http://www.power-eng.com/news/2013/04/15/gasification-carbon-negative-sng-from-waste-biomass-and-coal-a-cost-effective-way-to-decarbonise-gas.html
04/15/2013
By A. R. Day, cost consultant; A. Williams, GL Noble Denton Ltd; Chris Hodrien, Timmins CCS Ltd.
Low cost carbon negative SNG (substitute natural gas) produced from co-gasified waste, biomass and coal, and decarbonised at source prior to injection into the gas transmission system, will assist in decarbonising downstream gas users – power, heat, transport and industry – at no cost to businesses and consumers, without alteration to their existing use of energy, provided that carbon negative SNG is cost competitive with fossil natural gas.
Particularly attractive is the integration of SNG production technology initially developed by British Gas Corporation and the UK government as part of a plan to supply the whole of UK gas demand by SNG (when North Sea gas ran out) with BGL multi-fuel co-gasification (as demonstrated by the SVZ company operating what was once Europe’s largest lignite to town gas production plant, at Schwarze Pumpe in former E. Germany), together with the Timmins CCS concept.*
The basic idea (Figure 1) is to use high efficiency slagging co-gasification to produce carbon negative synthetic natural gas with CCS. The low cost carbon negative SNG, with gas storage, and natural gas back up, is used in a conventional natural gas fired combined cycle plant with no loss of efficiency or operational flexibility.
The cost per unit energy of carbon negative SNG is estimated to be between 1/10th and 1/15th of the ‘whole system’ cost of wind power, and produces lower emissions than wind when emissions from fossil fuel back up are taken into account.
The carbon negative SNG scheme can also be extended to include integrated electrolysis, powered by low cost excess wind ‘lopping’, to produce ‘green’ hydrogen, oxygen and heat for low cost demand management and energy storage (see Figure 2).
For the main carbon negative SNG scheme discussed here, the following results have been obtained:
– Plant scale: 1.0 to 1.5 million tonnes per annum of nominally 50% mixed wastes, 30% biomass and 20% coal by mass.
– Gross efficiency, for carbon negative SNG: 78.5%.
– Net efficiency for carbon negative SNG, allowing for parasitic plant loads: 76.75%.
– Net fuel cost: £-0.4/GJ.
– Carbon content of fuel: 54.6% biogenic, 45.4% fossil carbon.
– Payback period: 20 years, 8% weighted aggregate cost of capital.
– Cost of 60 bar carbon negative SNG: 40 to 45 p/therm.
– Implied cost of carbon negative SNG fired power generation: £40 to 50/MWh.
– Cost of 150 bar high purity supercritical CO2: £0.4 per tonne CO2 excluding transport and storage.
– Cost of CO2 transport and storage: 33% of the unit cost of CO2 transport and storage per unit energy output compared with a fossil fuel power station.
– Net emissions intensity: -45 gCO2/kWh, assuming carbon negative SNG is used in a 60% efficient CCGT.
Decarbonising gas turbine based generation
Natural gas fired combined cycle plants are the thermal generation technology of choice in most of the Western world due to the combination of: flexible operation; high efficiency; low emissions; low capital cost; readily available fuel supply system; low land take; and low water consumption. However, fitting post-capture CCS to a natural gas fired CCGT significantly compromises many of those advantages.
Our approach is to decarbonise gas at source, prior to its injection into the gas grid, thus enabling existing CCGT operators to generate decarbonised electricity with no loss of: energy efficiency; plant load factor; operational flexibility; or rate of capital recovery. This highly attractive proposition depends on the cost of carbon negative SNG being competitive with the cost of fossil natural gas.
Methane is the simplest and most common hydrocarbon gas, and is the world’s most highly developed, internationally traded, fungible and storable gaseous energy resource and vector. But methane is not necessarily a fossil fuel. The fossil CO2 emissions intensity of methane used for energy purposes depends on what fuel the methane is made from, how it is made, and the end use. Fossil CO2 emissions from the use of methane can be negated by a combination of partly biogenic carbon fuels and CCS (Figure 3).
