than in 9M 2010, hence caus-ing a larger reduction on runs,” according to the company.

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Despite the corporate-wide net loss in the latest quarter, “substantially higher revenues came primarily from the refin-ing and marketing segments, in the light of a reduction in the percentage of third party processing activity, as well as higher oil products’ prices,” according to the company.

Diesel fuel sales in the latest quarter traded at an average of $660/ton vs. $567/ton in third-quarter 2009, while gaso-line sold at an average $689/ton vs. $646/ton in third-quarter 2009, according to the company.

EBITDA (earnings before interest, taxes, depreciation and amortization) in third-quarter 2010 was €36.0 million (US$49.3 million), up 311% versus a net loss of€17.1 million (US$23.4 million) in third-quarter 2009. “The better result in Q3 2010 derives almost entirely from a smooth operational performance of the refining segment, which compares with important maintenance delays and conversion losses in Q3 2009,” according to Saras.

Power Segment ResultsBesides refining assets, Sarlux also owns a 575-megaWatt IGCC plant, with electricity production exceeding 4 billion kilowatt hours per year.All of the electricity is sold to the GSE (Gestore dei Servizi Energetici), the parent company of GME, the Italian national power grid manager.

In the latest quarter, the power segment “provided an im-portant effect of stabilization to the overall group EBITDA [earnings before interest, taxes, depreciation and amorti-

zation], thanks to robust operational performance, which increased production by 7% vs. 9M 2009,” according to the company.

EBITDA for the power segment rose to €33.8 million (US$46.3 million) in the latest quarter, up 154% from third-quarter 2009. However, segment net income was only €0.1 million (US$137,000) for the latest quarter, compared to a €1.4 million (US$1.9 million) net loss in third-quarter 2009.

Electric output in the quarter rose 21% compared to third-quarter 2009, while electric tariffs also rose by 18%. How-ever, the power margin (measured by Saras in US dollars per barrel oil equivalent) from the IGCC plant fell by 14% com-pared to third-quarter 2009.

“In Q3 2009, there was a cycle of maintenance activities on one train of the ‘gasifier-turbine’ section, while no major maintenance was undertaken in Q3 2010,” according to Saras.

“Comparable EBITDA in Q3 2010 was €51.8 million [US$70.9 million], up 11% vs. Q3 2009, due to significantly higher sales of hydrogen and steam, up by €5.3 million [US$7.26 million],” according to Saras.

For the remainder of 2010, “standard maintenance activi-ties on two trains of the ‘gasifier-turbine’ section of our Sar-lux IGCC plant were completed as per schedule in first-half 2010, and no further maintenance is expected for the remain-ing part of the year,” according to the company.

– Jack Peckham

Eneabba: Power Station Would Start on Natural Gas, Switch to UCG Syngas LaterAustralia-based Eneabba Gas announced November 12 that its proposed 168 megaWatt (MW) “Centauri 1” power station in Western Australia – initially to be fired by natural gas – remains the company’s “key focus,” rather than underground coal gasification (UCG).

“While the discussions with potential cornerstone inves-tors are advanced and progressing positively, they are at this stage incomplete and confidential,” according to Eneabba.

“The company reiterates that the Centauri 1 Power Station development is the principle focus of the company and that while UCG is a future environmental and economic develop-ment, it will be advanced once the Centauri 1 gas-fired Power Station is underway.

“Potential cornerstone investors are also reviewing oppor-tunities associated with the UCG potential of the Sargon coal tenements. The company believes these parties have been attracted to the Centauri 1 Power Station project due to the recent [mining demand growth] developments in the [Austra-

lian] Mid West and a relatively short time-frame required for start-up, approximately 14 months from commencement of construction, and the fact that Centauri 1 has all environmen-tal and regulatory approvals in place.

“The company has undertaken detailed discussions with iron ore mining interests in the Mid West and has been re-quested to review the total energy output by Centauri 1 from 168 MW up to 275 MW in the medium term and a possibility of up to 390 MW in the longer term, in staging development of the power station capacity.

“In addition, the environmental impact of lower carbon emissions and the future lower energy cost associated with the introduction of UCG capabilities within a possible three year time frame, is seen to be major advantage over other energy generation capabilities.

“In regards to its Sargon Tenements, the company can confirm it has undertaken the drilling on the eastern Sargon Tenements which have shown to be potential UCG capability.

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As a result of these activities the company has met its mini-mum expenditure requirements as required by Department of Mines and Petroleum.

“While the company does have an agreement with [UCG specialist] Cougar Energy regarding the development of the

Sargon Tenements, it is currently reviewing the development opportunities associated with these tenements as a result of the delays mainly caused by Cougar Energy and its ongo-ing funding and project related environmental issues [in Queensland] not yet resolved since early July 2010.”

ERG Posts €14 Million Net Loss for 3Q 2010Italy-based ERG – owner of both oil refining and integrated gasification combined cycle (IGCC) power plant assets – on November 12 reported a €14 million (US$19 million) net loss for third quarter 2010.

“The results for the [latest] quarter, which on the whole show growth, have been adversely affected by the performance of the refining sector, which was affected by a particularly un-favorable market, with margins reduced compared to the same period last year,” said ERG CEO Alessandro Garrone.

Among ERG divisions is the “coastal refining” ISAB re-finery unit in Priolo, Italy, managed in a joint venture with Lukoil. ERG also has an “integrated downstream” fuel sales joint venture with Total (dubbed “TotalErg”), as well as the 528-megaWatt ISAB Energy joint-venture IGCC plant, 51% owned by ERG and 49% by IPM.

While refining results declined in the latest quarter, “the performance of the Power & Gas division was very positive, thanks to the full contribution of ISAB Energy and the [sepa-rate, natural gas-fired] ERG Power plant, with a considerable increase in electricity production,” Garrone said.

“The results were also sustained by the fuel distribution sector and by renewables [ERG’s wind-power sector]. For the final part of [2010], despite the situation still being dif-ficult, we are expecting positive results for the Power & Gas division and in particular for Renewables, which will benefit from the full contribution of the two wind farms that were acquired in July, with a total capacity of 102 MW.

“In the refining & marketing division, we are expecting [full-year 2010] results in line with 2009, despite the unfavorable refining market continuing also into the final part of the year.”

Despite the net loss in the latest quarter, ERG’s third-quar-ter 2010 adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) improved to €79 million (US$108 million) compared to €47 million (US$64.3 million) recorded in the third quarter of 2009.

Refining and marketing segment adjusted EBITDA at replacement cost amounted to €5 million (US$6.8 million),

down from the €35 million (US$47.9 million) earned in third-quarter 2009.

The third-quarter 2010 downstream result “was primarily impaired by an unfavorable refining market, against a stable result for marketing,” according to the company.

“In 3Q 2010, the contribution from the coastal refining seg-ment was a negative €18 million [-US$24.6 million], while the contribution from the integrated downstream segment was a positive €23 million [US$31.5 million],” according to ERG.

In ERG’s Power & Gas segment, third-quarter 2010 EBITDA at replacement cost rose to €78 million (US$106.8 million), up from €12 million (US$16.4 million) in third-quarter 2009.

“This increase was mainly due to the contribution given by the new ERG Power plants to the production of electric-ity, supported by a favorable trend in energy prices and to the return to operation of the ‘powertrain 1’ at the ISAB Energy [IGCC] plant,” according to ERG.

ISAB Energy completed the reconstruction of the power-train damaged in an October 13, 2008 accident. The unit re-turned to full commercial operation on 27 May, approximately one month ahead of schedule, according to the company.

On a related front, ERG’s “hydrogen project” – involving construction at the IGCC plant of a syngas membrane-sepa-ration unit that produces hydrogen for the adjacent ISAB re-finery – went into operation in July. “The supply of hydrogen is of strategic importance in that it will enable the refinery to produce low sulfur fuels (therefore with a lower environmen-tal impact),” according to ERG.

So far this year, ERG’s middle distillate yield reached 52.4%, while the light distillates (naphtha and gasoline) yield stood at 28% of total refined products. ERG’s output of middle distillates was 1.95 million tons in the latest quarter, compared to 1 million tons of naphtha and gasoline. For nine-months 2010, ERG’s middle distillate output hit 5.5 million tons, compared to 2.9 million tons for naphtha plus gasoline. – Jack Peckham

Mitsubishi: ‘ZeroGen’ IGCC Moving to FEED Next YearWashington, D.C. – The proposed “ZeroGen” integrated gas-ification combined cycle (IGCC) project in Queensland, Aus-tralia, moves into front end engineering and design (FEED) stage next year, according to the project’s technology provider.

