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Freshwater ecosystems are responsible for a large proportion of global methane emissions to the atmosphere. The radiocarbon (14C) content of this aquatic methane is useful for determining the age and source of this important greenhouse gas. Several methods already exist for the collection of aquatic methane for radiocarbon analysis, but they tend to only sample over short periods of time, which can make them unsuitable for characterizing aquatic methane over longer timespans, and vulnerable to missing short-term events. Here, we describe a new time-integrated method for the collection of aquatic methane that provides samples suitable for radiocarbon analysis, that are representative for periods of up to at least 16 days. We report the results of a suite of tests undertaken to verify the reliability of the method, and the 14C age of aquatic methane from field trials undertaken at sites within Scotland, UK. We believe that this new method provides researchers with a simple approach that is easily deployable and can be used to collect representative time-integrated samples of methane for radiocarbon analysis from a wide range of aquatic environments. [ABSTRACT FROM AUTHOR]

Twenty-four Merino lambs were allocated to three dietary treatment groups to determine the effects of a dietary starch and protein binding agent and heat stress on methane (CH4) emissions and rumen parameters. The diets were a wheat-based diet (WD), a 2% Bioprotect™ (Bioprotect™, RealisticAgri, Rutland, UK) treated wheat-based diet (BD), and a maize-based diet (MD) for 3 periods of 1-week duration. During Period 1 (P1) the lambs were maintained under thermoneutral conditions and at a 1.7 × Maintenance (M) level. During P2 and P3, the lambs were maintained under cyclic heat stress conditions and fed at 1.7 × M and 2.0 × M, respectively. Total CH4 production was lower for the BD diet than the WD diet, which in turn was lower than the MD diet (p < 0.001). Total CH4 production was lower during P2 than P1 with P3 intermediate (p = 0.04). Rumen total volatile fatty acid (TVFA) concentrations were higher for the WD diet than the MD diet with the BD diet intermediate (p = 0.01). Rumen TVFA concentrations were lower during heat stress than under thermoneutral conditions (p < 0.001). Whole tract starch digestibility was higher for the BD and WD diets than the MD diet (p < 0.001). In conclusion, feeding Merino lambs the BD diet reduces CH4 emissions without reducing starch digestibility. [ABSTRACT FROM AUTHOR]

Anaerobic digestion (AD) and sewage sludge digestion (SD) plants generate significant quantities of ammoniacal nitrogen in their digestate liquor. This article assesses the economic viability and CO2 abatement opportunity from the utilisation of this ammonia under three scenarios and proposes their potential for uptake in the United Kingdom. Each state-of-the-art process route recovers ammonia and uses it alongside AD-produced biomethane for three different end goals: (1) the production of H2 as a bus transport fuel, (2) production of H2 for injection to the gas grid and (3) generation of heat and power via solid oxide fuel cell technology. A rigorous assessment of UK anaerobic and sewage digestion facilities revealed the production of H2 as a bus fleet transport fuel scenario as the most attractive option, with 19 SD and 42 AD existing plants of suitable scale for process implementation. This is compared to 3 SD/1 AD and 13 SD/23 AD existing plants applicable with the aim of grid injection and SOFC processing, respectively. GHG emission analysis found that new plants using the NWaste2H2 technology could enable GHG reductions of up to 4.3 and 3.6 kg CO2e for each kg bio-CH4 supplied as feedstock for UK SD and AD plants, respectively. [ABSTRACT FROM AUTHOR]

We present a method for estimating fossil fuel methane emissions using observations of methane and ethane, accounting for uncertainty in their emission ratio. The ethane:methane emission ratio is incorporated as a spatially and temporally variable parameter in a Bayesian model, with its own prior distribution and uncertainty. We find that using an emission ratio distribution mitigates bias from using a fixed, potentially incorrect emission ratio and that uncertainty in this ratio is propagated into posterior estimates of emissions. A synthetic data test is used to show the impact of assuming an incorrect ethane:methane emission ratio and demonstrate how our variable parameter model can better quantify overall uncertainty. We also use this method to estimate UK methane emissions from high-frequency observations of methane and ethane from the UK Deriving Emissions linked to Climate Change (DECC) network. Using the joint methane–ethane inverse model, we estimate annual mean UK methane emissions of approximately 0.27 (95 % uncertainty interval 0.26–0.29) Tgyr-1 from fossil fuel sources and 2.06 (1.99–2.15) Tgyr-1 from non-fossil fuel sources, during the period 2015–2019. Uncertainties in UK fossil fuel emissions estimates are reduced on average by 15 % and up to 35 % when incorporating ethane into the inverse model, in comparison to results from the methane-only inversion. [ABSTRACT FROM AUTHOR]

