Power plants are increasingly operating in a more competitive climate and in a world short of mineral resources, coal continues to be the raw materials of choice and correspondingly by-products from coal combustion are increasing. Stricter regulations and a heavier legislative burden coupled with increasing environmental awareness have made the operation of power plants more complicated and expensive. Resultant higher transport and disposal costs associated with waste and combustion by-products mean that the power industry must look for solutions to minimise the environmental impact. Reutilisation of bottom ash from coal combustion is already showing positive results with its use in structural embankments and drainage systems. When mixed with fly ash it may also be used in the cement industry. A new dry bottom ash handling system continues to burn the bottom ash during the extraction and cooling phase – passing ambient air, instead of water, over the ash. Known as DRYCON™, the system not only minimises emissions and non-recyclable waste products but also delivers increased boiler efficiency, due to the improved burning of the ash.

Dry vs wet
Traditionally bottom ash has been handled in a wet condition via established technologies such as impounded hoppers or submerged scraper conveyors. The use of water as opposed to air as a cooling agent can incur additional costs. Factors such as water treatment, corrosion damages, higher disposal costs and environmental problems as well as the higher costs to maintain must all be considered.

Using a dry system means that no water is required in the process therefore no water treatment is necessary. Reduced emissions and returning heat energy to the boiler resulting in lower coal usage and so with lower costs for emission trading are also highly beneficial to plant operators. The table below shows the main factors which compare between the two methods of conveying:

Cost scenario – DRYCON™ vs SSC

The following is an economic study of the relative costs of a DRYCON™ bottom ash system against the more traditional Submerged Scraper Conveyor (SSC) technology. The study is based on a typical European base load pulverised coal fired power plant of 800MW operating with imported coal. The economic factors assumed for the study assume depreciation over 10 years and the interest on loan capital of 12 per cent.

Looking at the investment costs, it can been seen that although the DRYCON™ is slightly more expensive than the SSC on a unit basis and the cost of associated crushing equipment is similar, these are offset by simpler transport and storage equipment and the lack of requirement of water treatment equipment such as pumps, filters, heat exchangers etc.

Considering the consumptions on an annual basis, it can be seen that due to the DRYCON™ roller design, the friction losses are significantly reduced and therefore have a positive effect on energy consumption and resultant wear. In addition, the SSC requires the provision of cooling water. At the associated costs indicated, it can be seen that the annual operating costs of the DRYCON™ are approximately 47 per cent of those of the SSC. As discussed earlier, the DRYCON™ captures waste energy from the incomplete combustion of the bottom ash and introduces it into the boiler as pre –heated air at approximately 450 degrees C. This results in an overall increase in boiler efficiency of between 0.15 and 0.5 per cent.

The bottom ash resulting from the DRYCON™ is a sellable product as it has good properties for the construction industry because it is low in carbon and it is dry and easily handled. In comparison the wet bottom ash from the SSC is generally disposed of and has the potential to impact the environment through water consumption and contamination.

For the concluding calculations, an increase of boiler efficiency of 0.15 per cent is assumed and no provision has been made for income from the sale of dry DRYCON™ bottom ash or costs for the disposal of wet SSC ash.

For the relative rate on investment the following calculation has been used.

Relative ROI = ((Gain from in investment from DRYCON™ over SSC) – (Cost difference between DRYCON™ and SSC))/(Cost difference between DRYCON™ and SSC)

In Scenario 1, it is assumed that the increase in efficiency of 0.15 per cent is used to generate an additional 9461 MW per annum (0.15% x 800MW x 7884hrs).

((9,460,800 kWh x 0.10 €/kwh) – ((€1,100,000 + €47,279) – (€852,500 + €100,065))) / ((€1,100,000 + €47,279) – (€852,500 + €100,065))
= 3.86 per year or 3.11 months

In Scenario 2, it is assumed that the same amount of power is produced but the increase in efficiency of 0.15 per cent is used to save 3514t of coal (0.15% x 297.2tph x 7884hrs).

((3,514 tonnes x 100 €/tonne) – ((€ 1,100,000 + €47,279) – (€852,500 + €100,065))) /
((€ 1,100,000 + € 47,279) – (€ 852,500 + € 100,065))
= 0.80 per year or 14.91 months

TPP Pljevlja is the only thermal power plant in the Montenegro power system powered by coal from the nearby coalmine. The thermal plant was commissioned in 1982 and it generates roughly 30 per cent of total power produced in Montenegro. The existing measuring, regulation and control equipment is Russian and has been used for 26 years. Increasing difficulties with the maintenance of the unit’s control equipment have brought about the need to install a new control system. Since the control equipment is outdated, it is hard to find spare parts for it. The concepts are also obsolete and, in terms of functionality, there are fewer options to use the block’s capacity. Therefore, the reconstruction of this unit was declared a project of special importance to Montenegro and the completion of works within agreed terms the main priority.

The modernisation project included the disassembly and the assembly of the entire existing automation and electrical equipment and the construction of the medium-voltage and low-voltage switchgear for temporary power supply. The Siemens consortium delivered to TPP Pljevlja a Distributed Control System (DCS) in the form of the SPPA T3000 automation system and boiler protection, as well as generator excitation system with a transformer, 220V direct current distribution utility, synchronisers, electrical protection for 6kV switchgears, generators and substations and electricity meters. With regard to electric power works, the modernisation included the installation of medium- and low-voltage switchgears, the installation of generator circuit breaker and measuring and regulation equipment in the field, which entailed construction works of a larger scope. The delivery included all necessary installation material, construction material and material for equipping the control room and the accompanying operator and staff rooms, air conditioning system for the control room and all rooms with electrical equipment and automation system cabinets, as well as the fire alarm system, including the auxiliary rooms and the administration building.

The newly-installed Block 1 configuration for TPP Pljevlja.

The scope of works and services constituted the main project for the complete modernisation, even for a part of electrical equipment not included in the scope of deliveries of the Siemens consortium. This particularly applied to medium- and low-voltage switchgear equipment. The installation works applied to complete modernisation, which also meant the installation of medium- and low-voltage switchgears, generator circuit breaker, measuring and regulation equipment in the field etc. The scope of contract for the most part also entailed construction works. Standard equipment testing, commissioning and optimisation of the measuring and regulation equipment were carried out. Technical personnel had both basic and additional training for working with the installed SPPA T3000 automation system. Siemens consortium provided complete support for the power plant during the trial run period.

Siemens liaised with several subcontractors and plant personnel to bring the project to a successful conclusion in record time.

After contract signing, the Main Project, including the specifications on equipment delivery, was prepared. The equipment was ordered and the preparations for its production began mid-July. Siemens dd Zagreb took over project coordination, engineering and commissioning.

Finally, over 35 subcontractors from the entire region came together to work on the project.
The implementation terms, first of all the terms for the making of the main project, production and delivery of the main equipment and material were unusually short. Disassembly of all existing automation and electrical equipment, as well as ordering and delivery of installation equipment and the construction of the medium- and low-voltage switchgear for temporary power supply began on July 20 and the work was completed in four weeks. The basic automation system equipment, equipment for generator excitation with a transformer and direct current distribution switchgear equipment were delivered approximately 15 days before the deadline. The engineering works were carried out by a team of 15 experts, while 30 associates (engineers and technicians) from Croatia, Serbia, Montenegro and Bosnia and Herzegovina worked on the commissioning activities. Installation works were carried out by over 120 additional workers provided by several hired subcontractors.

The Siemens consortium officially completed all planned equipment installation and testing works within the scope provided by November 13, 2009. The first successful grid synchronisation of the unit was carried out on December 16, 2009. After successful synchronisation there was a three-month trial run. A total of 201 days passed from the date of contract signing to the beginning of the TPP Pljevlja unit 1 exploitation.

Why Coal?

The power industry is confronting challenges with seemingly conflicting goals – affordable rates, dependable service, and reduced impacts. Different energy conversion technologies have their applications, but no single option does it all. Wind, solar, and hydro options don’t use any fuel, so shouldn’t we just rely on these technologies? Wind power is best sited where the duration/velocity makes sense, away from migration pathways, and away from neighbours who would object to noise and fluttering shadows. It will likely require 100 per cent back-up or additional energy storage systems, and new longer transmission lines to load centres are often required. There are similar requirements for solar power, just substitute lumens for velocity. With hydro power, there are concerns for fish migration/spawning, land use, geological concerns for supporting the weight of a new lake, stability concerns for newly saturated perimeter hills that can result in landslides, and the impact of a drought on production. Its the delivered cost on your utility bill that counts; the capital cost of the plant itself is only a single component.

Large, central power plants provide the reliability and flexibility utilities require for baseload, cycling, and on-demand situations. They can be strategically located near load centres or along transmission corridors and provide the economy of scale needed to minimize the cost of production.

The single, largest, operating cost for a gas, oil, or coal -fired electrical power generating station is fuel. In the simplest terms, the power plant is converting the chemical energy stored in fuel to electrical energy. Plant design, process requirements, and efficiency goals make fuel quality an issue. A high performance engine needs a high quality fuel.
So as we see, when we purchase a fuel, we are purchasing energy value. Coal is the most difficult to extract and burn, but as a source of energy, it is also the most economical. That’s the reason it fueled the industrial revolution and has historically been the fuel of choice in many countries for power generation. It continues to be the fuel of choice for new power generation for counties with high growth, India and China for instance.

What’s Coal?

