Low cost carbon negative SNG (substitute

Transcription

1 Carbon negative SNG from waste, biomass and coal: a cost-effective way to decarbonise gas-fired generation When waste is gasified, along with biomass and coal, the economics of producing carbon negative SNG (synthetic natural gas) are transformed. In the scheme proposed here, using the highly fuel flexible BGL gasifier, in conjunction with HICM combined catalytic shift and methanation, plus the Timmins process, the cost per unit energy of carbon negative SNG is estimated to be as little as 1/15th of the whole system cost of wind power. Carbon negative SNG fuelled dispatchable power generation may produce lower whole system emissions than intermittent wind, when emissions from fossil fuel back up are considered. A. R. Day, A. Williams, GL Noble Denton Ltd, and Chris Hodrien, Timmins 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 all 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 SNG can be produced at a cost which is 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 cogasification (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 concept.* The basic idea (Figure 1) is to use high efficiency slagging co-gasification to produce carbon negative synthetic natural gas with. The low cost carbon negative SNG, with gas, and natural gas back up, is used in a conventional natural gas fired combined cycle plant with no loss of efficiency or operational flexibility. Figure 1. Carbon negative SNG scheme (source GL Noble Denton Ltd) 80% waste & biomass 0% coal 70 bar BGL gasifier CS hydrolysis Gas cooling and cleaning N ASU Steam 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 S S removal CCGT Site power Boiler feed water HICM methanation NG import/ SNG recirc. Electrical export 150 bar removal Drying SNG SNG export produce green hydrogen, oxygen and heat for low cost demand management and energy (see Figure ). 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 0% coal by mass. *This article draws on the presentation given by Dr Williams at the IChemE Conference in Cagliari, Sardinia, May 01. It also follows on from the article on Timmins published in the January 013 edition of Modern Power Systems. Timmins is a generic separation scheme for any gas flow above 10 bar pressure, using rearranged standard gas processing plant. In the Timmins scheme the whole plant operates at high pressure, thus avoiding de-pressurisation and re-pressurisation costs, and producing high purity high pressure liquid. Timmins may be integrated into a wide variety of power generation, gas processing, reforming, urea and petrochemical plants where it is desired to separate as a high purity, high pressure liquid. Three different schemes, based on three different fuels, using the Timmins process for gas turbine power generation, are currently being developed: Waste, biomass and coal: co-gasification with to produce carbon negative SNG (as described in the present article), currently, the most advanced development of Timmins. : IGCC with and a hydrogen fired CCGT. This was the topic of the January 013 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 (PX) with autothermal reforming with a dual fuel high-hydrogen syngas/natural gas fired CCGT. Energy is recovered from the hot gases produced by the PX reactor in an expansion turbine prior to further reforming, and the CCGT. The additional energy recovered by the expander turbine offsets the energy losses in the reforming stages. 36