• 10 UK biogas plant methane emission rates were estimated. • Total methane emissions were in range of 0.1 to 58.7 kg hr -1. • The percentage of losses relative to the calculated production rate ranged from 0.02 to 8.1%. • Biogas plants may averagely account for up to 1.9% of total methane emissions in the UK. The rising number of operational biogas plants in the UK brings a new emissions category to consider for methane monitoring, quantification and reduction. Minimising methane losses from biogas plants to the atmosphere is critical not only because of their contribution of methane to global warming but also with respect to the sustainability of renewable energy production. Mobile greenhouse gas surveys were conducted to detect plumes of methane emissions from the biogas plants in southern England that varied in their size, waste feed input materials and biogas utilization. Gaussian plume modelling was used to estimate total emissions of methane from ten biogas plants based on repeat passes through the plumes. Methane emission rates ranged from 0.1 to 58.7 kg CH 4 hr-1, and the percentage of losses relative to the calculated production rate varied between 0.02 and 8.1%. The average emission rate was 15.9 kg CH 4 hr-1, and the average loss was 3.7%. In general, methane emission rates from smaller farm biogas plants were higher than from larger food waste biogas plants. We also suggest that biogas methane emissions may account for between 0.4 and 3.8%, with an average being 1.9% of the total methane emissions in the UK excluding the sewage sludge biogas plants. [ABSTRACT FROM AUTHOR]

The focus of this research is the potential of biomethane in Britain's gas grid. It examines its relative ability to address Britain's sustainability and energy security challenges from an economic perspective. Such research is important because UK is wedded to gas for heat production and power generation and is increasingly dependent on imported gas, in line with shrinking domestic production, and uncertain future trading relationships. Also, dependency on natural gas, threatens Britain achieving its legally-binding carbon budgets. The study included a thorough literature review, primary research to finally uncover the views of key UK market participants plus analytical modelling. The findings reveal that the market is cautiously optimistic, despite reservations regarding feedstock availability and the impending cessation of subsidy approvals. Investors are in greater need of long-term certainty, however, and the challenge of decarbonising heat and heavy-duty transport warrants this. Retail price premiums are polarised but, in line with wholesale costs, relatively high compared to electricity. The key recommendation is for the policymakers to follow precedents in renewable electricity and liquid biofuels, by mandating that energy suppliers, owners of heavy-duty road fleets and occupiers of new buildings purchase biomethane. In tandem, feedstock and grid-entry restrictions must be tackled creatively. • Dependency on natural gas threatens Britain achieving its carbon budgets. • Biomethane is a solution for sustainable and clean gas supply for the UK. • Cautiously optimistic market in the UK on the future of biomethane in the energy mix • Polarised retail price premiums for green gas relatively high compared to electricity • Recommendation: UK policymakers to follow renewable electricity precedents [ABSTRACT FROM AUTHOR]