Coal is formed from organic plant matter. It is the stored product of the photosynthesis of solar energy that has transformed carbon dioxide and water molecules into compounds containing carbon, hydrogen, and oxygen. Coal is created over aeons with favourable geologic and climate conditions. The results for each individual deposit is time and process dependent, so coal properties vary from region to region, mine to mine, and even seam to seam. Parameters such as heating value, moisture content, sulphur content, ash composition, and ash quantity are important in maintaining boiler rating, reliability, and performance. The absorption of nutrients by plants and the geological sediments/conditions introduce non-combustible minerals to coal, which for combustion purposes are impurities. The combustion residue of this mineral matter is ash.

Combustion Technology Issues

As power plants face a growing need to reduce costs and environmental impacts, coal quality is increasingly an issue of interest, as a means to do more with less. Coal quality affects plant performance in efficiency, emissions, and availability. At high combustion temperatures, fractions of ash can become partially fused and sticky. Depending upon a particular coal’s ash fusion temperature, it can adhere to heating surfaces building up as slag on water-walls and bridging tubes to obstruct the flow of combustion gases. Tube/refractory erosion and corrosion are issues too.

Recognizing the importance of fuel quality, coal specifications have become more restrictive, monitoring more intensive, and penalties more expensive. This can lead to increasing fuel cost as the demand for the most desirable sources escalates.

For large, central power stations, pulverized coal-fired (PC) boilers have evolved as the technology of choice. PC boilers combust a suspension of finely ground coal that is blown into the furnace in a gaseous matrix to form a large, stable flame vortex. Fine coal particles react similarly to atomized particles of liquid fuels. The reaction time is measured in seconds. The amount of coal, its heating value, and the impurities determine the size and design of the furnace/boiler and placement of the heating surfaces. Coal ash/impurities can form deposits on heat transfer surfaces and the ash itself must be collected. Products of combustion including SO_X and NO_X compounds must be controlled. The amount of ash and its constituents are basic design parameters for the boiler and the back-end air quality control systems.

Circulating fluidized bed (CFB) boilers are a more recent design option. Their size has gradually increased since the technology was first commercially demonstrated at the Nucla Station, in an EPRI (Electrical Power Research Institute) sponsored program. In a CFB boiler, fuel is combusted at lower temperatures in an aerated/fluidized bed of material that typically includes crushed limestone. The lower combustion temperatures and calcium content of the limestone reduce the formation/discharge of SO_X and NO_X compounds, so emission controls start in the combustion zone. Air quality control systems can further reduce emissions. The relatively long residence time for fuel within the combustion zone makes this combustion technology useful for lower quality fuels – fuels that are difficult to ignite, take longer to fully combust, and contain large quantities of impurities that are problematic for suspension firing in a  PC boiler.

Other combustion technologies, like coal gasification and pressurized fluidized bed boilers are being developed/demonstrated. The co-firing of coal with biomass and other solid fuels is also practical. Each technology has its own, unique requirements. So while coal quality control is an issue of importance, its means and methodology cannot be separated from its utilization. Combustion technology and fuel quality are coalescent issues.

Resource Management

Coal quality control begins at the mine. The mining engineer is responsible for developing the mining plan, monitoring production, and managing operations. One objective of any mining plan is to maximize recovery of the deposit of suitable quality coal. This is an economic issue; it’s cost effective to retrieve as much of a given resource that is economically possible. Mine development has sunk costs that should be “spread” over as much coal as possible. There are economic “cut-off” parameters that impact the mine plan. For open cast mines, the issues include strip ratios, how much overburden or interburden must be removed to expose a given quantity contained in a coal seam. For underground mines, it can be the seam height, pitch, depth, roof stability, etc.

Carbon capture and storage (CCS) consists of three necessary components: capture (including compression), transport and storage. Each component is deemed essential for the demonstration and deployment of a CCS infrastructure. Whereas capture and compression can be integral parts of the power cycle in a generic manner, transport and storage are site-specific composed of an export system (piped or tanked), an injection well(s) and a form of geological storage (such as a saline aquifer, or depleted or non-depleted oil or gas reservoirs).

For various reasons a fully-integrated power plant with CCS is still awaited. A pressing issue is the timeline for CCS to become a viable enabler of low-carbon power generation. In response to the climate change issue a relevant question is how fast CCS can be deployed to comply with a 50-80 per cent reduction target for greenhouse-gas emissions by 2050. The European Commission has announced its readiness to support up to 12 large CCS demonstration units (>300MWe) by 2015, as part of a wider vision of developing the technology to commercial maturity by 2020. The reason for the fairly high number of units at the outset is the urgent need to provide enough experience on candidate concepts and the suitability of various storage sites and other representative boundary conditions. The G8 has targeted 20 CCS demonstration plants worldwide by 2020. More recently, the Obama administration (2009) ¹ suggested that it would be supportive of a similar number of large CCS demonstration projects by 2020. China reportedly is seen as an integral part of reaching this target. These ambitions are all top-down promises that call for international actions to mobilise the required knowledge and capacities required to fast-track CCS as a viable component of a transition towards a “low-carbon society”.

Timeline concerns

The political need for accelerating and materialising CCS to within just one decade represents an unprecedented challenge that calls for targeted research via integrated projects at international level to validate CCS by demonstration projects. Crucial factors include the mapping and pre-qualification of geological reservoirs suitable for storage, and deployment studies. Most pressing, however, is the full characterisation and preparation of new storage sites following seismic shooting. Experience tells that this may require some 4-5 years per site (at the best), including proper drilling. This time lag should be highlighted as a critical path of any CCS transition strategy.

When will CCS happen?

Figure 1: the emergence of CCS projects along the timeline by fuel, purpose and stage of development (pilot, demo, commercial)

Numerous CCS projects are in the planning phase and some have been (conditionally) announced as indicated in Figure 1. But still uncertainty (mainly) about cost and financing as well as the legal and regulatory framework is delaying the triggering decision of building large, fully-integrated CCS-based power plants for demonstration and commercial operation.

Coal-based power generation

Modern conventional coal-based power plants in the 1GW class require some 8-10kt of coal per day. They emit CO₂ in the range of 6-7Mtpa. Should CCS be employed, a logistic system would be required to transport the captured CO₂ safely to a permanent storage.

Figure 2: emission index versus efficiency relating to bituminous coal (solid lines) with various
capture rates for CO₂ (CR). The chart includes trajectories of lignite and natural gas
(the latter without CO₂ capture). The capture unit is assumed to account for six per cent of
the efficiency penalty, whereas the penalty owing to compression is determined by fuel and capture rate.

Figure 2 illustrated the impact of efficiency on emission index (in g CO₂/kWh) using coal and natural gas as fuel. With coal the impact of capture rate (CR) is also shown. The European Parliament has proposed a level for clean energy at 500 g/kWh. As depicted, to be termed “clean energy” with natural gas CCS is not required provided net efficiency exceeds 42 per cent (LHV). Likewise, with bituminous coal and 42 per cent net efficiency a capture rate of 25 per cent would be required. Figure 2 clearly suggests that high (initial) efficiency is one important component of any strategy intended for reducing CO₂ emissions.

Figure 3: impact on plant efficiency owing to compression work vs CO₂ capture rate. Coal characteristics: upper left hand. Compressor characteristics: lower right hand. Base-plant efficiency: 45% (without capture).

The major efficiency penalty with CCS is caused by:
a) the CO₂ capture process – accounting for typically 5-8 percentage points depending on technology, coal and power cycle
b) the compression train – accounting for typically 3-4 percentage points, depending on coal properties, power cycle , capture rate and transport requirement (see Figure 3).

Pre-conditioning and CO₂ compression

Per se CO₂ compression represents an integral part of any CCS concept. Usually the CO₂ must be dehydrated and transformed into dense phase at super-critical pressure for pipeline transport – or it is liquefied at meso-pressure and low temperature for tank shipments (typically 5-10bar and close to -50°C). Various restrictions may be imposed on the purity of the CO₂ depending on transport system, and requirements for the sink – mainly for reasons that owe to the overall economics, health and safety issues, material selection versus corrosion, energy demand for compression and precautions to avoid hydrate formation ^{2 , 3, 4, 5, 6, 7, 8}.

CO₂ capture

The CO₂ contained in a flue gas stream can be trapped in various ways – most commonly via absorption or adsorption using a solvent or an agent with a strong bonding to the CO₂ (chemically or physically). Once the bonding has taken place the CO₂-rich agent must be diverted from the gas stream. To re-use the agent in a cyclic manner the CO₂ must be stripped off whereby the agent recovers its bonding capability before re-entering the flue gas stream. Stripping requires energy, either as a heat input (temperature swing) or electric power (pressure swing). Alternative ways go via cryogenic processes, especially in combination with oxygen-based combustion. A major research challenge is associated with the separation work, as the energy demand in practical separation processes is far more extensive than the theoretical minimum energy requirement. Therefore, energy penalty is a major issue that relates to any CCS technique. This also applies to compression, as the theoretical power input to compressors is only around half of the power needed.

Current research and development emphasises power cycle improvements at various levels including alternative ways of making use of fuels and oxidants (either via gasification or by oxygen-based combustion), and also studies on how to trap the tail-end CO₂ from the flue gas with the lowest practical and affordable efficiency drop – combined with emerging techniques. Efficiency improvements are mostly sought within the capture system and the degree of integration thereof with the power cycle. This narrows down the (theoretical) potential for efficiency-drop improvement to a range of 5-8 percentage points of efficiency.