A typical mixed waste stream contains around 65% biogenic carbon. A typical 50% mixed residual waste, 30% biomass and 20% coal fuel mix contains 50 to 55% net biogenic carbon (as a proportion of total carbon). A typical methanation plant produces nearly 55% of total carbon throughput as CO2, which is available for sequestration, and 45% as methane. Emitted biogenic carbon, and sequestered fossil carbon are accounted as carbon neutral. Sequestered biogenic carbon is accounted as carbon negative, and offsets fossil carbon emissions at the SNG’s final point of use. The biomass is assumed to be sustainably resourced. Residual waste has already had at least one economic use, and any emissions associated with the original materials processing and use are assumed to have been accounted for in the original use. Residual wastes are those wastes left after waste reduction reuse and recycling, for which there is no further economic use.
Methane synthesis is an attractive route to delivering low cost CCS. SNG plants are inherently carbon capture ready as they produce CO2 as a waste byproduct. Compared with fossil fuel power stations, SNG plants produce relatively low volumes of high CO2 partial pressure mixed SNG and CO2, and can be converted economically to CCS. This has been demonstrated at the Great Plains synfuel plant in Dakota, since 1984 the world’s largest and longest-running SNG plant, which was retro-fitted in 2000 with CO2 capture and pipeline compression for EOR at Weyburn in Canada. The carbon negative SNG with Timmins CCS scheme discussed here uses the same British Gas developed catalysts as at Great Plains.
Reducing the cost of CCS
CCS installed on fossil fuel thermal power generation is currently uneconomic due to the high cost of CO2 capture and compression from power station flue gases. This is the largest single impediment to the large scale deployment of CCS on power generation. On the other hand, CCS on gas based processes is already economic, and in use at commercial scale.
The solubility of gaseous CO2 in a liquid solvent carrier is proportional to the concentration of CO2 in the original mixed gas stream, and the pressure of the gas stream. Concentration x pressure = partial pressure. CO2 partial pressure is thus the ‘key’ determinant of the capital and operational cost of CO2 separation and compression.
The IEA recently stated “The higher the CO2 partial pressure, the greater the ease of capture, and the lower the cost per tonne of CO2 captured and stored.” At the point of CO2 separation, and for the same plant energy input, the gas flow rate in an SNG plant with Timmins CCS is 400 times less, and the CO2 partial pressure is 250 times greater, than in a post-combustion fossil fuel power plant. This is a massive engineering, operational and financial advantage and explains why the cost of CO2 capture and compression from an SNG plant is two orders of magnitude lower than for post-combustion CCS on a fossil fuel power station. See Figure 4.
Reducing the cost of producing SNG from coal
80% of the unit cost of SNG is the cost of fuel and the cost of capital. Both may be reduced by improving net process efficiency. The 1955 to 1992 UK government/British Gas Corporation ’30 Year plan’ to produce SNG from coal to supply the whole of UK gas demand when North Sea gas ran out remains the world’s highest efficiency coal to SNG scheme, at 76% net efficiency unabated.
This compares with 61% net efficiency in the recently published US DOE/NETL Worley Parson coal or lignite to SNG scheme, with the option of fertiliser co-production. The British Gas scheme delivers 25% more SNG per tonne of coal than the DOE/NETL scheme.
The technology was successfully demonstrated at the British Gas SNG development plant at Westfield prior to its closure in 1992.
The high efficiency of the British Gas SNG scheme is achieved by integrating the BGL slagging gasifier, the world’s highest cold gas efficiency industrial scale solid fuel co-gasifier (Figure 5), and the HICOM combined catalytic shift and methanation process, with a range of standard industrial gas cleaning processes: Rectisol pre-wash, COS hydrolysis, Selefining, Claus/Scot and Selexol.