In a presentation to Gasification Technologies Council 2010 annual meeting here earlier this month, Mitsubishi Heavy Industries (MHI) IGCC-gasification manager Hiromi Ishii explained that the 530 megaWatt air-blown IGCC plant

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would tap experience from MHI’s 250-MW demonstration-scale IGCC plant in Japan.

The “ZeroGen” plant would capture between 65% to 90% of byproduct carbon dioxide (CO2), he said.

For ZeroGen, a coal gasification feasibility test at MHI’s 24 tons/day pilot plant was successfully completed in April 2010, followed by a feasibility study report in June and a third-party review in July, he said.

Four candidate coals were evaluated. Tests confirmed “no significant slag deposits in the gasifier” and a “stable slag discharge,” he said.

Following the FEED study next year, the next step would involve an engineering, procurement and construction con-tract in 2012, followed by construction and then completion of the plant in 2016, he said.

On another related front, MHI aims to introduce its higher-efficiency “J” class gas turbine for IGCC applications starting in 2013, he said.

MHI also launched development of a lignite pre-drying scheme this year, which eventually could boost prospects for mine-mouth IGCC or coal-to-chemicals projects in future, he said. – Jack Peckham

EmberClear Reveals Global Gasification Projects, TechnologiesWashington, D.C. – Calgary, Alberta-based EmberClear – a project development company merging with Houston-based Future Ventures – is now pursuing multiple projects around the world involving China Huaneng Power Group’s gasifi-cation technology developed by Thermal Power Research Institute (TPRI).

In a presentation to Gasification Technologies Council (GTC) 2010 annual meeting here, Bill Douglas, managing director of Future Ventures subsidiary Future Fuels, revealed that potential EmberClear gasification projects go far beyond the relatively well-known, 270-megaWatt “Good Spring” in-tegrated gasification combined cycle (IGCC) power project in Pennsylvania.

The “Good Spring” project is already “fully permitted” and if financing is secured, then it would start-up as early as 2014, he said.

Beyond “Good Spring,” other gasification projects under consideration are in Colombia, Chile, Poland, Czech Republic and the Kentucky/Indiana/Illinois region in the U.S., he said.

In a post-conference interview, EmberClear spokesman Albert Lin explained that India is also on the list of potential EmberClear gasification projects, although the first project in India “would almost certainly start with a technology other than gasification.”

Beyond gasification technology, the EmberClear technol-ogy portfolio from China Huaneng also includes an amine-based carbon dioxide capture (“post combustion capture”) technology for traditional pulverized coal power plants, an ultra super-critical technology for coal-fired power and a cir-culating fluidized-bed coal-combustion technology.

Asked whether Huaneng Power or some other source would bring any finance to the table for the Good Spring IGCC project (or any other gasification project involving EmberClear), Lin told Gasification News that “Huaneng’s financial role in any of the projects has not been disclosed. All projects with the exception of Good Spring IGCC have

a known owner and operator who would also provide the fi-nancing (mostly governments or large corporations).

“Good Spring IGCC is unique in that the developer (our-selves, in this case) is the current owner and operator. As a project developer, we do not intend to be the long-term owner and operator. As such, the ultimate financing would be largely determined by the owner/operator.

“If we are unsuccessful in finding an owner/operator for Good Spring IGCC, then we must address the funding ques-tion you pose. At this time, we have interested parties which would guarantee a purchase power agreement to obtain debt financing, but the equity portion (estimated to be 40% of total cost) is still unaddressed to this date. There are many possible avenues, but the environment is far more uncertain for such financing than in the past.”

Beyond EmberClear’s “exclusive rights” to China Huaneng Power’s gasification technology, EmberClear also has “strategic alliances with top Chinese gasifier/equipment fabricators and engineering firms,” Douglas said.

“We bundle our advanced technologies with fabrication contracts and development services to deliver low-cost, turn-key solutions,” he said.

Future Ventures/EmberClear not only is spearheading the Good Spring project but also at least one other “Pennsylvania IGCC project,” he said. Future Ventures also “controls large coal reserves in the Northeast U.S.,” he said.

Beyond just technology links, EmberClear is also “backed by China Huaneng Group’s balance sheet,” with China Huaneng having posted 2009 revenue of US$22 billion, he said. In China, China Huaneng has 130,000 employees and an installed power base totaling 115 gigaWatts, he said. A sub-sidiary, Huaneng Power, is listed on the New York Stock Ex-change with a market cap of around $9 billion, he explained.

The TRPI technology features a two-stage gasifier scheme, offered in both syngas cooler and syngas quench versions, he said.

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The entrained-flow, dry feed, oxygen blown, slagging gas-ifier employs a membrane wall rather than refractory, he said.

From 70% to 85% of a mixture of fuel/steam/oxygen is injected in the first stage, creating syngas at around 1,500 C, he said. In the second stage, up to 25% of total fuel and steam (but no oxygen) is injected. The hot syngas from the first stage creates an endothermic reaction, causing the syngas tempera-ture to drop to around 800 C after the second stage, he said.

Advantages of TPRI gasification include “high fuel flex-ibility, from petcoke to lignite” as well as “low maintenance,” with the membrane-wall life estimated at 20 years and burner life at 10 years.

The two-stage gasification scheme also reduces total oxy-gen consumption, while a relatively wide pressure range (from 0.5 to 4 MegaPascals) provides operating flexibility, he said.

The scheme also features “high carbon conversion of more than 99%” as well as “minimal gas recycle required for gas cooling” and the dry-feed system also means relatively low oxygen consumption and relatively high cold-gas efficiency of greater than 83%, he said.

Commercial experience with the TPRI gasifier includes an under-construction, 300,000 tons/year methanol plant at Shilin, China, employing a syngas quench configuration. This plant is scheduled for start-up in 2011, he showed.

The TPRI gasifier is also being employed in the under-construction, 250-MW “GreenGen” IGCC project in China, due for start-up next year.

A third project is the “Manzhouli” methanol plant, due for start-up in 2012. This plant will gasify 3,000 tons/day of lig-nite, producing 600,000 tons/year of methanol.

A fourth project is the CHNG Xinjiang synthetic natural gas (SNG) project, which would employ eight syngas-quench gasifiers, he said. The SNG would serve the Shanghai market. While a start-up date hasn’t been announced yet, “engineer-ing is ongoing,” he said.

EmberClear FY 2010 ResultsOn a related front, EmberClear announced November 4 that it posted a Cdn$14 million (US$14 million) net loss for its fiscal 2010 ended June 30, compared to a Cdn$8.8 million (US$8.6 million) loss in fiscal year 2009.

The losses include the impact of discontinued operations, according to the company.

Net cash position of EmberClear on June 30 was Cdn$5 million (US$4.8 million) with a working capital of Cdn$6.5 million (US$6.3 million), according to the company.

“In connection with [our] previously announced strategic review whereby all or portions of our camera business may be sold and cost reduction measures have been taken, all fi-nancial comparisons have been reclassified to conform to our current investment holding company status,” according to the company.

– Jack Peckham

BGL Gasifier Technology Gaining More Commercial ContractsWashington, D.C. – The “BGL” gasification technology (also known as British Gas Lurgi) is nabbing more commercial customers – especially in China.

In a presentation to Gasification Technologies Council 2010 annual meeting here, Envirotherm GmbH managing director Hansjobst Hirschfelder explained that commercial interest in the BGL technology is “considerably growing” especially for converting low-rank coal to synthetic natural gas (SNG) in Asia.

Envirotherm, a German-based subsidiary of Allied Re-source Corp. and a sister company of Pennsylvania-based Allied Syngas, offers both BGL gasification as well as circu-lating fluidized bed gasification, Hirschfelder said.

Recapping the BGL heritage, Hirschfelder explained that the improved “slagging” version of the existing Lurgi gasifier was jointly developed with British Gas from 1974 onwards in Westfield/Scotland.

The variation on the older Lurgi technology aimed to produce a non-leachable vitreous slag rather than dry ash,

improve specific reactor throughput, increase fines content acceptable in the feed, cut steam consumption and conse-quently gas condensate production, recycle tars/oils to extinc-tion and increase carbon monoxide/hydrogen yields.

Following various demonstrations on a “wide range” of coals, the first commercial-scale BGL gasifier was installed at Schwarze Pumpe, Germany, from 2000 until 2007, using broad range of feedstock including waste.