Figure 4: trajectory of coal-power plant efficiency by recent year, and expected development owing to new materials for ultra-super-critical technologies and the expected set-back owing to CCS.

The potential for further development can be derived from the trajectory of the thermal power plant efficiency as depicted in Figure 4. The trend projects a quite promising leap of around four percentage points in just a few years owing to advanced material properties for steam cycles. The chart also includes a plot for the highest plant efficiency at 47 per cent (LHV, dry), which corresponds to the Danish Nord-Jyllandsværket. This high efficiency is achieved by combining advanced steam parameters, and a low end-point of the expansion line of the low-pressure turbine. The latter results from the cold sea-water used for condenser cooling. A similar system with air-tower cooling would have a net efficiency typically 1-2 percentage points lower.

The awaited leap in efficiency owes much to ongoing research in advanced materials in the USA and Europe, which targets advanced materials to enable ultra-super-critical power generation (USC-PC) for new steam cycles to reach 360 bar and 700/720°C (superheat and reheat respectively) ^{9, 10}. The commercialisation of these materials is expected to match with the timeline of emerging CCS concepts up to year 2020. This means that a net efficiency around 50 per cent could be regarded a realistic level for reference of conventional USC-PC.

Conversely, the impact of CO₂ capture on USC-PC-CCS is indicated by the broken line at the lower right-hand area of the figure. This implies that a net thermal plant efficiency (LHV-dry) is likely to be boosted from some 35-37 per cent (current state of the art) to some 40-43 per cent (or even more) by 2020.

Concepts for CO₂ capture

Three main avenues for CCS prevail – broadly characterised as to where or how the CO₂ is removed vis-à-vis the combustion process – notably pre-combustion, oxygen-based combustion and post-combustion. In Table 1 and Table 2 the main characteristics and the integration of prevalent CCS technologies are synthesised for reference. With post-combustion capture the fuel is converted with conventional air leaving a large amount of nitrogen in the flue gas and, hence, the CO₂ concentration is fairly low (typically 12-15 per cent). With pre-combustion capture, however, the solid fuel is converted to basically hydrogen and CO₂. As a result, the CO₂ occurs in higher concentration and at an elevated pressure (typically around 40 per cent CO₂ and 30 bar). At this condition the partial pressure of the CO₂ will become high, which is favourable to the CO₂ capture. In oxygen-based combustion concepts, however, the nitrogen is removed from the air before the fuel is burnt, which leaves a flue gas rich in CO₂ and water vapour. By condensing the water vapour the CO₂ becomes available at a high concentration (typically well above 90 per cent).

Table 2 – Prevalent technologies avenues for CCS (simplified)
	Pre-combustion capture scheme
	Typical oxy-combustion scheme
	Typical post-combustion scheme

Figure 5: polygeneration from coal broken down in unit operations. ¹¹

Co-producing electricity and synthetic fuels via gasification and pre-combustion capture responds to the issue of security of energy supply. Such polygeneration schemes may also improve the flexibility of IGCC-CCS plants, as they allow the gasifier to operate constantly at nominal load while the response to the varying demand is handled by the power cycle, thus, using the chemical yields as swing products.

Post-combustion capture

Post-combustion capture is applied to conventional power-plant technology in which the CO₂ (up to around 90 per cent) is removed from the flue gas. This requires mainly heat for the regeneration of the solvent and electric power for compressors, pumps and fans.

Figure 6: Typical absorption process for post-combustion capture systems using amine-based solvents. ^12,13

Post-combustion capture is based on a system using either absorption or adsorption technology. Although numerous chemical and physical solvents are considered candidate agents, a generic aqueous solution of mono ethanol amine (20-30% MEA) is used in many studies and pilots, however, with some proprietary additives that prevent corrosion and foaming. In systems based on absorption the solvent absorbs CO₂ at typically 40-60°C ¹². The solvent leaving at the bottom of the desorber is then heated to typically 120°C in a reboiler that leaves a hot CO₂/steam mixture to the lower section of the desorber unit (Figure 6). The CO₂ stream will then ascent counter-current of the trickling rich solvent to the top of the column. It will then divert to compression and dehydration throughout multiple stages before a sufficiently pure and dense CO₂ stream is due for transport to the storage site.

Maturity of CCS

The maturity of the prevalent CCS concepts and their development potential are identified in Table 3.

Water balance

In hot and dry countries like China, Australia and India the significance of process water demand is an important factor to validate when dealing with alternative CO₂-capture systems. Depending on the availability of cooling water and the dew point of the flue gas a water-balancing strategy has been suggested by Hetland et al. (2009) ¹² and by Kvamsdal et al (2010) ¹³. The reasoning is simply that the required net process water becomes zero if the amount of water supplied by the flue gas equals the amount of water contained by the cleaned gas and the CO₂ stream. This leaves an option to produce water – depending on fuel, power cycle and cooling capabilities. Table 4 reveals dew points estimated for various coal properties with oxygen-based and air-based combustion processes.

The table suggests that oxy-coal operation facilitates the recovery of process water from the flue gas, by cooling to below dew point. With air-cooling this is practically feasible with lignite and to some lesser extent with bituminous coal. With anthracite, however, this option seems to be rather unlikely.

Conclusion

Research along the whole CCS chain is ongoing in numerous countries, but so far no technology has been coined the winner. However, in the near-term perspective a majority of projects use post-combustion capture in pilots and in emerging demonstration projects. Owing to the unavailability of gas turbines in suitable power classes, no pilot is announced for pre-combustion capture schemes (IGCC-CCS). Seemingly, Europe and North America have a slight preference for post-combustion, although oxygen-based combustion is gaining momentum in these regions. Other continents, however, are prone to be in favour of pre-combustion and oxy-combustion.

For more information, please contact:
Jens Hetland, PhD/Senior Research Scientist – SINTEF Energy Research, Norway.
Email: Jens.Hetland@SINTEF.no

References

¹ FRIEDMAN, L. (2009) “A Sea Change in China’s Attitude Toward Carbon Capture” in:The New York Times. 22 June. [Accessed http://www.nytimes.com/cwire/2009/06/22/22climatewire-a-sea-change-in-chinas-attitude-
toward-carbo-94519.html]
² SEIERSTEN , M (2001) “Material selection for separation, transportation and disposal of CO2″ (paper 01042) in: Proceedings of Corrosion 2001, National Association of Corrosion Engineers.
³ MOHITPOUR , M, GOLSHAN, H and MURRAY, A (2003) Pipeline Design & Construction, A practical approach , The American Society of Mechanical Engineers, New York, United States.
⁴ AUSTEGARD, A, SOLBRAA, E, DE KOEIJER, G and MØLNVIK, MJ (2006) “Thermodynamic Models for Calculating Mutual Solubilities in H2O-CO2-CH4 mixtures” in: Chemical Engineering Research and Design (ChERD), Part A, 2005. Special issue: Carbon Capture and Storage, V84, A9, September, pp781-794.
⁵ DE VISSER, E, HENDRIKS, C, BARRIO, M, MØLNVIK, MJ, DE KOEIJER, G, LILJEMARK, S and LE GALLO, Y (2008) “DYNAMIS CO2 quality recommendations” in: International Journal of Greenhouse gas Control 2, pp478-484.
⁶ HETLAND, J, RØKKE, NA, RØKKE, P, LE GALLO, Y, EVANS, DJ and EICKHOFF, C (2008) “Towards large-scale co-production of electricity and hydrogen via decarbonisation of fossil fuels combine with CCS (geological storage) in: Proceedings GHGT-9, Washington DC, USA, 17-20 November.
⁷ CARROLL, JJ (sd) “Problem is the result of industry’s move to use higher pressures, Gas Liquids Engineering Ltd” in: Pipeline & Gas Journal, 230(6), 60-61, Calgary, Canada.
⁸ ODRU, P, BROUTIN, P, FRADEET, A, SAYSSET, S, RUER, J, GIROD, L (2006) “Technical and economic assessment of CO2 transportation, Institute France Petrole, Work supported by the French agency ADEME” in: Proceedings GHGT-8,Trondheim, Norway, June.
⁹ OTTER, N, (sd) “The importance of Advanced Material in achieving the goals of other ETPs” in: Zero Emission Fossil Fuel Power Plant Platform (ZEP), http://eumat.eu-vri.eu/downloads/Launchevent/…/11_ZEFFPP-EuMaTv2.pdf (last visited April 2010).
¹⁰ VANSTONE, RW (2005) “Advanced Material for AD700 Steam Turbines” in: AD700 – Advanced 700 PF Power Plant, A Clean Coal European Technology, Milan, Italy, 27 October.
¹¹ HETLAND, J, LI, Z, XU, S (2008) “How polygeneration schemes may develop under an advanced clean fossil fuel strategy under a joint Sino-European initiative” in: Springer Clean Technologies and Environmental Policy (128).
¹² HETLAND, J, KVAMSDAL, H, HAUGEN, G, MAJOR, F, KÅRSTAD, V and TJELLANDER, G (2009) “Integrating a full carbon capture scheme onto a 450 MWe NGCC electric power generation hub for offshore operations: Presenting the Sevan GTW concept” in: Applied Energy, Volume 86, Issue 11, November, pp2298-2307.
¹³ KVAMSDAL, H, HETLAND, J, HAUGEN, G, SVENDSEN, HF, MAJOR, F, KÅRSTAD, V and TJELLANDER, G (2010) “Maintaining a neutral water balance in a 450 MWE NGCC-CCS power system with post-combustion dioxide capture aimed at offshore operation” in:International Journal of Greenhouse Gas, doi:10.1016/j.ijggc.2010.01.002.

