Monday, January 20, 2020

Low Cost Decarbonising of Gas From Mixed Waste, Biomass and Coal


Methane is not necessarily a fossil fuel. Gas can be decarbonised economically prior to injection into the high pressure gas grid. British Gas (BG) developed high efficiency Synthetic Natural Gas (SNG) technology between 1955 and 1992. Costly British coal made SNG uneconomic compared with North Sea gas. Replacing coal by low cost waste makes SNG economically competitive. 60 bar negative emissions LCG produced for 40 to 45 p/therm, less than the cost of Natural Gas, will enable gas users, and existing CCGT’s, to be decarbonised at zero cost.

SNG making is inherently carbon capture ready. CO2 separation and compression is standard gas industry practise. High pressure LCG made by co-gasifying partly biogenic mixed waste, biomass and coal, using integrated ex-BG SNG and high CO2 partial pressure Timmins CCS processes, produces supercritical CO2 by-product for 40p/tonne. Per unit energy output, 3 to 4 times less CO2 is produced by LCG than CCS on fossil power generation.  Supercritical CO2 produced in smaller quantities, at lower cost, is more useful for enhanced oil, gas and Coal Bed Methane recovery, ‘dry’ fracking and CCU than large quantities of expensive CO2 from fossil power generation.

The three main gaseous energy vectors are: Synthesis Gas (Syngas), Hydrogen and methane. Methane provides the backbone of the UK energy system. This article explores low cost decarbonising of gas at source.


Low Carbon Gas (LCG) is made by combining the methanation of 50+% biogenic mixed part biogenic and part fossil fuels, with CCS. Sequestering sustainably sourced biogenic CO2 removes anthropogenic CO2 from the Earth’s atmosphere. The negative emissions from sequestering biogenic carbon are used to offset fossil carbon  emissions. Biogenic carbon emissions and sequestered fossil carbon are accounted as emissions neutral. The waste CO2 by-product of methanation used for CCS is typically over 50% of the total Carbon throughput. Combining 50+% biogenic fuel and 50+% CCS produces negative net emissions of anthropogenic CO2.

Gt. Plains Synfuel plant produces commercially viable SNG from lignite. Inherently carbon capture ready methanation produces waste CO2 by-product for commercial EOR. Replacing part of the lignite fuel at Gt. Plains with low cost mixed wastes and biomass would economically decarbonise the product SNG to produce LCG.

Injecting low cost high pressure LCG into the gas grid decarbonises existing CCGT’s at zero operational cost, or  loss of load factor. CCGT’s can be geographically distributed, with LCG plants grouped near CCS ‘hubs’. Carbon capture ready unabated LCG plants can easily be abated when a supercritical CO2 ‘hub’ or pipeline becomes available. LCG can support low cost Power to Gas and intermittent renewable energy storage. Low cost supercritical CO2 can support ‘dry fracking’, enhanced oil or shale gas recovery and CCS in depleted shale gas wells providing an onshore gas industry method of reducing the cost of decarbonising energy supplies, and the cost of CCS. Integrated methane synthesis with CCS is the key ‘hub’ technology to deliver low carbon gas and power.


The cost of synthetic methane is dependent on:

  • Efficient process design.
  • Fuel cost.
  • Cost of capital.
  • Economies of scale.

BG’s cost studies indicate that for a given process, and cost of fuel and finance, the output cost of SNG was dependent on plant size and process pressure. BGL gasification at 65 bar pressure was demonstrated at Westfield in the 1980’s. BG estimated that gasifying coal at 80 bar would produce 60 bar SNG at 76% efficiency unabated. The BGL gasifier produces high methane content Syngas. Increasing gasification pressure, and replacing coal by the plastic in waste, increases methane yield and reduces the work to convert Syngas to methane.

A recent 4 year proof of concept study, using commercially confidential ex-BG cost and engineering data, indicates that integrating proven high efficiency BG methanation technology operating at 70 bar with waste based fuels, and Timmins CCS, produces 60 bar pipeline ready negative emissions LCG, and dry 99.6% pure 150 bar supercritical CO2, at a net efficiency of 76.75%. This must be one of the few cases where the use of low grade secondary fuels, and adding CCS, increases the efficiency of the underlying unabated technology.


SNG production is established technology, its economic viability depending on the price ‘spread’ between the fuel and Natural Gas. Due to the large ‘spread’ between low cost stranded West China coal and expensive East coast LNG imports, inter-connected by low cost gas pipelines, SNG production in China is developing rapidly.

The Lurgi dry ash gasifier was developed during the 1930’s. The first pilot of its derivative the slagging Lurgi gasifier was built in 1943 to gasify Italian lignite. In 1947 HM Ministry of Fuel and Power reported that the economic case for the slagging gasification of low grade fuel lay in the fuel cost being low enough to cover the cost of oxygen. In 1955 the Ministry purchased the rights to the slagging Lurgi gasifier, now called the British Gas Lurgi or BGL gasifier. This uses less steam and oxygen than the dry ash version. The future of gasification in  Europe lies in gasifying low grade secondary fuels. The diversion of large quantities of waste from landfill has turned residual waste into a useful low cost fuel. The ‘spread’ between the unit cost of low cost mixed wastes, biomass and coal, and the unit cost of fossil Natural Gas makes SNG production in EU and UK economically viable.