That gasifier has since been dismantled and is being reas-sembled at Haldia, West Bengal, India, for a coal-to-ammonia project, he showed.

A second BGL gasifier, identical to the former gasifier at Schwarze Pumpe, is also being built at the plant, owned by Shriram EPC Ltd.

Start-up at this plant is expected in the second quarter of 2012. In China, Envirotherm is building a BGL gasifier system

for Yuntianhua United Commerce Co.’s “Hulunbeier New Gold Chemical Co.” subsidiary at Hulunbeier in Inner Mon-golia, he said.

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Resulting syngas will be used for the production of 500,000 tons/year of ammonia and 800,000 tons/year of urea, he said.

Feedstock for this plant is domestic dried and briquet-ted lignite.

Start-up is expected in summer 2011, he said.The scheme includes three gasifiers operating at 40-bar

pressure, with syngas production of 119,000 normal cubic meters per hour.

Another China project is for Client China Yituo Group Co., at Luoyang, Henan Province. This project will produce fuel gas for an industrial project.

Two BGL gasifiers will be installed for converting local hard coal to 43,000 normal cubic meters/hour of syngas.

Start-up is expected at the beginning of 2012, he said.Yet another project involving BGL is the proposed “South

Heart Energy Development” (SHED) project, a joint venture between Great Northern Power Development (GNPD) and Allied Syngas Corporation (ASC), he said.

This project, if built, would employ three BGL gasifiers to convert local briquetted lignite (5,700 tons/day) into some 4.7 million normal cubic meters/day of hydrogen for power production, with byproduct CO2 (2.1 million tons/day) for enhanced oil recovery, he said..

In total, seven BGL gasifiers are under construction or in detailed design phase, with proposed projects including SNG, fertilizers, fuel gas, electric power and coal-to-liquids fuels, he said. – Jack Peckham

Guizhou Plans Big CTL ProjectGuizhou Yufu Energy Development Co. aims to develop a 5 million tons/year coal-to-liquids (CTL) plant estimated to cost US$11.3 billion.

According to a report from the official Shanghai Securities News, “the CTL project will apply technology developed by Synfuels China Inc., a shareholder of Guizhou Yufu Energy, and is slated to be built in Southwest Guizhou Prefecture, which boasts 7.53 billion tons of proven coal reserves.

“The National Energy Administration (NEA) has agreed to involve the project in its 2011-2015 energy development plan.”

According to a separate report from China Industry Daily News, the plant “could be the largest CTL project [ever built] in China.”

The Institute of Coal Chemistry would be a minor partner (15%) in the proposed project, according to the report.

According to a separate Reuters report quoting a statement from the Guizhou Development and Reform Commission, the CTL technology, “hatched by the Institute of Coal Chemis-try under Chinese Academy of Sciences, has been applied in three pilot projects and one of them, a 160,000 tons-per-year plant Yitai in Inner Mongolia, passed NEA [National Energy Administration] examination in July.”

That report also mentioned that China’s National Develop-ment and Reform Commission has yet to issue a final deci-sion on the proposed 80,000 barrels/day Sasol/Shenhua CTL project, which would employ Sasol’s coal gasification and Fischer-Tropsch synthesis technologies.

GAS TO LIQUIDS & COAL TO LIQUIDS

‘OMB’ Gasification Grows to 17 Projects The “opposed multi-burner” (OMB) gasification technology developed by East China University of Science & Technol-ogy (ECUST) and Institute of Clean Coal Technology has now grown to a total of 17 commercial projects, including 10 under construction.

In a presentation to Gasification Technologies Council 2010 annual meeting here earlier this month, ECUST re-searcher Xingjun Wang revealed details on many new slurry-fed gasification projects as well as developments on a new dry-feed gasification scheme.

The 17 OMB gasification projects involve 45 total gasifiers, the largest of which has a capacity of 2,200 tons/day, he said.

Of the seven plants already operating, these employ 16 OMB gasifiers in total, including five units each of 2,000 tons/day capacity.

Among the operating units, the two OMB gasifiers at Ji-angsu Linggu Chemical Co. started-up in June and August of 2009,with 318 total operating days, he said.

The produced gas has a carbon monoxide (CO) and hydro-gen (H2) content of 81% to 84%, with less-than 2% combus-tible content in the dry-slag byproduct, he said.

Similarly, the Yinchuan Shenhua gasifier operations (two operating, one spare), are producing 79% to 81% CO/H2 since start-up in March 2010, with less-than 5% combustibles

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in the byproduct slag. The three gasifiers have run between 600 to 1,200 hours so far.

On the research front, ECUST continues to make progress in investigations of a “water wall gasifier” scheme that would demonstrate gasification of coal with a relatively high ash-fu-sion point. The pilot plant at Tengzhou, Shandong, employed in these tests is the only pulverized coal entrained-flow gas-ification pilot in China, he said.

Tests on Tianba and Nantun coals with this gasifier show that CO yield varies from 62% to 65%, while H2 yield varies from 24% to 28%.

Elsewhere on the research front, ECUST aims to start-up tests of a dry-feeding OMB pilot-scale gasifier next year, at Kaiyang, Guizhou. Each of the two gasifiers will have 1,100 tons/day capacity, operating at 4.0 MegaPascals pressure and at around 1,600oC.

A separate dry-feeding gasification test program will be launched next year at China Blue Chemical Co. in Inner Mon-golia, with two gasifiers (each of 1,200 tons/day capacity) and the same 4.0 MPa pressure, he said. – Jack Peckham

Carbon Energy Wins Enviro OK at UCG SiteCarbon Energy reported November 17 that the Queensland Government Department of Environment and Resource Man-agement (DERM) has accepted the company’s environmental report on its Bloodwood Creek underground coal gasification (UCG) pilot project.

According to the company, the report “addresses the re-quirements of the [DERM] Environmental Evaluation notice

issued on July 21, 2010, and additional information notice issued on September 21, 2010.

“The evaluation related specifically to containment of surface water on site, a common situation faced by many industries and not specifically UCG, and at no time were underground activities or groundwater impacted by the incident.

Cougar: No BTEX in UCG Monitoring WellsAustralia-based underground coal gasification (UCG) specialist Cougar Energy announced November 22 that its latest series of groundwater monitoring bore tests in the upper aquifer system in close proximity to the pilot burn location at the Kingaroy UCG project in Queensland fail to show any benzene, toluene, ethyl-benzene or xylene (BTEX) contamination.

“Samples from these bores have not shown any detectable levels of BTEX chemicals and therefore do not exceed the trigger levels for Australian drinking water standards,” ac-cording to Cougar.

“Since May of this year no benzene or toluene has been detected in groundwater tests conducted by Cougar Energy on water bores and monitoring bores at distances as close as 20 meters and up to 4.2 kilometers from the company’s pilot [UCG] burn site.

“In total, 11 additional monitoring bores were recently in-stalled at distances varying from 20 to 60 meters from pro-cess well P4 (where the well casing failure took place) as part of the company’s on-going environmental evaluation work requested by the Queensland Government’s Department of Environment and Resource Management (DERM).

“The extra monitoring bores are positioned radially around P4 and allow groundwater to be sampled from different geo-logical layers in the upper aquifer system. Three of the bores did not generate water samples. All sample test results have been forwarded to DERM.

“Since April 2010 Cougar Energy has been conducting in-tensive and continuous groundwater sampling and testing at

Kingaroy after the initiation of the pilot burn earlier this year for the following results:

1. Water bores operated by local farmers: 23 bores located 1.3 to 4.2 kilometers from the pilot burn have been sam-pled; 227 water samples were collected and 5,192 sepa-rate chemical tests undertaken. No benzene or toluene above detectable or trigger limits was found.

2. Monitoring bores installed by Cougar Energy: Ten bores located 20 to 276 meters from the pilot burn have been sampled; 135 water samples were collected and 7,748 separate chemical tests undertaken. As pre-viously advised, two isolated and transient measure-ments of benzene (2ppb) above drinking water levels were detected in one well sampled in May.

“Based on these groundwater sampling and testing re-sults, Cougar Energy is confident that the pilot burn at its Kingaroy site has had no adverse impact on landholder water bores.

“DERM has advised the company that, pursuant to the Queensland Environmental Protection Act 1994, the decision date on whether to accept both Environmental Evaluation re-ports has been set for January 17, 2011. This assumes the company delivers all of the requested materials by December 10, 2010, and that DERM does not make any new requests for information.

“Cougar Energy continues to work with DERM to ensure the re-commencement of the Kingaroy trial project at the ear-liest possible time.”