According to EURACOAL’s latest report, 2009 continued the trend of demand shifting from the Atlantic market to the Pacific, thanks in part to demand growth in China and India, coupled with supply growth from Australia and Indonesia. Peabody Energy is showing signs that it expects this trend to continue, with the recent opening of a new office in Singapore, with the goal of expanding its coal trading activities within the Asian region.

The seaborne steam coal trade witnessed a 9Mta increase in volume in 2009 to 641Mta. And as can be seen from tables 1 and 2, all of the largest swings occurred in the Pacific market, which expanded by some 21Mt, with extra volumes entering the market from Indonesia, Russia and Australia. The fact that Chinese coal supply recorded the greatest change (-20Mt) is easy to rationalise, given the sheer size of both demand and supply within the country’s domestic market, causing small percentage swings to result in comparatively large changes in traded volumes, to the extent that a one per cent change in total Chinese coal output changes the country’s import/export balance by around 30Mt. Meanwhile, the Atlantic market shrunk by 12Mt, primarily due to lower exports from Columbia, the USA and Venezuela.

Steam coal prices, like other energy commodities have seen considerable turbulence over the past two years, reaching an unsustainable US$219.00/t in August 2008, before falling to a low of US$68.00/t in March 2009. The high levels of volatility were boosted by those in the freight markets for bulk carriers. Having since recovered back to more acceptable levels (from the perspective of producers), there are considerable barriers to stronger coal prices in the European market, in the form of high coal inventories at ports and power plants, particularly in Spain and the UK. This was despite a 63.9Mt reduction in total coal supply in the region to 724.9Mt for 2009, highlighting the damage done to industrial and residential demand by the recession, which was exacerbated by the fact that occasionally coal shipped from the Pacific proved to be cheaper than that produced locally. The largest single change in European hard coal production was a 6.1Mta decline in Polish output, coincidentally the same as the total reduction in European hard coal production. Polish domestic consumption was hit in 2009 by the economic situation, while in the UK, a significant reduction in the relative price of natural gas caused thermal coal demand to drop. Spain’s push towards greater use of renewables also helped pushed thermal coal use down further. European lignite production fell by 16Mt in 2009 to 406.7Mt, with the most significant declines coming from Germany (5.4Mt) and Romania (5.2Mt).

After an introduction and welcome by Michael Manley, Assistant Secretary at the Ministry of Science, Technology & Innovation and Natural Resources, and Professor Nicholas Canny, the academy’s President. Scott Brocket of the European Commission gave the European context for CCS. In the last two years, the EU has made progress in CCS policy as it adopted a regulatory framework in the form of CCS Directive 2009/31/EC as well as providing for a stimulus in CCS demonstration projects.

Ken Macken of Ireland’s Environmental Protection Agency and J Owen Lewis of the Sustainable Energy Authority of Ireland added further context as they discussed climate change, mitigating action and CCS in a low-carbon future, focusing mainly on Ireland.

The Royal Irish Academy assembled a variety of expert speakers: Emile Elewaut (TNO The Netherlands), Richard Vernon (SLR Consulting), RIA President Nicholas Canny, John Barry (Shell), Peader McArdle (GSI).

The morning’s session was rounded off by Dr John Morris of the Geological Survey of Ireland who gave an overview of carbon storage options.

In the second session of the day, keynote speaker Dr Jens Hetland of SINTEF Energy Research, Norway, discussed the three main routes for CO₂ capture and the status of technologies as well as mapping out various CCS projects around the world by technology, size and timeline. He also touched upon the typical cost of CCS related to early commercial projects in Europe.

Pat Naughton of ESB Power Generation explained the role of CCS in power generation. ESB’s vision is for the organisation to have a net carbon neutral generation fleet in Ireland by 2035. Mr Naughton pointed out the need for stable regulation and licensing, appropriate support mechanisms and public acceptability and stressed the importance of collaboration between industry, academia, policy makers and other stakeholders.

After the coffee break, Dr Robert Finley (University of Illinois), Professor Stuart Haszeldine (University of Edinburgh) and Emile Elewaut (TNO, The Netherlands) gave examples of strategies and technology relating to carbon storage, each from their perspective. Robert Finley took the listeners through permitting and developing the 1Mt geological sequestration test in a deep saline reservoir at Decatur, Illinois, USA, while Stuart Haszeldine gave a UK overview on storage. Currently, work is underway to evaluate selected aquifer stores in detail and researching a more specific capacity evaluation of all UK offshore sites. Emile Elewaut closed the day’s sessions with an interesting presentation regarding North Sea strategies and explained how the Dutch are considering the storage potential of their depleted gas fields. However, for this to be a viable solution, the country’s regulatory framework would need to be adjusted as well as solving problems relating to the timing between closure of some gas fields, connecting trunk lines and CO₂ storage potential.

In a session sponsored by the Irish Times, Jeff Chapman of the CCS Association, Stephan Singer (WWF) and Dick Ahlstrom, the Irish Times' science editor debate the issue of carbon capture and storage in Ireland.

In the evening, RIA teamed up with the Irish Times to play host to Jeff Chapman of the CCS Association and Stephan Singer of WWF for a thought-provoking debate on the impact of CCS on climate change.

The following day, Richard Vernon of SLR Consulting kicked off the CCS as a business session, outlining the Irish regulatory and business environment for CCS. His presentation was followed by Frank Convery, University College Dublin, who gave a European viewpoint to the carbon market. Shell’s John Barry represented the energy company’s perspective. Donnchadh Irish of ESB International, shared his experiences of his trip to China as he gave a Chinese perspective on carbon capture.

The Sleipner project came under close scrutiny as Andy Chadwick of the British Geological Survey kick-started the session on monitoring, regulation and research. The issue of monitoring is a crucial one in the success of CCS as reliable monitoring processes will help to get CCS accepted by the public as a viable option in reducing atmospheric carbon dioxide. Chris Bean of the University College Dublin appraised the audience of the latest advances in research on monitoring and verification. Peter Croker of the Department of Communications at Energy and Natural Resources brought attendees back to Ireland and the opportunities and constraints of offshore CCS while Michael Tutty of the Commission for Energy Regulation touched upon the issues of regulation and long-term stewardship.

In the afternoon, the organisers had lined up four more speakers which would shed light on the challenges facing Ireland in implementing CCS. John Ludden of the British Geological Survey brought the audience up to speed regarding CCS research opportunities. Richard Tol of the Economic and Social Research Institute detailed CCS economics in an Irish context. David Reiner (Judge Business School, University of Cambridge) gave an informative and highly entertaining talk on public awareness of CCS issues, stressing the importance of public acceptance of the technology in its successful implementation.

The final session of the conference was given to Bob Hanna of the Department of Communications, Energy and Natural Resources, who suitably rounded off two days’ presentations by clarifying the Irish position on CCS and looking into the future.

Successful implementation of CCS will have to overcome a number of barriers. There are not only technological challenges, but also economic and political ones. As for now, raising awareness on the issue of CCS appears a key element in its progress and RIA’s conference has been a step in the right direction.

Germany is a major user of lignite. The west of the country chose to expand the use of the fuel, when legislation was enacted back in 2002, to phase out the German nuclear reactor fleet and lignite-fired power plants accounted for a startling 60 per cent of East Germany’s generating mix, prior to reunification. As a result, lignite currently meets around 12 per cent of Germany’s primary energy requirements, but uses over 20 per cent of its CO₂ budget, under the EU ETS. Thanks to the country’s large resources of the fuel, lignite is Germany’s cheapest fuel at around €1.1/GJ (US$1.70/mBtu), equivalent to around a third of the cost of imported coal. The country has also demonstrated that lignite-fired plants need not be inefficient. For example, the Lippendorf power station, located 15km south of Leipzig, boasts a 42.4 per cent design efficient t hanks to new high-temperature technology and has been operating since 2000.

Greece’s state owned power utility, PPC, also extensively relies on lignite reserves in the Northwest region of Kozani. However, it’s position has come under attack from the European Commission which has required that Greece give the right to develop four new lignite mines to new power entrants. According to the commission, competitors “would probably need to have access to a minimum of 40 per cent of exploitable lignite resources in order to create a level playing field in the electricity market (EU Energy).” The Greek government invited investors to bid to operate a coal mine in the Northwest of the country on February 8. PPC currently controls 97 per cent of the Greek electricity market and is Europe’s second largest lignite producer. According to Authuros Zervos, CEO of PPC, his company is moving forward with plans to build two new lignite-fired power plants in the cities of Ptolemaida and Florina by 2016. There is a certain amount of irony in this decision, given that EU funds are available for a CCS project via the NER300 scheme, which currently holds funds in the order of €4.5bn.

In the Ukraine, lignite is also plentiful, but high in sulphur and ash, making gasification the only real means of commercialising it. However, with the government struggling to remain solvent this remains something of a dream, but the economic case is extremely compelling in the context of the country’s dependence on Russian natural gas.

Poland’s reliance on lignite-fired power plants, is a contenious issue from the perspective of European efforts to reduce the trading bloc’s CO₂ emissions

Poland, despite the wishes of its fellow EU member states, given its reliance on coal-fired generation, is also likely to see several new lignite for power projects. Enea, the Polish power utility and KWB Konin, a lignite miner were both tipped by the country’s deputy economy minister, Joanna Strzelec-Lobodzinska, as potential investors to develop lignite deposits near Gubin in the west of the country in November 2009. In 2008, the two companies set up a joint venture to build three 800MW block by 2021, that would consume around 17Mta of lignite a year. However, their plans have met with fierce local opposition. The country currently relies on lignite-fired power plants for 34.5 per cent of its electricity.