The avoided cost of 2015 UK Landfill Tax at £-8/GJ offsets the cost of coal and biomass at around £2.25 to £4.0/GJ producing a near zero cost 50+% biogenic fuel mix. The ‘spread’ between waste at £-8/GJ and Natural Gas at around £6.25/GJ makes converting waste to gas financially attractive. Using some coal in the fuel mix to provide the energy to drive slagging gasification is far more economic than using electricity to drive plasma gasification.

The projected 40 to 45 p/therm (£15/MWh) unit cost of 60 bar storable LCG at from high CO2 partial pressure LCG making with CCS is around 1/6th the projected £100/MWh unit cost of CCS on low CO2 partial pressure fossil fuel power generation. The 40p/tonne unit cost of supercritical CO2 (sCO2) from an LCG plant with Timmins CCS is around 2 orders of magnitude lower than for fossil fuel power generation. The cost per unit energy of sCO2 transport and storage from an LCG plant is around ¼ to 1/3rd the cost per unit energy of sCO2 transport and storage from CCS on fossil fuel power generation.

Co-gasifying approximately 50% mixed secondary fuels: residual hazardous and non-hazardous residential, commercial and industrial wastes; Refuse and Tyre Derived Fuel; petcoke; sewage and industrial sludges; 30% contaminated and woody biomass, and 20% coal or briquetted lignite reduces input fuel costs to near zero, and contains nearly 55% biogenic carbon, delivering LCG and CCS at lower cost than any other fuel/technology mix.


When the UK gas grid was converted from Towns Gas to Natural Gas, it was known that the different properties of the two gases would make re-conversion to Towns Gas impractical. It was unclear whether UK possessed sufficient Natural Gas to supply its needs, and how long it would last. Supported by HM Government, BG embarked on a strategic long-term programme to develop SNG against a future shortage of Natural Gas. BG “High Speed Gas” naptha to SNG conversion was commercialised in USA. Pulverised coal hydrogenation to SNG was demonstrated at test rig scale. Commercial scale high efficiency BGL slagging gasification and HICOM combined catalytic shift and methanation of lump or briquetted coal to SNG technology was developed between 1955 and 1992 The SNG development plant at Westfield was mothballed on completed of the R and D programme.

Co-gasifying waste, biomass and coal using the BGL gasifier was demonstrated commercially at SVZ Schwarze Pumpe between the late 1980’s and 2007. Gt. Plains has been converting lignite to SNG since 1984 using Lurgi dry ash gasifiers, with CCS for EOR since 1999. Westfield, Gt. Plains and SVZ were always inherently carbon capture ready. Different elements of the LCG process chain were developed at the plants, but the whole chain was not demonstrated at a single plant. Except for this accident of history, large scale low cost LCG might have been commercialised 30 years ago. BGL gasifiers are being built in China to use low grade stranded North China coal assets. HICOM catalysts are used at Great Plains and the recently completed Phase 1 SNG plant at Datang.


Both the BGL gasifier and HICOM combined shift and methanation use internal mass and energy transfer to maximise process energy efficiency. Carbon is oxidised to provide the energy to drive the gasification and methanation reactions. During gasification and methanation, oxygen and steam are injected into the process gas stream. The hydrogen to oxygen molecular bond in the steam is broken, and the hydrogen re-bonded to carbon, producing methane. CO2 is separated to leave the methane product gas. Hydrogen and oxygen are added to the process gas stream, and CO2 is removed. In essence, carbon to hydrogen mass and energy exchange occurs.

The BGL is counter-current gasifier. Hot Syngas flows upwards from the gasification zone at the bottom of the gasifier causing the fuel being fed by gravity from the top of the gasifier to be dried, pre-heated, devolatilised and pyrolised prior to gasification. The Syngas is cooled from around 2000 to 5000C. Internal heat exchange reduces the need for external Syngas cooling and heat exchange, and increases process efficiency.

HICOM combined catalytic shift and methanation combines two exothermic reactions. This reduces the requirement for external heat exchange, and maximises exothermic energy recovery to high temperature and pressure steam used for power generation and process utilities. The shift reaction absorbs water. The methanation reaction produces water. Internal water exchange occurs between the shift and methanation reactions. This reduces steam injection and downstream water vapour removal.


IPPC, IEA, UK CCSA and Schlumberger state that CO2 partial pressure (CO2 concentration x pressure) is the ‘key’ determinant of CO2 capture and compression cost, which is 80% of the cost of CCS. CO2 solubility in a carrier liquid is a function of gas pressure. The volume flow rate of gases, and vessels, pipe and pump size, is a function of gas pressure. CO2 concentration determines the amount of gas to be processed to obtain a given amount of CO2. For the same energy input, the CO2 partial pressure in an SNG plant with Timmins CCS is 250 times greater, and the gas volume flow rate 400 times less, than in a fossil fuel power plant with post-capture CCS. This massive engineering and cost benefit is due not to any ‘magic’, but to basic process physics and chemistry.