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CVR Restarts UAN Unit Following TurnaroundFollowing a rupture in a high-pressure vessel on September 30, CVR Energy has since repaired the unit and as of Novem-ber 16 has restarted urea ammonium nitrate (UAN) produc-tion at its Coffeyville Resources Nitrogen Fertilizers plant.

“Because of the rupture affecting the UAN vessel, the company moved up a planned biannual turnaround for the entire plant by a few days. With the turnaround completed on October 29, the company subsequently has been produc-

ing and selling only anhydrous ammonia fertilizer pending resumption of UAN production,” according to CVR.

CVR also operates an adjacent 115,000 barrel per day oil refinery in Coffeyville, Kansas, which produces transportation fuels.

The byproduct petcoke produced at the refinery is re-used as feedstock for a GE (formerly Texaco) gasifier that pro-duces syngas for ammonia and UAN production.

Synthesis Energy Systems Posts US$3.8 Million Loss for FY 1Q 2011Houston-based Synthesis Energy Systems (SES) announced November 10 that it lost US$3.8 million in fiscal first-quarter 2011 (ending Sept. 30) versus a net loss of $5.0 million in fiscal year first-quarter 2010.

The company, which licenses the “U-Gas” gasification technology from Gas Technology Institute, reported $1.6 mil-lion in revenue for the latest quarter, down $0.73 million from the prior-year quarter.

In the latest quarter, SES’s Zao Zhuang joint-venture gas-ification plant in China operated at only 31% of capacity be-

cause of extended shutdowns at the neighboring methanol plant that receives the gasification plant’s syngas. That was down from 54% capacity in the prior-year quarter.

Technology licensing and related services revenues in the latest quarter totaled $0.2 million, generated from coal testing, feasibility studies and other technical services provided in as-sociation with the company’s technology licensing business.

U.S. TDA Looking for Bidders on Colombia WTE ProjectU.S. Trade & Development Administration (USTDA) an-nounced November 17 that it’s offering a US$$573,039 grant for a feasibility study “to determine the technical, economic and financial viability of a 20 megaWatt waste-to-energy [WTE] plant” in suburban Medellín, Colombia’s second-largest city.

Asked whether gasification-based WTE technology would be acceptable, USTDA country manager Jacob Flewelling told Gasification News that both mass-burn and gasification technology would be considered.

“As is suggested in the Grant Agreement and the Definitional Mission report, this project is by no means only for consider-ation of mass burn WTE technology,” Flewelling told us. “ The Grantee [Instituto Para el Desarrollo de Antioquia (IDEA)] is

interested in proceeding with the WTE technology that is most viable technically and economically in accordance with the ex-isting waste stream.”

According to the USTDA summary of the proposed project (see: link to document), IDEA “invites submission of qualifi-cations and proposal data from interested U.S. firms that are qualified on the basis of experience and capability to develop a feasibility study to determine the technical, economic and financial viability of a 20 MW waste-to-energy plant . . . .

“IDEA is the autonomous regional development institution in Antioquia and has participated in the development of numer-ous energy, infrastructure, mining and reforestation projects.

“The WTE plant would be fueled by the collected urban and industrial wastes from five municipalities south of

BIOMASS TO LIQUIDS & WASTE TO ENERGY

“As part of the evaluation, a comprehensive soil testing program was undertaken and has been independently assessed by a tier 1 environmental consultancy, which confirmed that there were no ongoing effects or environmental harm.

“As part of its report, the company detailed the engineering and operating changes it has established on site to ensure that any reoccurrence is mitigated and has already put in place additional environmental controls.

“DERM has further advised that, prior to gasification com-mencing for the company’s UCG Panel 2, it intends to amend some of the environmental conditions for the site to reflect the outcome of the environmental report and the company’s proposed mitigation measures.”

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Swedish Biomass Gasification Plant DebutsSveaskog – Sweden’s biggest forest owner – on November 18 announced the inauguration of a 1 megaWatt biomass gasifica-tion pilot plant in Sweden that could boost prospects for future, commercial-scale, bio-based methanol, dimethyl ether, ethanol, synthetic natural gas (SNG) and Fischer-Tropsch diesel.

The research plant will gasify forestry wastes (branches and tops) for “green” energy.

The SEK 25 million (US$3.6 million) test plant – jointly developed by Sveaskog, Smurfit Kappa, IVAB and the ETC Gasification Center in Pitea – will employ a pressur-ized entrained flow biomass gasification (PEBG) technol-ogy from IVAB.

According to a Lulea University of Technology summary, the project is divided into two joint sub-projects, PEBG A and PEBG B.

“PEBG A shall establish a 1 MW pilot plant of an en-trained flow gasifier,” according to Lulea.

“With focus on design, construction and operation, the gas-ifier will also provide experimental data and unique test op-portunities for the PEBG B project, which focus on research of entrained-flow gasifiers.

“The goal is to find the best way to develop and oper-ate a gasifier. This includes issues from material selection, to more global questions about optimization and integration with other processes.”

Besides funding from Sveaskog, IVAB and Smurfit, the Swedish Energy Agency is also contributing funds, accord-ing to Lulea.

Next door to the plant is Chemrec’s black-liquor gasifica-tion plant, which will produce bio-DME.

Also nearby is the Sunpine biomass-to-liquids (BTL) Fischer-Tropsch diesel plant in which Sveaskog is a partner. That plant is converting pine oil to “green” diesel (see Diesel Fuel News 03/29/2010).

In an interview with Gasification News, ETC senior scien-tist Magnus Marklund explained more details about the new Sveaskog-Smurfit-IVAB-ETC project.

Gasification News: How many tons/day of biomass will be processed at this plant?

Marklund: This is a pilot plant that will be run in a cou-ple of experimental campaigns/year at a nominal capacity of ~100 kilograms/hour at 5 bar (a) pressure.

Gasification News: What type of product will be pro-duced? Will it be dimethyl ether, methanol, electric power, synthetic natural gas, Fischer-Tropsch fuel or something else? And how much product will be produced, per year?

Marklund: The main focus is just to produce syngas but with a possibility to take a side stream for tests in a catalytic lab rig for methanol synthesis.

Gasification News: Are there more technical details avail-able describing the IVAB biomass gasifier? A key issue with biomass gasification is how to deal with the byproduct tars that are formed with biomass gasification. There are vari-ous ways to capture or destroy these tars, but what is IVAB’s solution to this issue?

Marklund: Currently there are no details available other than simple process flow diagrams. When it comes to tars, our approach is to try to limit the amounts formed in the reactor, remove as much as possible in the quench and characterize the resulting product gas.

Medellín that are currently deposited at the “El Guacal” landfill in the Municipality of Heliconia, about 25 kilometers from Medellín.

“The WTE plant is anticipated to be sited on the property of the El Guacal landfill, which is owned and operated by EVAS Enviambientales (EVAS). EVAS is responsible for the treatment and final disposition of solid waste at the El Gua-cal landfill and is licensed for 24 years to receive, select and process ordinary and special solid waste and mud.

“EVAS is a sanitary and landfill operator company in Colombia, fully owned by the Municipality of Envigado, but which serves much of the southern Aburrá Valley area in Antioquia.

“The waste processing and power generation facility will input the roughly 650 tons per day of municipal solid waste (MSW) presently deposited at the EVAS landfill and convert it to roughly 400 tons of refuse-derived fuel for the generation of approximately 20 MW of electricity.

“With collection and landfill deposits well managed by EVAS, these wastes have been studied and classified, con-firming a sufficient calorific value with a steady and con-tinuous daily flow. The owner and operator for the proposed WTE plant is anticipated to be a joint venture (JV) between IDEA, the Municipality of Envigado, and possibly a private sector engineering firm.”

A detailed Request for Proposals (RFP), which includes requirements for the Proposal, the Terms of Reference, and a background definitional mission report, is available from USTDA at: https://www.ustda.gov/businessopps/rfpform.asp.

“Interested U.S. firms should submit their Proposal in English and Spanish directly to the Grantee by 5 p.m., December 7, 2010,” according to USTDA.

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Gasification News: Does this plant have all required gov-ernment permits, especially the air pollution permit limiting any criteria pollutants (such as particulate matter, nitrogen oxides, carbon monoxide, volatile organic compounds, “air toxics” such as dioxins/furans etc.)? Does the process have certain advantages in limiting such pollutants?