Romania’s National Lignite Company is carrying out two projects to upgrade its facilities. The first of which has the aim of modernising its mines at Rosiuta, Pesteana and Rosia, at a projected cost of €35m. It is also looking to invest €2m in upgrading the power grid and electricial installations at its opencast mines.

Interestingly, Kosovo’s lignite resources are expected to play a key role in the region’s reconstruction and renewal. As of end 2006, its certified lignite reserves were in the order of 14.3bnt, the third highest in Europe, after Germany and Poland. Commercialisation of the reserves is badly needed, given that the Balkan state is suffering from persistent power shortages and is currently reporting an unemployment rate of around 40 per cent. Fortunately, an end could be in sight, with the recent announcement that the government has shortlisted four bidders to build a new plant with an initial 500MW of capacity, with the option of building a further 500MW at a later date. Once completed, the plant will rely on the nearby Sibovc lignite mine for fuel, which is considered to have the best lignite deposit in the state. The four qualified bidders for the project are: Indian-led Adani power group; US-based AES with Turkey’s Demir Export; Turkey’s Park Holding; and a consortium of US-UK Contour Global with Greece’s public power company. The tender for the project is to be published by the end of April and the winner by July, according to Justina Shiroka-Pula, minister of mining and energy. Construction is expected to begin in 2011, with commissioning in 2016. Once complete, it will replace two obsolete plants at the same site. The total cost of the project is currently estimated at between EUR700m and EUR1bn.

India’s pressing need to boost its electricity supply, coupled with the fact that its coal industry is struggling to keep up with the relentless pace of demand from new hard coal-fired projects is putting lignite usage in the country on an upward trajectory. The Neyveli Lignite Corporation (NLC) was reported as planning to build four lignite-fired plants with a combined capacity of 500MW at Bikaner in Rajastha, as part of its ambitious goal to increase its total generating capacity to 10,000MW by 2017, from its current 3000MW. At the same time, the corporation is becoming increasingly aware of the need to eventually diversify away from lignite. NLC’s Chairman and Managing Director, A.R. Ansari, told the audience at an Engineers’ Day function in September 2009, that lignite reserves in Neyveli will not last more than three decades. Last year, the company recorded its highest ever lignite production and power generation.

In December 2008, Tata Power’s new 1.54km coal handling system unloaded and conveyed the first coal from barges to the power plant stockyard in Mumbai, India. This event marked the coming into operation of India’s most sophisticated, efficient and environment-friendly system, which includes a continuous ship unloader (CSU) and pipe conveyors supplied by FLSmidth. The project demonstrates Tata’s commitment to high-level technology and social responsibility.

Tata Power has a total installed generating capacity of over 2300MW in the form of thermal, solar, hydro and wind energy plants. In Mumbai, the company operates a 1330MW thermal power station at Trombay. Tata Power was planning to install two more units of 250MW each to cater for Mumbai City’s increasing demand. Besides, it wanted to ensure that all the units are compatible for the coal-based system. Due to governmental regulations it was necessary to install an environmentally-friendly system for unloading coal at the power plant’s jetty and conveying it to and from the stock yard. Tata Power had been working on these requirements for more than a decade before deciding to work with FLSmidth to install a cutting edge system that meets the stringent regulations and is still competitive.

FLSmidth – a preferred partner to Tata Power

In 2004, FLSmidth learned about Tata Power’s requirements for building its own jetty to unload imported coal from Indonesia for its existing power plant and for the new power plant being planned. The challenging part was to transport coal within the congested plant layout over a distance of 1540m, crossing existing power plant units, circumventing an existing flyover, passing below the high-voltage power lines, and crossing the 74m-wide Mumbai Port Trust channel, which houses chemical, gas and oil pipe lines.

In January 2006, FLSmidth was awarded an order on a semi-turnkey basis for a complete system, comprising a continuous ship unloader and two pipe conveyors (including the conveyor at the wharf), structural engineering, electrical supplies and instrumentation.

FLSmidth continuous ship unloader – a design leap

The CSU was preferred instead of a grab, because it is an environmentally-friendly machine for unloading coal at the dedicated jetty. The machine marked a design leap since the unloaders previously supplied by FLSmidth were for capacities 800tph and below. The machine was designed with a perspective to aggressively enter the port business, at the same time bringing in standardisation. Hence, it has a vertical screw of 820mm diameter, which is capable of handling up to 2000tph of coal. The horizontal arm is 21m long and the vertical arm is 16m high, while the total machine weighs 283t. It was developed, designed and sourced by FLSmidth, who also developed and tested the complete electrics including the PLC. The equipment was installed by the FLSmidth team working closely with Tata Power.

FLSmidth pipe conveyors – an engineering marvel

This installation is a classic example of a pipe conveyor application. There are two pipe conveyors of diameter 450mm: PCN-N2 (444m long) and PCN-N3 (1100m long). The pipe conveyors are designed for a speed of 4.5m/s and have a rated capacity of 1550tph. PCN-N2 receives the coal from the wharf conveyor and feeds PCN-N3 at an elevation of 40m in the junction tower. PCN-N3 has curve radii of 135m, the tightest in the world. Pipe conveyor PCN-N3 has 14 curves, one of which measures 94°. The double-pipe conveyor system is an alternative solution that replaces 14 conventional conveyors which would otherwise have been required for this application.

Before manufacturing the pipe conveyor belting, a finite element analysis was done followed by testing in the test rig at CKIT works in South Africa under simulated operating parameters and in the presence of the client, the FLSmidth team, Dr Gabriel from Delft University and belt manufacturer M/S Taeryuk, South Korea. PCN-N2 is also designed for return conveying of coal from the yard to the new power plant units. Gantries with provision for accommodating a standby pipe conveyor for bringing coal to the new plant are already in place.

The Tata Power project overcame several challenges which included space constraints, overhead high-voltage power lines and underground pipelines.

Challenges in the brownfield project

The project was full of challenges right from finalising a feasible route to carrying out the work due to space constraints, existing roads and facilities, overhead high-voltage power lines, underground cables and pipelines at the 50 year-old power plant. Several solutions were devised while executing the project, which was completed to the satisfaction of Tata Power and FLSmidth.

Maximising FLSmidth competency and experience

To date, FLSmidth has successfully installed more than 280 pipe conveyor systems worldwide, which are operating in various industrial applications, handling the easiest to the most challenging materials at 60-2000tph capacities and over lengths ranging from 60m to 8200m. FLSmidth worked closely with CKIT (South Africa) to execute the state-of-the-art system from concept to commissioning. This is the first time a system of this configuration has been installed for this application. The company’s experience from the 280 installations has helped in successfully designing and executing a dream project for TATA Power with its continued support.

One Source One Partner – a preferred approach

The system has been operational since December 2008 and a performance test was scheduled prior to the end of March 2009. In response to FLSmidth’s professional approach, Tata Power awarded another order on a single-party basis to replace a set of four conventional conveyors with two pipe conveyors. In addition, an operation and maintenance (O&M) contract for the ship unloader along with a contract for supervision of pipe conveyor maintenance has been awarded to FLSmidth.

For more information, consider visiting the following websites:
FLSmidth
Tata Power

Canada holds 6.6bnt of proven recoverable coal reserves, which are estimated to hold over 100 years of supply at current production rates, according to the government’s Natural Resources Canada department. Around 3.5bnt are bituminous coal while another 3.1bnt are classed as sub-bituminous and lignite. In addition, the country’s bedrock holds an extra 192bnt of identified coal resources, of which 92bnt is bituminous and 100bnt sub-bituminous and lignite types.

In 2007, its miners produced 70Mt of the black gold, up from the 66Mt extracted the previous year and indicative of the strong markets both inland and overseas.

Canada’s coal deposits are concentrated in the west of the country with vast swathes of lignite and bituminous coal dominating the national coal map (see Figure 1). Furthermore, the country also has considerable supplies of sub-bituminous coal in Alberta and appreciable quantities of anthracite in British Columbia. Much smaller deposits occur in Ontario, Newfoundland, and Nova Scotia and in the north of Nunavut. All-in-all, the sector counts over 20 mines, mostly open-pit operations.

It is estimated that in 2006, installed mine capacity was around 81Mt (excluding the New Brunswick and Nova Scotia mines) of sub-bituminous, bituminous steam and coking coal and lignite. Approximately 35.30Mt or 43 per cent of this capacity is found in Alberta mines, while 40 per cent is located in British Columbia and the remainder in Saskatchewan.

Canadian coal …

… employs over 5000 people directly and creates over 50,000 indirect jobs nationwide.
… contributes CA$5bn to the national economy annually.
… is the number one commodity in volume hauled by rail – 31Mt of coal were transported by rail in 2006, mainly to Vancouver for export shipment.

In good company

Canada counts nine coal companies:
• Compliance Energy Corporation
• Grande Cache Coal Corporation
• Hillsborough Resources
• NB Coal
• Northern Energy & Mining
• Sherritt International Corporation
• Teck Coal, part of Teck Cominco
• TransAlta Corporation
• Western Canadian Coal Corporation

Thermal coal imports

Canada’s coal-fired electricity generation demands significantly more coal than the country’s mining operations can provide. Hence, it imports coal into central and eastern Canada from the close by US east and central coal producing regions. Around 80 per cent of imports are shipped into Ontario. In 2007, 19Mt of coal imports went some way to meeting the national deficit.

