Coal Bed Methane System Modeling - Reservoir, Wells and Surface Facilities

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Thermal effects on geologic carbon storage

The final publication is available at Springer via http://dx.doi.org/10.1016/j.earscirev.2016.12.011One of the most promising ways to significantly reduce greenhouse gases emissions, while carbon-free energy sources are developed, is Carbon Capture and Storage (CCS). Non-isothermal effects play a major role in all stages of CCS. In this paper, we review the literature on thermal effects related to CCS, which is receiving an increasing interest as a result of the awareness that the comprehension of non-isothermal processes is crucial for a successful deployment of CCS projects. We start by reviewing CO2 transport, which connects the regions where CO2 is captured with suitable geostorage sites. The optimal conditions for CO2 transport, both onshore (through pipelines) and offshore (through pipelines or ships), are such that CO2 stays in liquid state. To minimize costs, CO2 should ideally be injected at the wellhead in similar pressure and temperature conditions as it is delivered by transport. To optimize the injection conditions, coupled wellbore and reservoir simulators that solve the strongly non-linear problem of CO2 pressure, temperature and density within the wellbore and non-isothermal two-phase flow within the storage formation have been developed. CO2 in its way down the injection well heats up due to compression and friction at a lower rate than the geothermal gradient, and thus, reaches the storage formation at a lower temperature than that of the rock. Inside the storage formation, CO2 injection induces temperature changes due to the advection of the cool injected CO2, the Joule-Thomson cooling effect, endothermic water vaporization and exothermic CO2 dissolution. These thermal effects lead to thermo-hydro-mechanical-chemical coupled processes with non-trivial interpretations. These coupled processes also play a relevant role in “Utilization” options that may provide an added value to the injected CO2, such as Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM) and geothermal energy extraction combined with CO2 storage. If the injected CO2 leaks through faults, the caprock or wellbores, strong cooling will occur due to the expansion of CO2 as pressure decreases with depth. Finally, we conclude by identifying research gaps and challenges of thermal effects related to CCS.Peer ReviewedPostprint (author's final draft

Lowering the barriers to developing thermal renewable energy technologies

Impediments to investment in renewable energy resources arise in five areas, namely, infrastructure access, technological and resource uncertainty, competition from established fossil fuel alternatives, asset financing and public policy. Together these can lead to large capital cost penalties and poor resource productivity that reduce the viability of projects. Presented here are system-wide analyses of two novel pathways to generate new investment in concentrated solar thermal and in geothermal energy resources. The pathways are designed to reduce the minimum capital outlay required for the development of renewable energy resources, by identifying synergies with established energy and non-energy infrastructure and technologies. The endothermic, thermochemical processing of fossil, waste and biomass using concentrated solar energy has been demonstrated, at experimental scales between 3-500 kWth, to upgrade the calorific value of syngas relative to the feedstock by ~30%, depending on the reactor technology employed and the fuel that is processed. However, no process modeling analysis has previously been presented of the impacts of diurnal, seasonal and cloud-induced solar resource availability on the operational limits of commercially available Fischer-Tropsch (FT) liquids syngas processing infrastructure. Presented here, are process modeling analyses of the relative performance of two solar gasification reactor systems and the operational impacts of their integration with a coal-to-liquids polygeneration facility. The reactor designs assessed were the batch process, indirectly irradiated solar packed bed gasifier that operates with solar input alone and a hybridised configuration of the solar vortex reactor that is assumed to integrate combustion to account for solar resource transience and thus enable a continuous non-zero syngas throughput. To address the impacts of solar resource transience, the process modeling analyses showed that the packed bed solar reactor requires syngas storage equivalent to >30 days of gas flow to maintain feasible operation of unit operations downstream of the gasifier. In comparison, the hybrid solar vortex reactor was shown to require only ~8 hours of syngas storage. A dynamic process modeling study of integrating a hybrid solar vortex coal gasifier with a FT liquids polygeneration system was shown to improve the overall energetic productivity by 24% and to reduce mine-to-tank CO2 emissions by 28%. This is the first comprehensive system analysis of a solar hybridised coal-to-liquids process that has assessed all the impacts of solar resource transience on the unit operations that comprise a FT liquids polygeneration system. Geothermal resources can face barriers to investment arising from their remoteness—in particular, distance from established electricity transmission lines—uncertainty in the cost of establishing well infrastructure and uncertainty in the scale of the recoverable resource. To address these challenges, presented here is a comprehensive system evaluation of the potential of high-value energy load data-centres to reduce the cost of developing geothermal resources. This potential arises from the data-centres’ modularity, their stable load for both electricity and refrigeration, and because their energy demand can be scaled commensurate to geothermal resource availability. Moreover, they can be connected to market by fibre optic network infrastructure, which is at least two orders of magnitude less expensive than electricity transmission. System analyses of this concept showed that a hybrid energy system that integrates low-temperature geothermal resources to meet data-centres’ refrigeration load, and natural gas to meet the electrical load, could generate expected returns of 25% and reduce the cost of developing geothermal resources by >30 times. The systems modelled in this thesis have shown that, compared with stand-alone development, the hybridised development of renewable energy resources with fossil fuel energy technologies offers a lower cost pathway.Thesis (Ph.D.) (Research by Publication) -- University of Adelaide, School of Mechanical Engineering, 201