Marklund: We have not yet gotten the final formal ap-proval for full start up of the plant but we expect to have this in January 2011. – Jack Peckham

Lack of Public Support Sinks WTE Gasification Project A total lack of public support (aside from the companies involved) explains why a U.K. government planning appeal inspector this month decided against approving a proposed gasification-based waste-to-energy (WTE) project in Derbyshire, U.K.

According to the appeal decision (see: link to document), pub-lic hearings resulted in 85 people opposing the scheme. “Nobody spoke in its favor,” according to the inspector’s decision record.

The WTE project technology proponent, Resource Recovery Solutions (Derbyshire), faced opposition from neighborhood groups including “Sinfin, Spondon and all Against Incineration (SSAIN), Derby Friends of the Earth (FOE); Derby City Coun-cillors and Derbyshire County Council members.

The plant would have gasified 190,000 metric tons/year of garbage to produce a net 8 megaWatts of “green” grid power. But neighbors objected to the building’s appearance, noise, increased truck traffic and potential plant or truck-traffic emissions, according to the decision.

While a small amount of particulate matter (PM10) would be emitted from the stack, the resulting public health impact would be negligible, according to the decision.

“The life expectancy of those whose health is already seri-ously compromised is predicted to be shortened by a fraction of

a second,” according to the decision. “The shortening of a life, by however small an amount of time, is something that goes against the grain of normal human aspirations. However, com-mon sense suggests that a fraction of a second’s reduction in the length of somebody’s life would, in reality, be undetectable.”

The decision also took note of residents citing a faulty ret-rofit WTE plant on Isle of Wight that has at times emitted eight-times more dioxin than permitted. The fault isn’t in the gasification section, but rather in a poorly executed retrofit section, according to the technology provider.

“Local residents’ fear about harmful health effects is not something that in itself warrants a dismissal of this [project]. It is nevertheless a material consideration of some weight,” according to the decision.

An increase in nitrogen dioxide emissions from various oper-ations connected to the plant were of greater concern, however, because of existing industrial and traffic emissions in the area.

“I consider that the proposed [WTE plant] has the potential to make a bad situation worse,” according to the inspector’s decision. “The living conditions of local residents in this de-prived part of Derby would not only be adversely affected but would also be unacceptably worsened.”

– Jack Peckham

EPI Wins Biomass Gasification Energy Project in Georgia Idaho-based Energy Products of Idaho (EPI) announced No-vember 17 that it has won a contract for a 53 megaWatt bio-mass gasification plant in Barnesville, Georgia.

The “Piedmont Green Power” plant would employ EPI’s staged gasification system converting biomass materials into 480,000 pounds per hour of superheated steam at 1,005°F and 1,500 pounds/square inch pressure for the electric power plant.

Zachry Industrial is the engineering, procurement and con-struction (EPC) contractor for the entire project, according to EPI.

“EPI’s fluidized bed technology has been utilized to handle hundreds of renewable biomass fuels and many other traditional and non-traditional fuels, such as agricultural wastes, municipal wastes and cattle manure,” according to the company. “In this application, EPI’s advanced staged gasification technology al-lows chipped biomass materials to be utilized as a fuel.”

According to an earlier announcement from North Caro-lina-based Rollcast Energy, which is financing the project, Georgia Power would receive the power under a long-term power purchase agreement.

Rollcast announced October 21 that it had closed non-re-course, project financing for the project.

“The terms of the financing include an US$82 million con-struction and term loan and a $51 million bridge loan related to the treasury grant,” according to Rollcast.

MUFG Power and Utilities and Investec are the lead ar-rangers and joint bookrunners for the financing. In addition, Atlantic Power Corporation, which owns approximately 60% of Rollcast, will provide the equity for the project, making an equity contribution of approximately $75 million for sub-stantially all of the equity interests in the project,” according to Rollcast.

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Clenergen Inks Biomass Gasification Power MoU with Yuken IndiaU.S.-based biomass energy specialist Clenergen on Novem-ber 16 announced a memo of understanding with Yuken India for a proposed 4 megaWatt (MW) gasification biomass power plant at Bangalore, India.

The resulting syngas would be burned in gas engines to generate power at Yuken’s manufacturing plant. “The gasifi-cation will provide Yuken a secure and sustainable supply of renewable electricity on site,” according to Clenergen.

Yuken manufacturers of oil hydraulic equipment.Under the deal, Clenergen would enter into a minimum 15-

years power purchase agreement (PPA) to supply Yuken up to the 2.5-MW/hour, with the balance of electricity generated being sold to India’s national grid, according to Clenergen. The 4 MW biomass power plants will be installed and opera-tional within 10 months upon signing of the PPA, according to the company.

“Clenergen India will lease up to 800 acres of non-arable land near the manufacturing site in order to grow a high yield-ing species of bamboo as a source of biomass for the gasifica-tion power plant,” according to the company. “After 10 years of breeding and fertilization programs, the bamboo is produced from tissue culture, resulting in an asexual, non-invasive, non-flowering plant which a lifespan of up to 50 years.”

Commenting on the deal, C. P. Rangachar, managing di-rector of Yuken India, said: “Energy security is critical to our manufacturing operations. Regular shortages of electric-ity within the southern states of India are now affecting our supply chain. Clenergen offers our company a turnkey, cost effective and sustainable solution to this problem.”

TECHNOLOGY

Market Snapshot

“Zachry, the project’s EPC contractor, will be released to begin construction immediately and Rollcast expects the project to be operational by the fourth quarter of 2012. Delta Power Services, a subsidiary of Babcock & Wilcox, will pro-vide operations and maintenance services and an affiliate of Rollcast will be the project’s asset manager.”

The project will utilize 500,000 tons of woody biomass annually, 100% of which will come from the local region, according to the company.

In an interview with Gasification News, EPI sales and mar-keting director Kent Pope told us that his company developed a fluidized bed gasification system in the 1980s “and we have produced many systems since then.

“These systems range in size from 5 MWe (or equivalent energy/steam) up to 60 MWe gross or 53.5 MWe net.

“In many of our gasification systems, we completely con-sume the [byproduct] tars prior to extracting the energy from the gas. In other systems designed to produce syngas for an engine or gas to liquids process, the tars are a byproduct of gasification but our technology does not produce heavy tars.

“Light tars are much easier to remove with cleanup tech-nologies, which make EPI’s gasification system ideal for these applications as well as the boiler or hot gas applications.

“This technology does not make any smells, and we are well within the very tight emissions standards for the area.

“Emissions of dioxins and furans are more associated with older grate type garbage burning systems as they are formed when there is chlorine (typically from PVC plastics) in the fuel and high carbon monoxide (CO) levels.In this case the fuel is wood and we produce extremely low amounts of CO.” – Jack Peckham

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Gasification Hot-Spots

AUSTRALIACarbon Energy UCG

JAPANMitsubishi IGCC

INDIAClenergen Project

FLORIDATEC Warm Gas Cleanup

UNITED KINGDOMWTE Protests

KANSASCVR Restart

CHINAGuizhou CTL

SWEDENBiomass Gasi�cation

Test Launch

ITALYSaras 3Q Results

COLOMBIAWTE Gasi�cation Project

• Colombia:WTE Gasification Project

• Sweden: Biomass Gasification Test Launch

• UK: WTE Protests.

• India: Clenergen Project

• China: Guizhou CTL

• Australia: Carbon Energy UCG

• Kansas: CVR Restart

• Italy: Saras 3Q Results

• Japan: Mitsubishi IGCC

• Florida: TEC Warm Gas Cleanup

RTI Explains Warm-Gas Cleanup Demo at Tampa Electric IGCC PlantWashington, D.C. – Warm syngas cleanup technology devel-opment will continue at the Tampa Electric integrated gasifi-cation combined cycle (IGCC) plant in Florida.

In a presentation to Gasification Technologies Council 2010 annual meeting here, Research Triangle Institute (RTI) researcher Raghubir Gupta explained the latest developments for the novel technology.

U.S. Department of Energy (DOE) recently announced it will grant US$169 million for 50-megaWatt demonstration-scale tests of the scheme, combined with carbon capture and storage (CCS), at the Tampa IGCC plant (see Gasification News 09/15/2010).

The RTI technology, earlier tested at pilot scale in coop-eration with Eastman Chemical, removes sulfur, heavy metals (mercury, arsenic, selenium) and other contaminants includ-ing hydrogen chloride, ammonia and hydrogen cyanide.

The system, employing a zinc-oxide adsorbent, operates at temperatures exceeding 450ºF, is pressure independent and is effective at removing both hydrogen sulfide and carbonyl sulfide, Gupta explained.