Cleaning up coal

Canada has been researching and developing so-called ‘clean coal technologies’ such as emission reduction, coal beneficiation and cleaning, CO₂ capture/storage, and coal gasification in both publicly- and privately-funded projects, aiming to combat coal’s poor environmental track record.

One example is Sherritt Coal Corporation’s Carbon Development Partnership (CDP), a 50-50 joint venture with the Ontario Teachers’ Pension Plan. CDP assesses opportunities to develop its coal reserves by considering projects in conventional power generation, surface and in-situ coal gasification and coal bed methane extraction.

The initiative is presently concentrating on the Dodds-Roundhill project to develop the country’s first commercial application of coal gasification technology, a process that produces minor amounts of SO_x and NO_x and has CO₂ capture and storage potential. In addition, the project includes the development of a surface coal gasification unit to produce coal syngas, which can be used to manufacture hydrogen, clean diesel or synthetic natural gas. The project uses sub-bituminous or lignite coals and produces hydrogen for bitumen upgrading. Phase 1 would produce 270Mft³d of hydrogen and 12,500tpd of high-quality CO₂ that would be used for enhanced oil recovery (EOR).

Strong coal market

Nearly 60 per cent of national coal output is thermal coal and is mainly produced for the domestic consumption. National demand reached 58Mt in 2006, with the country’s 21 coal-fired generation plants consuming 51Mt. Coal accounts for some 14.5 per cent of electricity generation with off-take particularly strong in Alberta, Saskatchewan and Nova Scotia.

The remaining 40 per cent of output is coking coal. While Canada’s steel industry used around 4Mt and cement and other industries used an extra 3Mt of this type of coal in 2006, most of its coking coal is exported. In 2007, 31Mt of coal, of which 90 per cent was coking coal valued at CA$2.9bn, left Canada’s mines for 50 or so overseas destinations, making it one of the world’s leading coking coal suppliers. Japan buys around a third of the North American country’s exports, followed by South Korea (20 per cent) and the US (six per cent).

In 2008, the coal market continues to be strong. Examples of recent deals include the signing of a thermal coal supply contract between Hillsborough Resources and Vitol of Switzerland for 300,000t of Quinsam coal in 2009 at US$137 FOB and a further 300,000-350,000t at US$138 FOB the year after.

The brisk market provides for firm prices. Sources at Western Canadian Coal Corp (WCCC) have been settling selling prices at CA$300/t for hard coking coal from its Wolverine mine and at CA$248/t for low-volatile pulverised coal injection (PCI) coal from its Brule operation (prices locked in through March 31, 2009). John Hogg, WCCC’s president and CEO, commented: “With the strength of the coal markets, along with the 15 per cent weakening of the Canadian dollar, the company is generating strong cash flows and will continue to build on its strong financial position.”

Plenty of activity

A look at the country’s key coal miners quickly reveals that they view the future of coal in an optimistic light with plenty of acquisition and expansion activity going on. Teck Cominco announced it acquired all of the assets of Fording Canadian Coal Trust. Teck now wholly owns the country’s largest metallurgical coal producer, Elk Valley Coal, and the subsidiary will be renamed Teck Coal Ltd. The company is the world’s second-largest producer of seaborne hard coking coal after BHP Billiton Mitsubishi Alliance and operates around 27Mt of production capacity. Last year, its total output of bituminous coking coal was estimated at 22.6Mt from its six operating mines in British Columbia and Alberta. They are:
• Coal Mountain, Sparwood, with a production capacity of 2.7Mt, to be expanded to 4Mta.
• Elkview, near Sparwood (BC), with a production capacity of 5.5Mta. The largest of the Teck holding over 235Mt of clean coal reserves.
• Fording River, near Elkford (BC), with 8.9Mta capacity and reserves of 200Mt.
• Greenhills, near Elkford (BC), has a 5.1Mta capacity.
• Line Creek, Sparwood (BC) with 17Mt of clean coal reserves.
• Cardinal River, Hinton (Alberta), with a capacity of 2.2Mta.

Last year proved rather difficult for the company with coal revenues at CA$951m, down from CA$1177m and operating profit following the same trend from CA$444m to CA$209m. EBITDA fell from CA$526m to CA$295m from 10.6Mt of output. However, third quarter 2008 results are showing much more promise for this year. Revenues have leapt from CA$221m to CA$600m on the back of higher coal prices which jumped from US$93/t in 2007 to US$275/t one year later. This resulted in an excellent growth in operating profits, expanding nearly 10-fold from CA$36m to CA$350m. EBITDA are following suit at CA$419m, up from CA$52m.

Western Canadian Coal Corp (WCCC) produces over 3Mt of metallurgical coal from three mines located in northeast British Columbia: Brule, Willow Creek and Wolverine, as well as a 50 per cent interest in Belcourt-Saxon. The Brule Mine, successor to the Dillon Mine, has been producing around 1.3Mta of ultra-low volatile PCI coal for export, mainly to Korea, since January 2007. The company expects to raise production to 2Mta by 2009.

In June, WCCC obtained a mine permit allowing for the coal production at the open-pit Perry Creek mine, part of the Wolverine Group to the tune of 3Mta. This figure is expected to increase to 3.5Mta by 2012 when not only Perry Creek, but also EB and Hermann mines will enter production. In early May, WCCC bought out Falls Mountain Coal from its UK parent company, Cambrian Mining plc, effectively gaining Willow Creek coal mine, located 45km west of Chetwynd, British Columbia. An added ‘bonus’ for the company came in the existing wash plant and rail load-out facility, which can also be used by the Brule mine, significantly reducing the risk in its full-scale development as it cuts the original estimate by CA$70m.

WCCC is putting Willow Creek back into production after a care and maintenance programme had been in force since November 2006. In early 2009, low-volatile PCI coal production is to be launched with production earmarked at least partly for exports. At present, 900,000tpa of this type of coal are mined with the prospect of a hard coking coal output of 600,000tpa to be started up in the third quarter of 2009, pushing up metallurgical coal production to 1.62Mta.

Apart from these properties, WCCC is also part of a 50-50 joint venture with Peace River Coal. The cooperation holds the properties of Belcourt and Saxon, some 85km south of Tumbler Ridge, British Columbia. It is expected that the output of the mines will be around 5Mta, from 2013 onwards.

Despite the expansion of its coal mining activities, WCCC faced a tough year in fiscal 2007-08. The rapid rise of the Canadian dollar against the US dollar affected the revenues from its export sales considerably as the company was locked in fixed-price contracts. In addition, the opening of the greenfield Wolverine mine presented some technical challenges and the company also suffered from the widespread labour shortages present in the resource business sector. However, the company saw its run-of-mine coal reserves grow by around 16Mt.

In terms of financial results, by the end of fiscal 2007-08, company sales stood at CA$252m, up 88 per cent when compared to the previous year with volumes up by 116 per cent to 3.043Mt. The average realised price fell by 13 per cent to CA$82.97 as the Canadian dollar traded higher in the market. Yet, the company enjoyed better trading conditions in the six months ended September 30, 2008 (1H09). Total sales revenues advanced considerably when compared with the equivalent period the previous year: CA$297.8m against CA$122.07m. While tonnage sold fell from 1.5Mt to 1.2Mt, a higher realised price of CA$251.77/t (cf. CA$82.20 for 3Q08) made up for this drop to generate healthy revenues. As a result, the company’s net income went back into the black at CA$104.5m from the red (-CA$46.9m) experienced the prior year.

Hillsborough Resources owns and operates several mines in Canada. Its Quinsam mine is an underground thermal coal mine with a production rate of 0.52Mta of clean coal or 0.765Mta of raw tonnage. Its reserves are around 25.7Mt and are located near Campbell River, British Columbia. In March 2008, a three-stage drilling programme started to delineate further resources in the mine’s North area. Completed later in the year, the Quinsam North resource has been calculated at 21Mt with 13Mt immediately available, subject to a mining plan being approved.

In addition, it owns properties relating to the Gates and Gething formations in north east British Columbia, which contain primarily metallurgical coal with some PCI and thermal coal. David Slater, president and CEO of Hillsborough commented: “These properties truly represent Hillsborough’s horizon for growth. That is our future.”

In the south east of the province, Hillsborough acquired the Bingay Creek metallurgical coal property, some 20km north of the town of Elkford, in 2004. A total of 15.5Mt of measured and indicated resources have been identified plus an additional inferred resource base of 2.4Mt. The company is considering a larger mine development with an annual output of about 1Mt.

Further exploration initiatives see the development of the Wapiti project in British Columbia as a potential export thermal coal project in a possible venture with an undisclosed Asian power utility. The project was first started with the domestic market in mind, but the province’s government adopted a new approach to CO₂. This forced newly-built coal-fired power plants to sequester all of their CO₂, resulting in Hillsborough power partner AES Corporation withdrawing from the project as they considered there to be a lack of available technology. Wapiti’s resource estimate points at 80.1Mt of measured thermal coal and an additional 35.2Mt of indicated reserves. The current development project is based on its Heritage and Centre blocks and foresees a production of 0.9Mta over a 12-year mine life.