2 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: 0 years, 8% weighted aggregate cost of capital. Cost of 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 : 0.4 per tonne excluding transport and. Cost of transport and : 33% of the unit cost of transport and per unit energy output compared with a fossil fuel power station. Net emissions intensity: -45 g /kwh, assuming carbon negative SNG is used in a 60% efficient CCGT. Figure. Diversified low cost low carbon energy system with large scale green gas and energy (source Fraunhofer Institute) Storage and energy mgt. Hydro, ocean Geothermal Solar Wind ELECTRICITY NETWRK Super Smart Grid pumps recycling, Power Transport CHP, turbines, fuel cells, gas with H Electrolysis -tank Nuclear Combust. engine* ing systems HEAT NETWRK Storage ptional Co-gasification CH 4 NATURAL GAS NETWRK Natural gas, shale gas coal bed methane, underground coal gasificaton Storage Biomethane 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- to a natural gas fired CCGT significantly compromises many of those advantages. ur 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 54.6% bio C Fuel 45.4% fossil C 9.9% bio C Electricial energy Thermal energy Mechanical energy Chemical energy (methane) Chemical energy (hydrogen) and vector. But methane is not necessarily a fossil fuel. The fossil 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 emissions from the use of methane can be negated by a combination of partly biogenic carbon fuels and (Figure 3). A typical mixed waste stream contains around 65% biogenic carbon. A typical 50% mixed residual waste, 30% biomass and 0% coal fuel mix contains 50 to 55% net biogenic carbon (as a proportion of total carbon). A typical methanation plant produces nearly 55% Figure 3. Waste, biomass and coal to carbon negative SNG emissions balance (source A. R. Day) EMISSINS BALANCE Fossil carbon emissions 0.6% Sequestered biogenic carbon -9.9% NET NEGATIVE EMISSINS - 9.3% Methanation 54.7% 4.7% bio C Gas grid/ 45.3% end users 0.6% fossil C 4.8% fossil C Sequestered biogenic carbon offsets fossil carbon emissions Emissions Electromobility Methanation, Green gas Waste (65% bio C) of total carbon throughput as, 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. SNG plants are inherently carbon ready as they produce as a waste byproduct. Compared with fossil fuel power stations, SNG plants produce relatively low volumes of high partial pressure mixed SNG and, and can be converted economically to. 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 000 with and pipeline compression for ER at Weyburn in Canada. The carbon negative SNG with Timmins scheme discussed here uses the same British Gas developed catalysts as at Great Plains. April MDERN PWER SYSTEMS 37

3 Figure 4. Comparative partial pressures for four power generation processes (source Timmins Ltd) after combustion post-combustion Air xygen Conventional SSP / before combustion pre-combustion xygen 10 m 3 /sec 45% 30 bar Decarbonised synthetic natural gas Waste High partial pressure, low cost Conventional PP with flushing xyfuel combustion Steam generator IGCC.5 m 3 /sec 54% Reducing the cost of installed on fossil fuel thermal power generation is currently uneconomic due to the high cost of and compression from power station flue gases. This is the largest single impediment to the large scale deployment of on power generation. n the other hand, on gas based processes is already economic, and in use at commercial scale. The solubility of gaseous in a liquid solvent carrier is proportional to the concentration of in the original mixed gas stream, and the pressure of the gas stream. Concentration x pressure = partial pressure. partial pressure is thus the key determinant of the capital and operational cost of separation and compression. The IEA recently stated The higher the partial pressure, the greater the ease of, and the lower the cost per tonne of d and stored. At the point of separation, and for the same plant energy input, the gas flow rate in an SNG plant with Timmins is 400 times less, and the partial pressure is 50 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 and compression from an SNG plant is two orders of magnitude lower than for post-combustion 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 Low partial pressure, high cost g Flue gas cleaning Flue gas cleaning cleaning shift cleaning 1000 m 3 /sec 13% 00 m 3 /sec 60-70% Shift, methanation, Condensation 1 bar turbine Combined cycle 1 bar CCGT, heat, industry, transport 199 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 DE/NETL Worley Parson coal or lignite to SNG scheme, with the option of fertiliser co-production. The British Gas scheme delivers 5% more SNG per tonne of coal than the DE/NETL scheme. The technology was successfully demonstrated at the British Gas SNG development plant at Westfield prior to its closure in 199. 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 HICM combined catalytic shift and methanation process, with a range of standard industrial gas cleaning processes: Rectisol pre-wash, CS hydrolysis, Selefining, Claus/Scot and Selexol. Both the BGL and HICM 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 C 155 bar steam drives on-site power supply, air separation and a range of plant processes. Increasing the operating 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 Integrating the use of partly waste based fuels and Timmins (Figure 6) with HICM and Selexol acid gas removal increases the efficiency of the base BGL, HICM 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 stream to HICM reduces the amount of product gas recycled for cooling purposes. It also assists in suppressing the Boudouard reaction (C = C + ), 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 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 HICM and Selexol plants offset the efficiency penalty for the Timmins cryogenic plant. A carbon ready SNG plant with the Timmins process produces high purity ambient temperature liquid at. In order to convert the plant to fully abated state, it is only necessary compress the already liquid to 150 bar supercritical state. This requires the addition of a small liquid pump with only 0.06% net energy penalty and 0.% CAPEX penalty. This explains the Steam 4.4 in slag 0.6 losses 3.7 Recoverable heat Fuel gas 93.5 Byproduct recycle 13. Gaseous sulphur compounds 1.0 High cold gas efficiency Figure 5. Sankey diagram for British Gas Lurgi (BGL) slagging gasifier. Features of the BGL process include: heat recovery from product gas by contact with coal bed; low oxygen consumption, 50-60% of that for entrained flow gasifiers; high cold gas efficiency; high carbon conversion; low gasifier outlet temperature; inexpensive and well proven conventional gas cooling train; low content in syngas; and, of particular significance, high methane output suitable for SNG production 38