The scheme offers both capital-cost and operating-cost ad-vantages compared to conventional Rectisol or Selexol syn-gas cleanup, he showed (see chart).

The system can be employed not only for IGCC applica-tions but also for methanol, Fischer-Tropsch fuel and syn-thetic natural gas applications, he said.

In more than 3,000 hours of pilot-plant tests at Eastman Chemical with coal-derived syngas, the researchers demon-strated that the scheme achieves greater than 99.9% removal of both H2S and COS simultaneously, with less-than five parts per million effluent sulfur independent of operating pressure, and with sorbent attrition rate of around 60% of commercial fluid catalytic cracking systems, he said.

The “Direct Sulfur Recovery Process” (DSRP) included in the system achieved more than 99.8% SO2 conversion to elemental sulfur, 96% ammonia removal and 90% mercury and arsenic removal, he said.

For the larger-scale demonstration at Tampa Electric, the researchers aim to establish RAM (reliability, availability and maintenance) targets, mitigate design and scale-up risk for a

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<0.05 ppmv total sulphur

SULPHUR

CO2

250300350400450

200150100

500

RECTISOL

<20 ppmv total sulphur <0.05 ppmv

total sulphur

SELEXOL WGC+ aMDEA

Capi

tal C

ost o

f Syn

gas

Clea

ning

and

CCS

Syst

ems

($/k

W)

Capital Costs

% H

HV E

ffici

ency

SULPHUR

CO2 SULPHUR

50

0

10

20

30

40

RECTISOL SELEXOL WGC+ aMDEA

Thermal Efficiency

7.16

9.14

6.478.23

COE (kWh) COE (kWh)

Source: RTISource: RTI

commercial plant, and capture and sequester 300,000 tons/year of carbon dioxide employing a conventional activated amine technology from BASF.

For the high-temperature desulfurization process (HTDP) transport reactor portion of the demonstration, the researchers aim to achieve sulfur reduction to less-than 10 parts per mil-lion, on a 50-MW scale over 8,000 hours of operation.

For the DSRP portion of the demonstration, they aim to achieve greater than 95% SO2 conversion to elemental sulfur, also over 8,000 hours.

As for removal of metals, they aim to achieve greater-than 90% removal at a 5-MW scale.

The researchers have completed a “pre-FEED” (front-end engineering and design) package, while a cost estimate is “in progress,” he said.

The BASF “aMDEA” amine process technology for CO2 capture is touted as having relatively high absorption ca-pacity and kinetics, relatively low energy for regeneration, thermal and chemical stability, non-corrosive, non-toxic and “readily biodegradable.”

“Potential integration options for syngas require effective H2S removal prior to non-selective H2S and CO2 removal with solvent,” he said. “Integration [of CO2 capture] with warm syngas cleanup results in lowest capex and opex be-

cause of reductions in equipment size and energy consump-tion in each system.”

Assuming that permitting and construction plans move for-ward as scheduled, operation of the system at Tampa could begin in 2015, he showed.

Tampa Electric “has studied the potential of CO2 storage” underneath the IGCC plant, in a “suitable saline aquifer.” The resulting underground CO2 plume “would not extend beyond property limits,” he said.

Nevertheless, “critical design issues” for the project in-clude “permitting for CO2 sequestration in a deep saline aquifer in Florida,” as well as a CO2 specification for se-questration. Other crucial issues include “optimization of the shift reactor” and “operation of the GE 7FA gas turbine on hydrogen-rich syngas,” he said.

Assuming all the obstacles are hurdled, the proposed inte-gration of warm gas cleanup and aMDEA CO2 capture would enable lower capital cost and higher thermal efficiency for integrated syngas cleaning and CCS, he said.

If successful, the demonstration would “mitigate technol-ogy risk for warm gas cleanup, CCS, integration with hydro-gen turbines and integration with high temperature hydrogen membranes,” he said.

– Jack Peckham

LanzaTech Inks Butanediol-to-Jet-Fuel R&D Deal with PNNLNew Zealand-based LanzaTech announced November 16 that it signed a cooperative research and development agree-ment (CRADA) with the U.S. Department of Energy’s (DOE) Pacific Northwest National Lab (PNNL) for butanediol-to-jet-fuel conversion.

“LanzaTech’s clean energy technology can produce 2,3-Butanediol (2,3-BD), an oxygenate which can be used to

make hydrocarbon fuels – true drop-in fuels that can replace diesel, jet fuel and gasoline – and high value chemicals,” ac-cording to LanzaTech.

“The U.S. has spent billions on its existing petroleum in-frastructure and to redesign airline jet engines costs in the realm of hundreds of millions of dollars,” said Jennifer Hol-mgren, LanzaTech’s chief executive.

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“The biofuels that will succeed must be compatible with existing engines, pipelines and refineries. LanzaT-ech’s integration of the fuels and chemicals value chain enables economic viability, as well as being environmen-tally sound.”

The first phase of the CRADA work will be done over one year, with the DOE funding PNNL and LanzaTech making an “in-kind” contribution, according to LanzaTech.

“Existing LanzaTech and PNNL collaborations with teams at Tsinghua University and the China National Offshore Oil

Corporation, which are performing techno-economic and life cycle evaluations, will also contribute to the work,” accord-ing to the company.

LanzaTech first made its mark in development of technol-ogies for the production of lower- cost ethanol from off-gases produced by the steel industry, with first development efforts occurring in china.

Since then, LanzaTech has expanded the focus of its pro-cess development program to include other industrial off gases and synthesis gas from gasification.

Nuke-Driven CO2 Recycling Scheme: Economic ‘Green’ FT Fuel Seen“Zero-carbon” nuclear power or renewable power with an operating expense cost (excluding capex) of around US$0.05/kiloWatt-hour (kWh) potentially could be em-ployed to recycle byproduct carbon dioxide (CO2) and water into Fischer-Tropsch motor fuels at around $3/gal-lon, according to a new study.

The study, published in the scholarly journal, Renew-able and Sustainable Energy Reviews (Volume 15, Issue 1, January 2011), summarizes the work of Columbia University (U.S.) and Denmark-based energy researchers.

According to their summary, “we estimate that the full sys-tem can feasibly operate at 70% electricity-to-liquid fuel effi-ciency (higher heating value basis) and the price of electricity needed to produce synthetic gasoline [or diesel] at US$2/gal-lon is US$0.02 to $0.03 cents/kWh. For $3/gallon gasoline [or diesel], electricity at 4–5 cents/kWh is needed.”

The study (see: link to source) points out that “while fossil-derived synthetic fuels (e.g. coal derived liquid fuels) and bio-fuels have received the most attention, similar hydrocarbons can be produced without using fossil fuels or biomass.

“Using renewable and/or nuclear energy, carbon dioxide and water can be recycled into liquid hydrocarbon fuels in non-biological processes which remove oxygen from CO2 and H2O (the reverse of fuel combustion). Capture of CO2 from the atmosphere would enable a closed-loop carbon-neutral fuel cycle.

“Dissociation methods include thermolysis, thermochemi-cal cycles, electrolysis, and photoelectrolysis of CO2 and/or H2O. High temperature co-electrolysis of H2O and CO2

makes very efficient use of electricity and heat (near-100% electricity-to-syngas efficiency), provides high reaction rates, and directly produces syngas (CO/H2 mixture) for use in con-ventional catalytic fuel synthesis reactors.

“Capturing CO2 from the atmosphere using a solid sorbent, electrolyzing H2O and CO2 in solid oxide electrolysis cells to yield syngas, and converting the syngas to gasoline or diesel by Fischer–Tropsch synthesis is identified as one of the most promising, feasible routes.

“In some regions that have inexpensive renewable [geother-mal] electricity, such as Iceland, fuel production may already be economical. The dominant costs of the process are the electric-ity cost and the capital cost of the electrolyzer, and this capital cost is significantly increased when operating intermittently (on renewable power sources such as solar and wind).

“Once-through re-use of CO2 results in net CO2 emis-sions of approximately one-half the emissions that would occur without any re-use (both from the industrial plant and from transportation [and] continuous closed-loop car-bon recycling via air capture of CO2 [would] result in near zero net emissions. These approximations neglect life-cycle emissions of energy generation, CO2 capture, materials, construction, etc.