Cyril Timmins led the BG SNG commercialisation programme. His co-patentee, Keith Tart was co-patentee for HICOM. The Timmins CCS recycle loop is a generic process for reducing the cost of separating CO2 from mixed gas streams at over 10 bar gas pressure. The efficiency penalty of CO2 separation and compression is reduced by running the whole plant at high pressure, with no pressure let-down. The cost of cryogenic separation is reduced by separating half the CO2 at each pass. The part CO2 content gas mix is recycled back into the process using the incoming process gas as ‘stripping gas’. The CO2 recycle loop is the basis for the patent, and is applicable to any process separating CO2 from high pressure mixed gases.

The Timmins CCS process is an elegant ‘fit’ with high pressure HICOM combined shift and methanation. In the integrated process, the high CO2 partial pressure assists in inhibiting the harmful Boudouard reaction (2CO = C + CO2). The recirculated CO2 assists gas cooling during exothermic methanation. Cryogenic separation of part of the

CO2 stream reduces the work done by the Selexol plant. The volume flow rate of the process gases is 400 times less, and the CO2 partial pressure is 240 times greater, than post combustion CCS on fossil fuel power generation.

In the unabated LCG with Timmins CCS case, dry 99.6% pure liquid CO2 is produced at 60 bar. In the abated case, the energy penalty to pump cool liquid CO2 to 150 bar supercritical state is only 0.06%. This leads to the Marginal Abatement Cost of Carbon capture and compression of £0.4/tonne, excluding transport and storage costs. The transport and storage cost of CO2 per unit energy is 25 to 33% that for CCS on fossil fuel power generation.


CCSAssociation’s recently reported on reducing the whole system cost of CCS on power generation. Using the CCSA’s published data, and LCG production cost analyses, the ‘whole system’ cost (including transport and storage) of power from LCG is around 1/3rd the cost of CCS on fossil fuel power generation. The whole system cost per tonne of CO2 from LCG is between 5% and 10% of CCS on fossil fuel power generation.


Gasification technology is highly flexible. Clean Syngas supports numerous downstream uses for Syngas. Low cost LCG, low cost supercritical CO2 and ‘green’ Hydrogen can support a variety of clean energy technologies.


LCG production uses both the hydrogen and oxygen produced by P2G plants, and the existing gas grid for economical bulk renewable energy storage and transmission. Injecting hydrogen into HICOM increases methane production and reduces CO2 production. Less steam is required for the shift reaction; less excess steam has to be removed after methanation, and exothermic heat output increases. Oxygen from electrolysis reduces the load on the air separation unit. LCG plant efficiency is increased for the same fuel input and plant CAPEX. The enhanced Return on Capital Employed for the LCG plant can be used to offset the low ROCE for the P2G plant.


Low cost supercritical CO2 can be used for: drilling; enhanced shale ‘dry’ fracking and proppant; EGR by methane desorption, reservoir re-pressurisation and ‘sweep’ gas, and CCS in depleted conventional and unconventional oil and gas wells. Most Natural Gas reservoirs contain some CO2, which must be removed in order to meet gas quality standards. Timmins CCS can be used for gas removing CO2 returned from conventional gas, EGR and ECBR.


Making economic use of supercritical CO2 for EOR and EGR depends critically on matching supercritical CO2 supply and demand to raise the revenue to pay for CCS infrastructure. A typical large UKCS oil field uses around 2 to 3 mtpa of supercritical CO2 for a period of around 5 years, reducing by around 50% after 5 years. A 1GWe fossil fuel power station produces around 6 mtpa of CO2, but this may fluctuate dramatically depending on the balance of electricity supply and demand in the grid. A 1 GWSNG LCG plant produces around 1.75 mtpa of CO2, and will operate largely at constant throughput as the gas grid operates as an effectively infinite capacity energy store. This will enable supercritical CO2 supply and demand by the UKCS oil and gas industry to be balanced against supercritical CO2 production from LCG more easily than for fossil fuel power generation.


Low cost LCG derived from waste and industrial sources; low cost high purity CO2 produced by Timmins CCS, and ‘green’ hydrogen can support a wide variety of chemical and biological synthesis routes to produce a variety of low carbon products, foods and energy vectors. Some of the more promising of these are shown below. In this concept, Syngas, hydrogen and LCG production are integrated around the ‘core’ methane synthesis and CCS.

Source: Dr. Williams - IChemE gasification conference


The 10 largest coal producers and exporters in Indonesia:

  1. Bumi Resouces
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  3. Indo Tambangraya Megah
  4. Bukit Asam
  5. Baramulti Sukses Sarana
  6. Harum Energy
  7. Mitrabara Adiperdana 
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