• 82% ammonia recovery from wastewater treatment plant digestate liquor. • Combined ammonia and biomethane fed solid oxide fuel cell modelled. • Increased renewable electrical power production of 45% compared with conventional system. • GHG emission reduction of 3.5 kg CO 2 e per year for each person served by treatment facility. Current standard practice at wastewater treatment plants (WWTPs) involves the recycling of digestate liquor, produced from the anaerobic digestion of sludge, back into the treatment process. However, a significant amount of energy is required to enable biological breakdown of ammonia present in the liquor. This biological processing also results in the emission of damaging quantities of greenhouse gases, making diversion of liquor and recovery of ammonia a noteworthy option for improving the sustainability of wastewater treatment. This study presents a novel process which combines ammonia recovery from diverted digestate liquor for use (alongside biomethane) in a solid oxide fuel cell (SOFC) system for implementation at WWTPs. Aspen Plus V.8.8 and numerical steady state models have been developed, using data from a WWTP in West Yorkshire (UK) as a reference facility (750,000p.e.). Aspen Plus simulations demonstrate an ability to recover 82% of ammoniacal nitrogen present in digestate liquor produced at the WWTP. The recovery process uses a series of stripping, absorption and flash separation units where water is recovered alongside ammonia. This facilitates effective internal steam methane reforming in the fuel cell with a molar steam:CH 4 ratio of 2.5. The installation of the process at the WWTP used as a case of study has the potential to make significant impacts energetically and environmentally; findings suggest the treatment facility could transform from a net consumer of electricity to a net producer. The SOFC has been demonstrated to run at an electrical efficiency of 48%, with NH 3 contributing 4.6% of its power output. It has also been demonstrated that 3.5 kg CO 2 e per person served by the WWTP could be mitigated a year due to a combination of emissions savings by diversion of ammonia from biological processing and lifecycle emissions associated with the lack of reliance on grid electricity. [ABSTRACT FROM AUTHOR]

This study introduces a new approach to estimate biomethane market potential by analysing biogas markets and their relative environmental and economic advantages. This potential is then combined with greenhouse gas emission values for different feedstock shares (farm-fed and waste-fed systems) and different application share to determine the possible contribution of biomethane to national greenhouse gas emission saving goals. Markets that are considered are Germany and the UK being the biggest emitters of CO 2eq in the European Union. The current use was compared with the scenarios (i) market projection, derived from literature study and (ii) reasonable potential, derived from environmental and economic calculations. The current market status is presented to show the past market development until the present date and associated greenhouse gas savings. Additionally the potential of biomethane to contribute to greenhouse gas emission savings is extensively described. Results indicate that the share of application in Germany is more environmental beneficial than the one in the UK achieving higher greenhouse gas savings at comparable feed-in level. In contrast, the UK has a higher share of waste-fed systems to produce biomethane. The use of biomethane in CHP plants achieves the highest GHG emission savings and if organic waste is used as feedstock the possible savings are even higher. With an increase of biomethane used in CHP plants and a decrease of biomethane used for direct heating the savings in the UK could increase up to 52%. Current savings of 2446 kt CO 2eq (Germany) and 606 kt CO 2eq (UK) can be extended to 4483 kt CO 2eq (Germany) and 1443 kt CO 2eq (UK) respectively. Scenario results were determined based on the environmental and economic advantageousness development of the existing biogas market. In this way positive future market development as well as improved shares of feedstock and application can contribute to further greenhouse gas emission savings of Germany and the UK. [ABSTRACT FROM AUTHOR]

• Two-stage gasification is 24–25% more economical than single-stage gasification. • Hydrogen from two-stage gasification is cost compatible to fossil fuel methane reforming. • Electricity from two-stage cost half the price of current electricity price in the UK. • Economic two-stage system achieved for feedstock cost ≤50 $/t or scale ≥1000 t/d. Although two-stage gasifier design offers a number of advantages i.e., producing high-quality gas (high H 2 content, low CO 2 and other impurities) and tolerating high degree of heterogeneity of feedstock, its economic feasibility is yet to be evaluated. In this study, a techno-economic assessment is fully conducted to assess the economic feasibility of a two-stage gasification system for three routes: hydrogen production, liquid fuels via Fischer-Tropsch synthesis, and electricity production from biomass. For a two-stage gasification of 20 years at a plant size of 1000 dry t/d, the total capital investment for hydrogen, FT-liquid and electricity production are US $214.8 million, US $345.5 million and US $307 million with operating costs of US $35.6 million/y, US $62.2 million/y and US $48.6 million/y, respectively. The minimum selling price for hydrogen (at a pressure of 70 bar) and liquid fuel from biomass is comparable to that from fossil fuels (US $1.59/kg for H 2 and US $1,109/m3 for liquid fuel) whereas for electricity (US $ 0.09/kWh), it is around half of the current electricity price from the grid in the UK. Comparing to conventional fluidised bed gasification for the same feedstock, around 25% cost reduction can be achieved for either hydrogen or liquid fuel production but only around 10% reduction for electricity. The results also show that the economics of the system can be improved further by 35–40% if the cost of feedstock is reduced by 30–50% at large-scale production facility (≥2000 dry t/d). [ABSTRACT FROM AUTHOR]