Capital costs for such a scheme would be in a similar range as . . . plants such as coal and natural gas-based liquid fuel production], but lower than estimates for large alkaline elec-trolysis plants,” according to the researchers. “The level of automation of the facility will likely have a large impact on the operations and maintenance cost.” – Jack Peckham

MHI Launching ‘J-Series’ Gas Turbine Tests in 2011Mitsubishi Heavy Industries (MHI) announced November 15 that it’s launching tests in February 2011 of a “J-Series” gas turbine touted as delivering “the world’s largest power gen-eration capacity and highest thermal efficiency in the 1,600°C turbine inlet temperature class.”

In preparation MHI has started conversion work on the combined-cycle power plant for verification testing at its Ta-

kasago Machinery Works in Hyogo Prefecture, which until now has conducted verification testing of the company’s G-Series gas turbines, and began installation of the J-Series gas turbine on November 13.

“The new turbine is able to withstand 100 degrees higher temperature than the 1,500°C-class G-Series gas turbine, the top-of-the-line until now,” according to MHI. “The 60

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hertz J-Series gas turbine achieves a rated power output of about 320 megaWatts (ISO basis) and an unprecedented 460-MW in gas turbine combined-cycle (GTCC) power genera-tion applications,” according to the company. “MHI has also achieved over 60% gross thermal efficiency – the world’s highest level in GTCC applications.”

The new turbine used in combined-cycle configuration would enable a 50% cut in net CO2 emissions compared to conventional coal-fired generation for equivalent power out-put, according to MHI.

As for nitrogen oxide (NOx) emissions, which usually in-crease as combustion temperature rises, NOx output from the gas turbine is “suppressed to a level equivalent to that of cur-rent models,” according to MHI.

Following tests at Takasago Machinery Works, “MHI aims to apply the results from long-term verification operation of the J-Series to further development of technologies that will enable even higher temperature gas turbines,” according to the company

Alberta Would Take Liability for Long-Term CO2 StorageLegislation introduced this month by the Alberta, Canada, government clarifies that the province would accept long-term liability for carbon dioxide stored underground from carbon capture and storage (CCS) schemes.

“This legislation ensures we are on track to reduce green-house gas emissions,” said Alberta Energy Minister Ron Liepert. “By using some of the captured CO2 for enhanced oil recovery, we expect it to double Alberta’s conventional oil recovery, generating tens of billions of dollars in provincial royalties and taxes.”

The Carbon Capture and Storage Statutes Amendment Act, 2010, Bill 24, clarifies ownership of “pore space” – that is, the tiny holes in porous rock where CO2 “greenhouse” gas would be stored.

“Under the proposed legislation, the Alberta government would accept long-term liability for injected carbon dioxide once the operator provides data showing that the stored CO2 is contained,” according to a Ministry press release. “It would also establish a fund financed by CCS operators for ongoing monitoring costs and any required remediation. The legisla-tion does not propose any changes to ownership of mine and minerals resources.”

The government of Alberta earlier committed Cdn$2 bil-lion (US$1.9 billion) to large-scale CCS projects in 2008, including Cdn$440 million (US$430 million) over the next three years.

REGULATION & LEGISLATION

Tenaska: Voters Support IGCC-SNG ProjectTenaska on November 15 unveiled results of a telephone survey of 800 Illinois voters regarding the company’s pro-posed “hybrid” 716 megaWatt integrated gasification com-bined cycle (IGCC) plant combined with synthetic natural gas (SNG) production.

According to Tenaska, “those polled strongly favor using Illinois coal to generate electricity and are willing to pay US$2 per month or more for cleaner power from Illinois coal.”

The proposed US$3.5 billion plant, which would capture most of its carbon dioxide emissions, faces an Illinois General Assembly vote on final approval later this month.

Up to 40% of coal-fired power capacity in Illinois is ex-pected to close during the next 10 years as the result of en-vironmental regulations, but the proposed IGCC plant could help preserve relatively low-cost coal power with ultra-low emissions to boot, according to Tenaska.

The poll, conducted by Anzalone Liszt Research, with the +/- 3.5% margin of error, revealed voter favorability toward clean-coal technologies in the state, according to Tenaska.

According to Tenaska, key findings include:1. “More than six-in-ten favor the use of Illinois coal to

produce electricity in the state. Sixty-one percent of vot-ers favor the use of Illinois coal to generate electricity in the state, including 25% who favor this strongly. Just 24% oppose using Illinois coal to generate electricity, and 15% say they are unsure.”

2. “Voters are nearly unanimous in their support for elec-tricity produced from coal if it can be made cleaner. Fully 86% of voters (56% strongly) say they would be more likely to support the use of Illinois coal to gener-ate electricity if the process could be made significantly cleaner than traditional methods (8% ‘less likely’). This includes strong majorities of Democrats (82% ‘more likely’), independents (82%), and Republicans (92%), and across all regions of the state.”

3. “Voters strongly support cleaner power plants in Illinois, and they are willing to make a personal investment to make it happen. By roughly a 3:1 margin, voters agree that it is more important that we build cleaner power

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plants in Illinois, even if it means a small increase in electricity rates (71% support this position). Less than one-quarter (24%) believe it is more important to keep electricity rates as low as possible, even if it means rely-ing on traditional, dirtier power plants in Illinois. Even solid majorities of Republicans (65%) and conservatives (61%) are willing to pay more for cleaner power.”

4. “A clear majority of voters are willing to pay an extra $2 or more per month to attain the goal of cleaner power from Illinois coal. Over six-in-ten (62%) say it is rea-sonable for consumers to pay an $2 or more on their monthly utility bill for cleaner power produced from Illinois coal. This includes 21% who say ‘more than $3 per month,’ 20% who say ‘up to $3,’ and 21% ‘up to $2.’ Another 26% say ‘up to $1.’ Only 5% say consum-ers should ‘pay nothing’ for cleaner power from Illinois coal (6% say ‘don’t know’).

5. “Creating jobs and reducing our dependence on foreign energy sources are voters’ top priorities when it comes to the state’s energy policy. When asked about what state leaders should prioritize when it comes to Illinois’ energy policy, a plurality (36%) says ‘creating Illinois jobs,’ fol-lowed closely by ‘reducing our dependence on foreign energy sources’ (32%). Fourteen percent say ‘reducing our use of fossil fuels like oil, natural gas, and coal.’

Nine percent say the top priority is ‘preventing increases in utility rates or energy costs,’ and 7% say ‘protecting the local environment.’

6. “By a 33-point margin, voters support building the Taylorville [IGCC] Energy Center [TEC]. Roughly half of voters (49%) favor building a new coal-fed power

plant in Illinois (24% strongly favor). This is compared to just 16% who oppose building the facility, and 35% who do not have an opinion.”

7. “Voters see TEC as a net-plus for the state of Illinois. Voters are even more moved to support TEC after learn-ing that the facility will create jobs, invest hundreds of millions every year into the Illinois economy, and help the state meet its growing energy needs without sacrificing the environment. Voters, particularly those who initially hold mixed feelings about TEC, respond positively after hearing that the facility uses clean coal technologies that will slash emissions. Moreover, the best-testing positive messages far outperform the stron-gest negative messages on TEC.”

8. “Support for TEC is bolstered by the plant’s broad co-alition of supporters. Clear majorities say they would be more likely to support TEC if the plant had the sup-port of public health groups, such as the American Lung Association (73% ‘more likely’ to support), environmen-tal groups, such as the Clean Air Task Force (65%), and consumer advocates, such as the Citizens Utility Board (61%). Close to half (48%) are more likely to support TEC after hearing that state leaders, such as [Illinois At-torney General] Lisa Madigan, support the plan.”

“It’s encouraging to see such broad public support for developing the Taylorville Energy Center,” said Bart Ford, Tenaska vice-president. “Once the General Assembly passes legislation allowing this project to move ahead, we look for-ward to investing billions in the Illinois economy, creating thousands of jobs and protecting residential ratepayers who will see no more than a 2% rate impact beginning in 2015.”

U.S. EPA Finalizes CCS Rules; ‘Greens’ Praise MoveU.S. Environmental Protection Agency (EPA) November 22 finalized two rules on carbon dioxide (CO2) capture and storage (CCS).

“The new rules aim to protect drinking water and to track the amount of carbon dioxide that is sequestered from facili-ties that carry out geologic sequestration,” according to EPA.

“Together, these actions are consistent with the recom-mendations made by President [Barack] Obama’s interagency task force.” That task force concluded that certain new rules need to be in place to promote development of CCS, accord-ing to EPA.

The two new EPA rules:1. Drinking Water Protection: This sets requirements for

geologic sequestration of carbon dioxide in wells, in-

cluding the development of a new class of injection well called “Class VI,” established under EPA’s Under-ground Injection Control (UIC) Program.