Both the BGL and HICOM rely on internal mass and energy exchange thus enabling the energy released by the oxidation of carbon to be used efficiently to transfer hydrogen bonds with oxygen in steam to hydrogen bonds with carbon in methane.
Some of the processes are endothermic, and some are exothermic. Highly developed waste heat recovery producing 540 deg C 155 bar steam drives on-site power supply, air separation and a range of plant processes. Increasing the gasification pressure increases methane production, decreases tar production, increases overall plant efficiency and reduces capital costs per unit output. A high pressure BGL was operated at 65 bar pressure at Westfield in the late 1980s.
Reduced operational costs with Timmins CCS
Integrating the use of partly waste based fuels and Timmins CCS (Figure 6) with HICOM and Selexol acid gas removal increases the efficiency of the base BGL, HICOM and Selexol processes. Plastic in the waste increases methane production in the gasifier, thus reducing the load on the methane synthesis process.
The recycling of part of the CO2 stream to HICOM reduces the amount of product gas recycled for cooling purposes. It also assists in suppressing the Boudouard reaction (2CO = C + CO2), thus reducing the need to inject excess steam to suppress Boudouard, and subsequently to remove the steam prior to gas separation.
Cryogenic separation of part of the CO2 stream prior to Selexol, and maintaining the gas flow at high pressure, reduces the capital and operational costs of the base Selexol plant. The improvements in efficiency in the base HICOM and Selexol plants offset the efficiency penalty for the Timmins CCS cryogenic plant.
A carbon capture ready SNG plant with the Timmins CCS process produces high purity ambient temperature liquid CO2 at 60 bar. In order to convert the plant to fully abated CCS state, it is only necessary compress the already liquid CO2 to 150 bar supercritical state. This requires the addition of a small liquid CO2 pump with only 0.06% net energy penalty and 0.2% CAPEX penalty. This explains the exceptionally low marginal abatement cost of carbon for the carbon negative SNG scheme with Timmins CCS.
Building on waste gasification experience, the key to viable economics
The big question is: can carbon negative SNG be produced at a price which is competitive with fossil natural gas? Some 80% of the levelised cost of SNG is CAPEX recovery and fuel costs. The answer is “yes” if waste gasification is factored in.
Our work has concentrated on reducing fuel costs by using waste as the primary fuel, with biomass and coal as the secondary fuels.
The basic physics and chemistry of modern high pressure gasification were developed before WW1. The first commercial coal fuelled dry ash Lurgi gasifier was built in the late 1930s. The first pilot oxygen blown slagging Lurgi gasifier, designed to run on Italian lignite, was built in 1943. Its existence was disclosed to allied intelligence in Frankfurt in April 1945 and reported to the UK government Ministry of Fuel and Power in 1947. The slagging gasifier used less steam than the dry ash gasifier, and could operate on low grade fuels. The UK government reported in 1947 than the cost benefit of using low grade fuel had to be balanced against the cost of oxygen.
A second pilot slagging Lurgi gasifier was built in Germany in 1953. The joint rights to the design were acquired by the UK Ministry of Fuel and Power in 1955. From 1955 to 1992 the British Gas Lurgi (BGL) slagging gasifier was developed in the UK, first at the Midlands Research Station (MRS) in Solihull, and latterly at the Westfield development centre.
Use of waste as a low cost substitute fuel was first considered at MRS in the early 1970s, and some low key experiments were carried out. In the late 1980s British Gas assisted the East German state run town gas plant at Schwarze Pumpe with experiments using a converted dry ash Lurgi gasifier, fitted with a slagging hearth, to co-gasify a 50/50 waste/coal mix.
From 1990 onwards the design of a commercial scale BGL gasifier, using operational data from Westfield, resulted in full environmental consent being granted in 1998 for the use of the BGL to co-gasify several hundred different classifications of hazardous and non-hazardous wastes at Schwarze Pumpe, at up to 85% waste/15% coal. Commercial operations commenced in 2000. The plant was dismantled in 2007, and is now in India awaiting re-erection as a lignite to fertiliser plant.