Full-year operating results for 2007 reveal that the company weathered 2007 better than 2006 with coal revenues up from CA$24,285,074 to CA$26,915,242. While net earnings figures remained in the negative, significant advances were made, reporting a decrease in loss to -CA$24,333 from -CA$5,384,822 in 2006. Nevertheless, the first nine months of 2008 saw the firm back in the red with net loss at CA$4,232,800 compared to a net gain of CA$2,310,202 in 2007. The termination of a domestic contract at the end of the year will enable the company to take advantage of a strong international coal market, selling its coal for export at better prices, according to corporate sources.

Meanwhile, until recently, Compliance Energy Corp held an interest in the Basin Coal Mine, located near Princeton, British Columbia. However, in August the company signed a memorandum of understanding (MoU) with NWPC of Australia, which has agreed to purchase Compliance’s 100 per cent stake in the 0.4Mta bituminous steam coal mine for CA$8m in a 50-50 cash-share arrangement. The deal will enable Compliance to focus on its activities Bear and Raven coal deposits on Vancouver Island.

Raven Metallurgical Coal is located nearly 80km north of Nanaimo, British Columbia, and holds a measured and indicated reserve of 39.1Mt and an inferred resource of 59.Mt of high-volatile A bituminous product. Last February, Compliance signed an MoU with Japan’s Itochu Corp and LG International Corp for the development of the mine, which has a target production of 1Mta, to start in 2010.

Bear Metallurgical Coal is just north of Raven and holds a resource of 8.6Mta, of which 5Mta is accessible by open-pit mining.

Compliance saw its business fortunes swing in 2007, noting a net income for the year of CA$1.36m improving its position significantly when considering the loss of CA$9.29m it suffered in 2006. Results from 1Q08 show a deterioration of net income to CA$0.47m from CA$1.24m although the company’s cash position appears to be improved.

Northern Energy and Mining (NEMI) owns and operates a 2Mt mine near Tumbler Ridge under the name of Trend Mine. Like other mines in British Columbia the property produces bituminous coking coal. Meanwhile, West Australian miner Aviva Corporation is teaming up with NEMI to create a CA$40m coal group. NEMI’s Peace River coal output is expected to serve as cash generator for Aviva’s project developments in Australia and Africa while debt-less Aviva will pour its cash reserves of CA$17m into NEMI’s coal mine expansions. Peace River started production early this year and is heading towards its permitted output rate of 2Mta.

Sherritt International Corp’s thermal coal operations are distributed between its Prairie Operations and its Mountain Operations. The eight Prairie mines are located in Alberta and Saskatchewan and delivered around 36.1Mt of coal in 2007. Its Mountain Operations consist of the Coal Valley mine, the Gregg River mine, Obed Mountain mine and Coleman properties with all but the first inactive. Coal Valley is situated around 100km south of Edson, Alberta. The majority of its output is earmarked for export with 3.4Mt shipped overseas last year. In 2004, the company announced a doubling of its capacity to 4Mta with a price tag of CA$125m, This was completed in 2006. Adjacent to existing operations, the firm is looking to expand its activities with three potential areas – Mercoal West, Yellowhead Tower and Robb Trend – under application.

In addition to its current mines, Sherritt is part of a 50-50 indirect partnership with the Ontario Teachers’ Pension Plan, named the Carbon Development Partnership (CDP). The programme is dedicated to the exploration and exploitation of 12bnt of undeveloped coal reserves and resources in western Canada. CDP is evaluating opportunities to develop its reserves by considering projects in surface coal gasification, in-situ coal gasification (eg Dodds-Roundhill), conventional power generation and coal bed methane extraction.

The company produced around 40Mt of thermal coal in 2007 and achieved record sales volumes at its Coal Valley deposit. In addition, it registered record realised prices as coal markets were buoyant. In the third quarter of 2008, revenues in its Prairie coal division stood at CA$150.6m, a CA$27.2m improvement YoY as higher royalties and increased cost and capital recoveries at the contract and Genesee mines impacted positively on income figures. At the Mountain operations, Sherritt enjoyed a “robust pricing environment for export thermal coal [that] continued to result in average realised prices that were significantly higher than in the prior periods.” The average realised price increased by 73 per cent YoY to CA$87.19/t, resulting in CA$39.3m record revenues. For the nine months ended September 30, 2008, total revenues for the coal division reached CA$529.9m, up from CA$446.3m when compared with the first three quarters of 2007 and EBITDA rose from CA$98.8m to CA$138.1m over the same period.

Relative newcomer Grande Cache Coal Corp, although formed in 2000, started its production in August 2004. Its coal leases cover over 22,000ha of the Smoky River Coalfield in west-central Alberta. Grande Cache has a production capacity of around 2Mta of bituminous coking coal. By the end of fiscal 2008, the company had produced around 1.42Mt of coal and sold 1.65Mt, increasing both indicators from 0.99Mt and 1Mt respectively YoY. Sales prices decreased slightly from CA$93/t to CA$89/t over the period, but revenues were not negatively affected, rising from CA$101.3m to CA$146.6m. The company continued to improve its situation, recording 1H09 revenues of CA$118m, up from CA$69m YoY, giving an income from operations of CA$41.3m against the previous year’s loss of CA$10.2m. Grande Cache’s sales declined marginally to 0.34Mt from 0.36Mt but soaring average sales prices, reaching CA$214/t (from CA$81/t) countered the potential loss in revenues.

TransAlta Corp – which possesses a diverse 8024MW energy portfolio, including five coal-fired thermal power plants in western Canada – owns two mines in the area, both of which are operated by Prairie Mines & Royalty.

Its Highvale mine is the largest surface strip coal mine in the country, covering 12,410ha. Located south of Lake Wabamun, it produces around 13Mta of low-sulphur thermal coal. This is delivered to the company’s Sundance and Keephills thermal generating plants. Upon the completion of Keephills 3 thermal plant, an additional 1.8Mta will be required.

On the other side of the lake lies its Whitewood mine, covering 3331ha and capable of producing 1.4Mt of sub-bituminous coal, which is supplied to the Wabamun thermal generating works. In May 2003, the Alberta Energy and Utilities Board approved an application allowing the mine to provide coal for the Wabamun power plant until 2010 when the works is slated to cease operation.

New Brunswick’s only mine, the Salmon Harbour mine in Minto, is owned by NB Coal, a wholly-owned subsidiary of NB Power Generation. Its 150,000t annual production is used to generate electricity at the Grand Lake thermal generating station. The company has been active in the region for the past 35 years, operating over 20 mines at various times. Former sites are now being reclaimed and the land restored to its original natural state of mixed forest, wetlands and ponds.

Further expansion and exploration

With export coking coal markets remaining strong and domestic thermal markets hungry for more product, Canada’s coal miners are confidently looking towards the future. This is reflected in numerous expansion and exploration projects that are about to start or are already underway.
For example, in April 2008, Goldsource Mines Inc announced it had intersected coal at a depth of around 80m in two core holes, located 1.64km apart and representing 26m and 32.5m respectively of coal seam. The drill holes are situated approximately 50km north of Hudson Bay, Saskatchewan. The coal is mainly ranked as high volatile bituminous C and sub-bituminous A belonging to the Mannville/Swan River Group of Cretaceous age. The company plans to carry out a major drilling programme on its permit area during the coming winter.

Greencastle Resources Ltd has been granted a coal exploration permit for an area on the Manitoba-Saskatchewan border, adjoining the eastern boundary of the coal exploration block of Goldsource Mines Inc. The Greencastle permit application covers around 1586ha in western Manitoba, some 25km southeast of the Goldsource discovery drill holes. Commenting on the recent coal initiative, Anthony Roodenburg, Greencastle CEO, stated: “We are pleased to have received final approval from Manitoba on our first application and will monitor exploration activity in the area closely, particularly the Goldsource winter exploration programme, while assessing our options for advancing the project.”

The Saskatchewan Ministry of Energy and Resources has issued a permit for the 18 Meter property owned by Westar Resources. The company can now begin exploration of the 138,240 acres near Tobin Lake and start mining this year, according to a company statement. Initially, Westar was testing for diamond-holding kimberlite, but found a significant thickness of coal at 47.7m, holding 7.6m of solid coal, followed by 11.2m of coal breccia.

In summary

Strong domestic and export markets, buoyant international coal prices, a solid supply from a good stock of proven recoverable reserves and continued exploration and expansion of identified resources – it appears that Canadian coal is set for a healthy growth in the future. Yet, the current global financial crisis warrants moving ahead with caution.

For more information:
Coal Association of Canada
Compliance Energy Corp
Grande Cache Coal Corp
Hillsborough Resources
Natural Resources Canada
NB Coal
Sherritt International Corp
Teck Cominco (Teck Coal)
TransAlta
Western Canadian Coal Corp

Despite the mounting interest surrounding the renewable sector, coal-fired power stations still account for a large percentage of the world’s electricity generating capacity. Each year, some 3bnt of coal is burnt, creating around 650Mt of coal fly ash in the process. In China alone, over 300Mt of fly ash was produced in 2006 and the country’s cumulative fly ash production is excess of 2.5bnt. In the US, 72Mt was produced in 2006, up 50 per cent from that seen in 1993. Like all waste products, its exact composition varies significantly, depending on the type of coal burnt and the specifics of the burning process. However, they tend to be rich in silicon, iron and aluminium oxides, as well as calcium oxide (CaO) and contain traces of heavy metals. The presence of CaO confers a pozzolanic quality, allowing some types of fly ash to be used as a substitute for Portland cement. As cement production requires a great deal of energy and generates substantial volumes of CO₂, the use of alternatives such as fly ash is attractive, both economically and environmentally. In addition, the rise of carbon trading may well give this approach an added boost in the future.