In the UK, AFC Energy has entered into a binding Heads of Agreement deal with HiiROC Ltd, whose plasma-based technology has proven its ability to extract hydrogen from methane and biomethane – readily available from incumbent gas networks – without CO 2 or other greenhouse gas emissions. The 'green' hydrogen produced using this technique could in turn fuel AFC's H-Power™ alkaline fuel cell systems, thereby opening up methane as a candidate carrier of green hydrogen for low-cost power generation. [ABSTRACT FROM AUTHOR]

• Accurate fuel consumption models were developed for gas and diesel trucks. • Results based on the models agree with the telematics data based results. • Reduction of equivalent carbon emissions with biomethane trucks is more than 70%. • In long haul operations, a CNG truck reduces equivalent carbon emissions by 10%. • Total cost of a gas truck break even with a diesel truck in approximately 2 years. • Difficult to run all trucks in the UK on biomethane due to limited availability. This article compares a conventional diesel-fuelled heavy goods vehicle with one that runs on compressed gas (CG): either Compressed Natural Gas (CNG) or biomethane. It includes an evaluation of the transport performance, carbon emissions, and total costs. 41 CG trucks were trialled by a supermarket, delivering goods from their distribution centre. One of the vehicles was instrumented with a gas flow meter, which measured the gas consumption, and a smartphone based data logger, which collected data from the truck's Fleet Management System (FMS) interface. Similarly, a baseline diesel truck was instrumented. Based on the measurements that were collected in-service, fuel consumption models were developed and validated. Using the validated models, the CG and diesel trucks were compared for their transport performance, costs and carbon emissions. In addition, the vehicles were evaluated using telematics data and refuelling data from a year of transport operations for all 41 CG trucks and 9 diesel trucks. The results show that for a tonne.km of in-service (mostly long haul) transport work, compared to the diesel trucks, the CG trucks spend on average 22% more energy and their fuel cost is 30% lower for biomethane. When running on CNG, their equivalent carbon emissions is 10% lower than the baseline diesel, and when running on biomethane, their equivalent carbon emissions is 78% lower. Compared to long haul, the benefits are lower for regional operations, and are the lowest for city centre operations where using CNG, the CG truck's equivalent carbon emissions is higher than the diesel truck. [ABSTRACT FROM AUTHOR]

• Reuse of oil and gas infrastructure could reduce the running costs of a carbon storage site. • Such a scheme would be far less costly than decommissioning and would help overcome the high costs of building a carbon storage site from scratch. • As the scheme dissolves CO 2 in brine before disposal, it is a secure way to ensure no leakage with the potential for monetizing the disposal of outside sources of CO 2. Co-production of methane and geothermal energy from produced subsurface brines with onsite power generation and carbon capture has been proposed as a technically feasible means to reduce the costs of offshore carbon storage sites. In such a facility, methane is degassed from produced brine, this brine is then cooled allowing the extraction of heat and then CO 2 is dissolved into it for reinjection into a porous rock formation. Once injected into the porous reservoir formation, this CO 2 -loaded brine will sink due to its relatively higher density, providing secure storage. Here, for the first time, we investigate, the economic feasibility and energy balance of such a system within the UK North Sea. We examine the suitability of a depleted hydrocarbon field coupled with a saline formation located in the Inner Moray Firth, Scotland. We find that such a system would be highly likely to have a positive energy balance, and would be an order of magnitude cheaper that decommissioning. Furthermore, as only 10% of the site's storage capacity is needed for disposal of the CO 2 emissions associated with its operation, there is significant potential for additional revenue creation from storing CO 2 from other sources. Whilst the chosen case study site was not ideal, due to its relatively shallow depth, and hence lower than ideal heat potential, it demonstrates that reuse of redundant oil & gas infrastructure that would otherwise be decommissioned could help to offset some of the financial barriers to developing a carbon storage industry in the UK North Sea. [ABSTRACT FROM AUTHOR]