Ultra-lean methane combustion in porous burners

Ultra-lean methane combustion in porous burners is investigated by means of a pilot-scale demonstration of the technology supported by a computational fluid dynamics (CFD) modelling study. The suitability of porous burners as a lean-burn technology for the mitigation of methane emissions is also evaluated. Methane constitutes 14.3% of total global anthropogenic greenhouse gas emissions. The mitigation of these emissions could have a significant near-term effect on slowing global warming, and recovering and burning the methane would allow a wasted energy resource to be exploited. The typically low and fluctuating energy content of the emission streams makes combustion difficult; however porous burners—an advanced combustion technology capable of burning low-calorific value fuels below the conventional flammability limit—are a possible mitigation solution. A pilot-scale porous burner is designed expressly for the purpose of ultra-lean methane combustion. The burner comprises a cylindrical combustion chamber filled with a porous bed of alumina saddles, combined with an arrangement of heat exchanger tubes for preheating the incoming methane/air mixture. A CFD model is developed to aid in the design process. Results illustrating the operating range and behaviour of the burner are presented. Running on natural gas, the stable lean flammability limit of the system is 2.3 vol%, a considerable extension of the conventional lean limit of 4.3 vol%; operating in the transient combustion regime allows the lean limit to be reduced further still, to 1.1 vol%. The heat exchanger arrangement is found to be effective; preheat temperatures of up to 800K are recorded. Emissions of carbon monoxide and unburned hydrocarbons are negligible. The process appears stable to fluctuations in fuel concentration and flow rate, typically taking several hours to react to any changes. A CFD model of the porous burner is developed based on the commercial CFD code ANSYS CFX 12.0. The burner is modelled as a single 1-dimensional porous domain. Pressure loss due to the presence of the porous solid is accounted for using an isotropic loss model. Separate energy equations for the gas and solid phases are applied. Models for conductive heat transfer within the solid phase, and for convective heat transport between the gas and solid phases, are added. Combustion is modelled using a finite rate chemistry model; a skeletal mechanism for ultra-lean methane combustion is developed and incorporated into the model to describe the combustion reaction. Results from the model are presented and validated against experimental data; the model correctly predicts the main features of burner behaviour. Porous burners are found to show potential as a methane mitigation technology