4 exceptionally low marginal abatement cost of carbon for the carbon negative SNG scheme with Timmins. 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. ur 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 Its existence was disclosed to allied intelligence in Frankfurt in April 1945 and reported to the UK government Ministry of Fuel and Power in 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 The joint rights to the design were acquired by the UK Ministry of Fuel and Power in From 1955 to 199 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 Figure 6. Integrated Timmins, BGL gasifier and HICM methanation (source Timmins Ltd). The whole plant runs at high pressure. Marginal abatement cost of dry 99.6% purity 150 bar is 40 p/tonne at the plant gate. Waste Part of syngas flow used as stripper gas to separate in selexol regenerator 70 bar BGL gasifier plant 1/3 /3 recycle BG HICM methanation Selexol 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 000. The plant was dismantled in 007, 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/0 to 5% mixed coal and lignite feed stock. Test runs in 003, supported by the European plastics industry (Tecpol), indicated stable operation on 80% mixed wastes/0% coal fuel mix. Base plant (CCR) Cryo sep n Add bar pump to convert from CCR to. Plant gate cost < 0.5/ton of Cryo pump Liquid to pipe SNG to GRID Add cryogenic separation to British Gas SNG scheme Future carbon 150 bar 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. 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 5% net efficiency is expensive and inefficient. In comparison the Figure 7. BGL gasifier at SVZ (source GL Noble Denton Ltd, Envirotherm GmbH) April MDERN PWER SYSTEMS 41

5 British Gas originated SNG scheme with Timmins 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. 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 slagging 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 006 for the highly efficient (99.99%) permanent destruction of persistent organic pollutants. Hazardous heavy metals are immobilised in a certified non-leaching vitrified recyclate. 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 for commercial ER at Weyburn in Canada; and the low capital recovery rate for federal funds invested in the project. ur concept is to increase the price spread between solid fuels and natural gas by using waste as a subsidised 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 015, then is flat to 01, with proposed inflation indexation from 01 to 08. The 015 landfill tax will be 80/tonne. Assuming a typical mixed nonhazardous 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 50:30:0 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 ur analysis shows that under a range of feasible policy scenarios, during the period 01 to 030, 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 0 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 Incentive (RHI) until 031, 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 015, and then gradually decrease from the mid 00s 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 UK and EU suggest a technically and financially robust scheme, which is cost competitive with long-term price trajectory for SNG around 40 to 45 p/therm is considered to be bankable. Figure 8. BGL gasifier in China, during construction (source GL Noble Denton Ltd, Zemag GmbH) The UK cost reduction task force recently reported that by 030 the cost of power generation with conventional 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 increased from 85% to 90%. ver 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% 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 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. MPS Figure 9. Recently completed methanation plant at Datang, China (courtesy Datang Chemical Engineering Co, Johnson Matthey plc, Davy Process Technology Ltd). This uses the same catalyst as that developed for HICM 4