Typically the BGL at Schwarze Pumpe ran on a 75 to 80% mixed wastes/20 to 25% mixed coal and lignite feed stock. Test runs in 2003, supported by the European plastics industry (Tecpol), indicated stable operation on 80% mixed wastes/20% coal fuel mix.
A changing economic landscape for waste
The combination of landfill tax, various incentives for the use of renewables and the carbon floor price have revolutionised the economic landscape in the UK for waste, biomass and coal co-gasification, when combined with low cost CCS. We believe that the BGL is the world’s highest net efficiency, and most operationally flexible, large scale gasifier capable of handling high waste content fuels and biomass.
In many parts of the world, residual waste (after reduction, recycling and re-use) is the most widely available and lowest cost sustainable indigenous fuel resource, but burning waste in a moving grate incinerator to produce low grade steam for base load power generation at around 25% net efficiency is expensive and inefficient. In comparison the British Gas originated SNG scheme with Timmins CCS can produce carbon negative SNG, which is a storable and dispatchable energy commodity, at 76.75% net efficiency, ie three times more ‘bang for your buck’.
Due to the far higher net energy efficiency, the capital cost per unit output energy of a waste gasification plant is lower than for a waste incinerator.
Around 34% of a waste incinerator’s mass throughput is produced as solid, liquid and gaseous emissions requiring expensive flue gas clean up, and secondary hazardous or leachable waste processing and disposal operations.
Coal and waste are both dirty hydrocarbon fuels. High temperature oxygen blown ‘clean coal’ slagging gasification technology, designed to co-vitrify the heavy metal and minerals in low grade coal or lignite is equally applicable to waste processing, and massively reduces the secondary waste processing problems associated with waste incineration. Indeed the BGL slagging gasifier can utilise the hazardous air pollution control residues produced by waste incinerators as a flux to promote slag formation.
As already noted, the BGL gasifier at SVZ Schwarze Pumpe (Figure 7) was granted full environmental certification in 1998 to co-gasify up to 85% mixed hazardous and non-hazardous wastes, and 15% coal, and was approved by UNEP in 2006 for the highly efficient (99.99%) permanent destruction of persistent organic pollutants. Hazardous heavy metals are immobilised in a certified non-leaching vitrified recyclate.
Coal to SNG is not economic in Europe or USA due to the low price ‘spread’ per unit energy between coal and natural gas being insufficient to cover the capital cost of an SNG plant. SNG developments are proceeding apace in China due to the large ‘spread’ between the low cost of stranded coal assets in western China, and the high cost of gas on the eastern China seaboard. Gas pipelines are the lowest CAPEX method of bulk energy transmission. There is already experience with BGL and SNG production in China, see Figures 8 and 9.
The Great Plains synfuel plant is commercially viable due to a combination of: low cost mine-mouth lignite as fuel; economic co-production of SNG, power, fertiliser, phenol and CO2 for commercial EOR at Weyburn in Canada; and the low capital recovery rate for federal funds invested in the project. Our concept is to increase the price ‘spread’ between solid fuels and natural gas by using waste as a low cost fuel to displace a large part of the coal supply.
In order to reduce the use of landfill for waste disposal, many countries tax the use of landfill from waste, and incentivise the production of ‘clean’ energy from waste. The UK landfill tax escalator runs until 2015, then is flat to 2021, with proposed inflation indexation from 2021 to 2028. The 2015 landfill tax will be £80/tonne. Assuming a typical mixed non-hazardous waste stream contains an average of 10 GJ/tonne of thermochemical energy, the avoided cost of landfill tax is an effective £-8/GJ fuel subsidy. This can be used to offset the typical UK cost of coal and biomass at around £3.0 to 3.50/GJ. Using an average 50:30:20 waste, biomass, coal (by mass) fuel mix as a basis, combined with processing of hazardous air pollution control residues produced in waste incinerators, it is possible to devise a net negative cost fuel mix with nearly 55% biogenic carbon content.