Ultra-lean methane combustion in porous burners

Ultra-lean methane combustion in porous burners is investigated by means of a pilot-scale demonstration of the technology supported by a computational fluid dynamics (CFD) modelling study. The suitability of porous burners as a lean-burn technology for the mitigation of methane emissions is also evaluated. Methane constitutes 14.3% of total global anthropogenic greenhouse gas emissions. The mitigation of these emissions could have a significant near-term effect on slowing global warming, and recovering and burning the methane would allow a wasted energy resource to be exploited. The typically low and fluctuating energy content of the emission streams makes combustion difficult; however porous burners—an advanced combustion technology capable of burning low-calorific value fuels below the conventional flammability limit—are a possible mitigation solution. A pilot-scale porous burner is designed expressly for the purpose of ultra-lean methane combustion. The burner comprises a cylindrical combustion chamber filled with a porous bed of alumina saddles, combined with an arrangement of heat exchanger tubes for preheating the incoming methane/air mixture. A CFD model is developed to aid in the design process. Results illustrating the operating range and behaviour of the burner are presented. Running on natural gas, the stable lean flammability limit of the system is 2.3 vol%, a considerable extension of the conventional lean limit of 4.3 vol%; operating in the transient combustion regime allows the lean limit to be reduced further still, to 1.1 vol%. The heat exchanger arrangement is found to be effective; preheat temperatures of up to 800K are recorded. Emissions of carbon monoxide and unburned hydrocarbons are negligible. The process appears stable to fluctuations in fuel concentration and flow rate, typically taking several hours to react to any changes. A CFD model of the porous burner is developed based on the commercial CFD code ANSYS CFX 12.0. The burner is modelled as a single 1-dimensional porous domain. Pressure loss due to the presence of the porous solid is accounted for using an isotropic loss model. Separate energy equations for the gas and solid phases are applied. Models for conductive heat transfer within the solid phase, and for convective heat transport between the gas and solid phases, are added. Combustion is modelled using a finite rate chemistry model; a skeletal mechanism for ultra-lean methane combustion is developed and incorporated into the model to describe the combustion reaction. Results from the model are presented and validated against experimental data; the model correctly predicts the main features of burner behaviour. Porous burners are found to show potential as a methane mitigation technology

Investigation of feasibility of injecting power plant waste gases for enhanced coalbed methane recovery from low rank coals in Texas

Greenhouse gases such as carbon dioxide (CO2) may be to blame for a gradual rise in the average global temperature. The state of Texas emits more CO2 than any other state in the U.S., and a large fraction of emissions are from point sources such as power plants. CO2 emissions can be offset by sequestration of produced CO2 in natural reservoirs such as coal seams, which may initially contain methane. Production of coalbed methane can be enhanced through CO2 injection, providing an opportunity to offset the rather high cost of sequestration. Texas has large coal resources. Although they have been studied there is not enough information available on these coals to reliably predict coalbed methane production and CO2 sequestration potential. The goal of the work was to determine if sequestration of CO2 in low rank coals is an economically feasible option for CO2 emissions reduction. Additionally, reasonable CO2 injection and methane production rates were to be estimated, and the importance of different reservoir parameters investigated. A data set was compiled for use in simulating the injection of CO2 for enhanced coalbed methane production from Texas coals. Simulation showed that Texas coals could potentially produce commercial volumes of methane if production is enhanced by CO2 injection. The efficiency of the CO2 in sweeping the methane from the reservoir is very high, resulting in high recovery factors and CO2 storage. The simulation work also showed that certain reservoir parameters, such as Langmuir volumes for CO2 and methane, coal seam permeability, and Langmuir pressure, need to be determined more accurately. An economic model of Texas coalbed methane operations was built. Production and injection activities were consistent with simulation results. The economic model showed that CO2 sequestration for enhanced coalbed methane recovery is not commercially feasible at this time because of the extremely high cost of separating, capturing, and compressing the CO2. However, should government mandated carbon sequestration credits or a CO2 emissions tax on the order of $10/ton become a reality, CO2 sequestration projects could become economic at gas prices of$4/Mscf

The combustion mitigation of methane as a non-CO2 greenhouse gas

These research results have received funding from the EU H2020 Programme (No. 689772) and from MCTI/RNP-Brazil under the HPC4E Project, grant agreement no 689772

Energy: A continuing bibliography with indexes, issue 20

A bibliography is presented which lists 1250 reports, articles, and other documents introduced into the NASA Scientific and Technical Information System from October 1, 1978 through December 31, 1978