“The rule requirements are designed to ensure that wells used for geologic sequestration of carbon dioxide are appro-priately sited, constructed, tested, monitored, and closed,” ac-cording to EPA.

See more information on the EPA “Class VI” Sequestra-tion rule.

2. Greenhouse gas reporting for geologic CCS: “Informa-tion gathered under the greenhouse gas reporting pro-gram will enable EPA to track the amount of carbon dioxide sequestered by these facilities. The program was established in 2009 under authority of the Clean Air Act

CARBON CAPTURE & STORAGE

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and requires reporting of greenhouse gases from vari-ous source categories in the United States,” according to EPA.

See more information on the greenhouse gas reporting rule.

‘Greens’ Praise EPA MoveMeanwhile, several major U.S. “green” groups quickly praised the new EPA scheme, including Natural Resources Defense Council and Clean Air Task Force.

“We see it as a landmark development,” NRDC climate center scientist George Peridas told Gasification News in an interview.

While technical, economic and regulatory hurdles can com-plicate CCS projects, the EPA rules “for the most part address” the regulatory hurdles, even though “pore space” ownership of the stored CO2 isn’t included in the new EPA rules.

Some CCS project proponents have argued in favor of a single U.S. nationwide rule defining “who owns” the under-ground pore spaces where CO2 would be stored. But others apparently feel they can work-out the issue with various state governments and land-owners, just as pipeline companies have done with “eminent domain” for new pipeline projects, he said. So, the lack of an EPA rule covering “pore space” ownership is “not necessarily a show-stopper” for CCS proj-ects, Peridas told us.

NRDC climate programs director David Hawkins added that CCS project operators “now know their exact permit re-quirements and what is expected of them as their projects move forward.

“We will review these extensive new [EPA] rules closely, as some issues may still remain unresolved, including whether

the rules are sufficient to demonstrate permanent sequestra-tion in enhanced oil recovery operations. But we are now one step closer to creating a system that will help assure that these projects are safe and effective.”

Separately, Clean Air Task Force senior counsel Ann Weeks commented that “EPA has taken two very important steps with its coordinated issuance of permitting and moni-toring rules for facilities that can permanently isolate carbon dioxide from the atmosphere.

“These new rules will facilitate the permanent geological storage of carbon dioxide that is captured from the nation’s coal-fired power plants and other large fossil-fueled industry sources, a critical step in our battle to curb global climate change.

“The two EPA rules released today create the necessary framework to ensure that carbon sequestration facilities will be developed with adequate safeguards to avoid damaging under-ground water resources, while at the same time providing per-manent isolation of carbon dioxide from atmospheric release.

“In addition, for three decades the oil industry in the U.S. has effectively sequestered carbon dioxide in the same basins from which it produces oil. That 30 years of experience tells us both that sequestration technology works, and that EOR [en-hanced oil recovery] projects can hold the carbon dioxide from the earliest carbon capture projects. They are a critical step toward compliance with EPA’s greenhouse gas regulations.

“We applaud EPA for recognizing the important role EOR can play in sequestration of carbon dioxide and look forward to working further with the Agency to ensure that EOR fields are developed and transitioned to sequestration safely and cost-effectively.” – Jack Peckham

CO2 Leaks into Drinking Water Possible but Avoidable: Duke StudyResearchers at Duke University unveiled a new study show-ing that carbon dioxide injected deep underground potentially could leak into drinking water aquifers near the earth’s sur-face, causing water contamination.

According to the study, summarized in a November 11 Science Daily report, the leak threat is “real” but avoidable.

Having analyzed core samples from four drinking water aquifers, Duke researcher Robert Jackson said that “we found the potential for [water] contamination is real, but there are ways to avoid or reduce the risk.

“Geologic criteria that we identified in the study can help identify locations around the country that should be moni-tored or avoided. By no means would all sites be susceptible to problems of water quality

“The fear of drinking water contamination from CO2 leaks is one of several sticking points about CCS and has contributed to

local opposition to it. We examined the idea that if CO2 leaked out slowly from deep formations, where might it negatively im-pact freshwater aquifers near the surface, and why.”

Jackson and fellow researcher Mark Little “collected core samples from four freshwater aquifers around the nation that overlie potential CCS sites and incubated the samples in their lab at Duke for a year, with CO2 bubbling through them,” ac-cording to the report.

After a year’s exposure to the CO2, analysis of the samples showed that “there are a number of potential sites where CO2 leaks drive contaminants up tenfold or more, in some cases to levels above the maximum contaminant loads set by the EPA for potable water,” Jackson said.

According to the report, “three key factors – solid-phase metal mobility, carbonate buffering capacity and electron exchanges in the overlying freshwater aquifer – were found

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to influence the risk of drinking water contamination from underground carbon leaks.”

The study also identified four markers that scientists can use to test for early warnings of potential carbon dioxide leaks.

“Along with changes in carbonate concentration and acid-ity of the water, concentrations of manganese, iron and cal-cium could all be used as geochemical markers of a leak, as their concentration increase within two weeks of exposure to CO2,” Jackson said.

Siemens Touts Amino-Acid CO2 Post-Capture SchemeSiemens on November 18 announced what the com-pany claims is a “breakthrough with CO2 reduction technology” with an amino-acid salt chemistry.

“Siemens Energy has successfully completed the first test phase with its CO2 capture process in a pilot facility at the Staudinger [Germany] power plant operated by E.On,” according to the company.

“Process efficiency, the long-term chemical sta-bility of the scrubbing agent and emissions were investigated in the pilot facility under real power plant conditions. After more than 3,000 operat-ing hours since commissioning of the facility in September 2009, it has been demonstrated that the post-combustion capture process developed by Siemens (PostCap) attains a CO2 capture efficiency of more than 90% with practically zero solvent emissions. The energy consumption is significantly lower than comparable conven-tional processes”

By contrast with conventional CO2 capture processes, such as those using amines, the Siemens PostCap process “does not require any complex downstream scrubbing of the flue gas after CO2 capture,” according to the company.

“In addition to CO2, the solvent also removes further contaminants contained in the flue gas. These contaminants

additionally absorbed by the solvent and any by-products pro-duced will in the future be removed from the liquid solution using an innovative separation process.”

Learnings from the pilot facility at Staudinger also would be applied to an “anticipated larger-scale deployment of the PostCap process, which is proposed to be performed at the Big Bend coal-fired plant operated by Tampa Electric under an award to Siemens Energy by the United States Department of Energy,” according to the company

CO2 Capture Plant/Source: Siemens

Plenty of Nordic CCS Capacity, but Power Cost Doubles: StudyFinland’s Technical Research Center (VTT) unveiled a study November 11 showing that plenty of storage capacity is avail-able for future carbon capture and storage (CCS) projects in the Nordic countries.

The study, summarized in an AlphaGalileo (U.K.) science news report, gives an overview of the technologies and ap-plications required for CCS in the Nordic countries.

The complete VTT study is available here: http://www.vtt.fi/news/2010/11112010_ccs-suomi.jsp.

The study “maps large emission sources in each Nordic country, lists potential storage sites and gives an overview of current CCS projects,” according to the report.

Power and heat plants account for the largest part of carbon emissions in those countries, followed by oil and gas activi-

ties (22%) and iron and steel production (12%), according to the summary report.

“The capacity for storing CO2 in underground geologi-cal formations in the Nordic countries seems sufficient for a large-scale deployment of CCS. The storage capacity of aquifers offshore in Norway was estimated at 85 gigatons of CO2, while the storage capacity in Denmark was estimated at 2 gigatons CO2,” according to the report.

“Applying CCS technology to power plants would reduce the CO2 emissions from combustion by 80–90%; however, it would also almost double the production cost of electricity due to the energy requirements of the capture process.”

Three of the four ongoing large-scale CCS projects in the world capture CO2 from natural gas processing, the report

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noted. “Of these, two are situated offshore in Norway: the Sleipner and Snøhvit projects,” according to the report.

“CO2 emissions from biomass combustion were also found to be considerable. The mapped facilities emit-ted 54 megatons of biogenic CO2 in 2007, which mostly (76%) originated from large pulp and paper mills in Finland and Sweden.

“Capturing and storing CO2 from biomass combustion would function as a CO2 sink, i.e. reduce the amount of CO2 in the atmosphere. However, the current EU Emission Trad-ing Scheme (ETS) for CO2 emissions does not include CO2 originating from biomass. Therefore, there are currently no economic incentives to apply CCS to facilities emitting bio-genic CO2.” –Jack Peckham