A strong case in the UK, EU and elsewhere
Our analysis shows that under a range of feasible policy scenarios, during the period 2012 to 2030, a carbon negative SNG plant in UK, with a fuel input of around 1.0 to 1.5 million tonnes pa (660 to 1000 MWt fuel input) of mixed fuels will produce carbon negative SNG at a cost of around 40 to 45 p/therm, based on a 20 year payback period and 8% weighted aggregated cost of capital.
The cost of carbon negative SNG in the UK case includes the avoided cost of UK landfill tax, the avoided cost of the UK carbon floor price, and a substantial developer’s risk premium, but excludes the additional revenue from the Renewable Heat Incentive (RHI) until 2031, currently 104 p/therm for 54.6% biogenic carbon content SNG.
The current open market wholesale price of natural gas in the UK is around 65 p/therm. This is expected to increase to around 70 p/therm by 2015, and then gradually decrease from the mid 2020s onwards. There is considerable debate about the long-term price trajectory for gas in EU and UK. It depends on, among other things, the rate at which conventional gas is supplemented by unconventional gas, and the impact this has on long-run oil-indexed gas prices. Informal advice from parties associated with shale gas development in the UK suggests that a technically and financially robust scheme, which is cost competitive with the long-term price trajectory for gas of around 40 to 45 p/therm, is considered to be ‘bankable’.
The UK CCS cost reduction task force recently reported that by 2030 the cost of power generation with “conventional” CCS might feasibly be reduced from around £160/MWh to around £100/MWh base load (8000 hours pa), the cost of sequestered carbon reduced from around £150/tonne to about £50/tonne, and the rate of CO2 capture increased from 85% to 90%.
Over the same period, and using the same assumptions as the task force, the cost of power generation from carbon negative SNG would reduce from £55/MWh to £40/MWh, the cost of sequestered carbon would reduce from £15/tonne to £3/tonne, with the equivalent of 110% CO2 capture rate. Even allowing for optimism bias, and discounting any benefit from the RHI, there is a strong case to be made for developing carbon negative SNG in the UK, and elsewhere in the EU.
There is also a strong case to be made for developing low cost carbon negative SNG with Timmins CCS in a number of countries (eg, USA, China, S Korea, Japan as well as in the EU) as a means of economically supplementing natural gas resources, addressing the problem of ever increasing production of hazardous and non-hazardous wastes, and reducing atmospheric emissions. The specific circumstances of each country would of course need to be taken into account when developing any particular scheme.
*This article draws on the presentation given by Dr Williams at the IChemE Gasification Conference in Cagliari, Sardinia, May 2012. It also follows on from the article on Timmins CCS published in the January 2013 edition of Modern Power Systems.
Timmins CCS is a generic CO2 separation scheme for any gas flow above 10 bar pressure, using rearranged standard gas processing plant. In the Timmins CCS scheme the whole plant operates at high pressure, thus avoiding de-pressurisation and re-pressurisation costs, and producing high purity high pressure liquid CO2. Timmins CCS may be integrated into a wide variety of power generation, gas processing, reforming, urea and petrochemical plants where it is desired to separate CO2 as a high purity, high pressure liquid.
Three different schemes, based on three different fuels, using the Timmins CCS process for gas turbine power generation, are currently being developed:
– Waste, biomass and coal: co-gasification with CCS to produce carbon negative SNG (as described in the present article), currently, the most advanced development of Timmins CCS.
– Coal: IGCC with CCS and a hydrogen fired CCGT. This was the topic of the January 2013 article in MPS. An update is planned, reporting on the latest results, which are greatly improved relative to those published previously.
– Natural gas: partial oxidation (POX) with autothermal reforming with a dual fuel high-hydrogen syngas/natural gas fired CCGT. Energy is recovered from the hot gases produced by the POX reactor in an expansion turbine prior to further reforming, CCS and the CCGT. The additional energy recovered by the expander turbine offsets the energy losses in the reforming stages.