Such uses for fly ash have become important to power plant operators in recent years, due to economics and policy directives. In the case of the former, the cost of landfill space has been a key driver in promoting greater recycling of fly ash. In the US, fears that heavy metals can leak from fly ash piles and into the local water supply have also been a contributing factor. Indeed Constellation Energy and a landfill site owner were forced to pay a US$1m fine last year for contaminating groundwater in Maryland. The site held 4.5Mt of fly ash.

Increasing awareness of the opportunities offered by fly ash has resulted in companies such as Evonik Power Minerals, (European-based and featured in our March issue) or Separation Technologies LLC (a US-based subsidiary of Titan America), which manage the transportation and handling of the ash from power stations to its end user. Separation Technologies LLC has seen its annual sales of fly ash to the concrete industry grow by 20 per cent per annum and markets the ash under its ProAsh brand. According to company representatives, 15-30 per cent of the ProAsh can be used to make cement, while some of the collected ash with remaining calorific value is returned to the power plant to be reburnt.

Separation Technologies signed a deal in July with Colorado Springs Utilities to process the 120,000-130,000st of fly ash produced each year by the city’s two coal-fired power plants. As a result, Colorado Springs will save US$620,000 in landfill costs and could net the utility up to US$2m/year in ash sales. The city is also looking to sell bottom ash to brick and cinder block manufacturers, potentially leading to further savings of US$27,250 in avoided landfill and generate up to US$10,000 in annual revenue. The deal took Separation Technologies’ number of clients up to 10.

Another promising use for fly ash is in the manufacture of dry walls, the most commonly used indoor building material in the US. A company called Spertech announced on October 27 that it has found a way of producing wallboards using 98 per cent fly ash without the need for heating.

There are two classes of fly ash as defined by the American Society for Testing and Materials: Class F and Class C (see Table 1). Class F is produced from the burning of hard coal (anthracite and bituminous) and has less than 10 per cent lime, while Class C typically contains over 20 per cent lime and has a higher sulphur content. It comes from the burning of lignite or sub-bituminous coals. Both classes have pozzolanic properties, but Class C differs from Class F in this regard, in that it does not require a chemical activator such as sodium silicate to be self-cementing.

The growing market for fly ash appears to be creating a symbiotic relationship between other fuel-intensive industries and the cement sector. For example, Nalco, Asia’s largest alumina producer has recently invited expressions of interest from ‘competent’ parties to set up a cement plant based on fly ash, according to RC Pradhan, the company’s chairman. Last year, Vedanta Resources, a major mining and aluminium producer, invited bids from cement companies with a view to setting up a similar project, preferably in the form of a joint venture.

The problem of fly ash storage is also an obstacle to obtaining planning permission for new power plants. For example, Santee Cooper, a South Carolina utility, is looking to build a new coal-fired power station and environmentalists are seizing on the potential dangers of heavy metal leakage from the proposed landfill site. However, although the company has admitted that some mercury will leach into the Great Pee Dee River, it is hoping to use the site as a staging area with the majority of the ash to be sold to cement companies. However, there are some environmental concerns associated with the use of fly ash in cement manufacture. High mercury emissions from a Lafarge cement plant, situated in New York state, have prompted an investigation, which is expected to report its findings later this year. It is thought that the inclusion of fly ash in the cement kiln and the resulting exposure to extremely high temperatures (around 1750ºC), is transforming heavy metals within the ash into vapour. The situation is made more complicated by the fact that as utilities have come under pressure to clean up their emissions from coal-fired power stations, the concentration of mercury in fly ash has been increasing. A study conducted by the EPA in 2007 found that the mercury content in fly ash has risen by 850 per cent due in part to tighter federal standards for emissions from power plants. Another worry is that mercury may not be the whole story, given the presence of other heavy metals in fly ash.

Figure 1: Total US slag cement shipments.
Includes both slag cement shipped as a separate
product and as a component of blended cement.
Source: Slag Cement Association.

Slag: surprisingly sophisticated

Coal-fired power plants aren’t the only source of a waste product with great value to the construction sector. Steelmaking produces large quantities of blast furnace slag, which can be used to make slag cement (also known as ground granulated blast-furnace slag). Blending slag cement with Portland cement results in a product with advantages over standard cement. These include lower permeability, a lighter colour and improved resistance to sulphate attack and the alkali-silica reaction. The latter is also true of Class F fly ash but not Class C. The composition of slag cement is much closer to Portland cement, than coal fly ash and therefore can be used in much higher quantities (replacing up to 50 per cent in normal concrete, and up to 80 per cent in special applications, such as mass concrete).

In comparison, fly ash typically can only replace 20-30 per cent of Portland cement. Slag cement is typically more uniform than fly ash, varying less from source to source. As can be seen from Figure 1, sales of slag cement and blended cement containing slag cement in the US have grown significantly over the past decade. The recent reversal is due to the sub-prime crisis which has impacted on the American construction industry. The 3.4Mt of slag used in 2007, resulted in the avoidance of 2.9Mt of CO₂ emissions, conserved 14.5tnBTU of energy and 5Mt of virgin materials. In China, fly ash and slag cement are used in combination, with the routine mix used for concrete being 50 per cent pure Portland cement, 25 per cent fly ash and 25 per cent slag. This proportion results in the highest compressive strength (MPa) after 28 days (Lan & Yuansheng, 2007).

Uranium from fly ash

One of the more novel approaches seen to date is being pioneered by Sparton Resources. This company is looking to extract commercially viable quantities of uranium from the fly ash generated from coal-fired power plants. It already has agreements in place in eight countries including China and South Africa. In March, it secured a patent from the Chinese government for its uranium extraction process. In the same month, it reported that initial leaching tests on coal fly ash from the Lincang germanium area of Yunnan province, succeeded in recovering 70-80 per cent of the uranium content from the ash (281ppm U3O8). In addition to the high yield, the results were seen as encouraging given the low acid consumption and the low lime content of the ash (three per cent). The fly ash samples were taken from Tianhao, a local power producer which has given Sparton permission to eventually extract uranium from its ash stockpiles which have been estimated to amount to 450,000t.

In addition, Sparton Resources is looking to extract uranium from the Xiaolongtang, Dalontang and the Kaiyuan power stations, also in Yennan province. The plant at Xiaolongtang alone produces some 0.9Mta of fly ash and has stockpiles of around 5Mt. According to company estimates, a total of 145t of uranium could be extracted from the fly ash produced annually by these power stations. Sparton has been working closely with the China National Nuclear Corporation subsidiary (ARCN) and the two organisations have formed a joint venture to further develop this technique. However, this approach is possible only due to the comparatively high uranium content of some Chinese coals. The practice of reclaiming uranium from fly ash had been used previously in China with some success but was abandoned when the uranium market collapsed in the early 1980s. The technique promises to help reduce the environmental impact of fly ash, while at the same time providing China with additional domestic supplies of uranium. This will be especially welcome as the country is currently looking to expand its fleet of nuclear reactors. The EIA has predicted that it will add 15-30GW of new capacity by 2020.

The US Geological Survey does not consider the radioactive components of fly ash to be a health issue and that, as pointed out by BE Scheetz of Pennsylvania State University, the extraction of uranium from fly ash is not a viable means of producing fissile material for nuclear proliferation purposes. If this was the case, then fly ash uranium extraction would have occurred on a large scale during the Cold War.

There are number of other applications for fly ash, including soil stabilisation, mine backfill and agriculture. The IEA’s Clean Coal Centre published a report in May 2005 which investigated the potential for these different approaches. It reported that fly ash has been successfully used to boost crop yields in many countries, allowing the use of less fertiliser, gypsum and irrigation, due in part to its moisture retention and boosting properties. However, the report highlighted that such approaches are often limited to the local vicinity of the plant where the fly ash is produced due to transportation costs. This also limits its use as a soil stabiliser for construction work.

An impressive example of the scale at which fly ash can be used, is the mine backfilling project at Northwich, UK. A total of 1.1Mt of pulverised fly ash was used to combat the risk of subsidence from the town’s disused salt mines. The fly ash originated from Drax, the UK’s largest coal-fired power plant. A study concluded that all other alternatives for the mine infilling were less suitable due to a variety of reasons “including hazardous nature, handling difficulties, consistency, availability and cost” (P. Brennan, 2007). The project made it possible to develop over 20ha of land around the northern part of the city.

Of course, fly ash and slag are not the only by-products from coal-fired power generation with financial value. FGD gypsum is produced as a by-product of the desulphurisation of flue gases and can be used as a substitute for natural gypsum which is used in the production of varnishes, adhesives and plastics. It is also used as a setting controller in cement production. plasterboard manufacturing. In addition to its use in brickmaking, bottom ash can be used in greenroof construction and to enrich soil.

Waste not…

The waste from coal-fired power generation and steel making can be used to turn an unattractive expense into a lucrative revenue stream for plant owners, while at the same time, substantially reducing energy consumption and the need for raw materials in the construction industry. This translates into significant CO₂ emission reductions. Given the growing maturity of companies set up to offer utilities waste product marketing services, this approach should be seriously considered by all large-scale coal consumers, especially when viewed in the light of the growing move towards sustainability as a vital part of corporate responsibility and a “license to operate.”

For more information consider visiting the following websites:
www.stiash.com
www.slagcement.org