Energy analysis on Coalbed Methane (CBM) coupled power systems

This study presents a performance prediction of triple combined cycles that use a solid oxide fuel cell (SOFC) and a gas turbine combined cycle (GTCC) with carbon capture technologies. Post- and oxy-combustion capture technologies were comparatively analyzed. The component design parameters of a commercial F-class gas turbine and SOFC were used. Minimizing the turbine inlet temperature (i.e., no extra fuel supplied to the combustor) resulted in higher net cycle efficiency. With post-combustion capture, the net cycle efficiency reached approximately 70 % when no fuel was supplied to the combustor, but the maximum CO2 capture rate was limited to 80 %. When a dual combined cycle was adopted, the CO2 capture rate increased to 91 %, while the net efficiency was approximately 69 %. With oxy-combustion capture, the optimum pressure ratio was higher than in the normal triple combined cycle, and the net cycle efficiency was lower than that of the post-combustion cycle. However, there was a critical advantage of a larger power output with nearly complete carbon capture. The impact of the location of the oxygen supply was examined in the oxy-combustion cycle with extra fuel supplied to the combustor, and supplying all the fuel to the SOFC improved the cycle performance.

Coal Bed Methane (CBM) gas is formed and trapped within coal seams, offering significant economic potential as it can be converted into electricity or transported through pipelines for various purposes. Indonesia is estimated to have approximately 574 trillion cubic feet (TCF) of CBM gas reserves, capable of meeting domestic energy needs. South Sumatera is classified as a province with the largest coal reserves in Indonesia, indicating abundant potential for CBM gas resources. This research aims to identify potential CBM indicators based on structural lineament interpretation using DEMNAS data. Field research was conducted to gather necessary data, and the findings from the study indicate that the surveyed area has a high potential for Coal Bed Methane (CBM) due to the high lineament density, ranging from 570/km2 to 710/km2 indicating high permeability that supports the well development of CBM gas. Optimal permeability can enhance the quantity of trapped Coal Bed Methane (CBM) gas, given the available space for the gas.

Advanced bibliometric analysis on the development of natural gas combined cycle power plant with CO2 capture and storage technology

Hydrogen is expected to play an important role in renewable power storage and the decarbonization of the power sector. In order to clarify the environmental impacts of power regenerated through hydrogen-fueled gas turbines, this work details a life cycle model of the greenhouse gas (GHG) and NOx emissions of the power regenerated by power-to-H2-to-power (PHP) technology integrated with a combined cycle gas turbine (CCGT). This work evaluates the influences of several variables on the life cycle of GHG and NOx emissions, including renewable power sources, hydrogen production efficiency, net CCGT efficiency, equivalent operating hours (EOH), and plant scale. The results show that renewable power sources, net CCGT efficiency, and hydrogen production efficiency are the dominant variables, while EOH and plant scale are the minor factors. The results point out the direction for performance improvement in the future. This work also quantifies the life cycle of GHG and NOx emissions of power regenerated under current and future scenarios. For hydro, photovoltaic (PV) and wind power, the life cycle of the GHG emissions of regenerated power varies from 8.8 to 366.1 gCO2e/kWh and that of NOx emissions varies from 0.06 to 2.29 g/kWh. The power regenerated from hydro and wind power always has significant advantages over coal and gas power in terms of GHG and NOx emissions. The power regenerated from PV power has a small advantage over gas power in terms of GHG emissions, but does not have advantages regarding NOx emissions. Preference should be given to storing hydro and wind power, followed by PV power. For biomass power with or without CO2 capture and storage (CCS), the life cycle of the GHG emissions of regenerated power ranges from 555.2 to 653.5 and from −2385.0 to −1814.4, respectively, in gCO2e/kWh; meanwhile, the life cycle of NOx emissions ranges from 1.61 to 4.65 g/kWh, being greater than that of coal and gas power. Biomass power with CCS is the only power resource that can achieve a negative life cycle for GHG emissions. This work reveals that hydrogen-fueled gas turbines are an important, environmentally friendly technology. It also helps in decision making for grid operation and management.

Unconventional gas resources, including a large proportion of coal bed methane (CBM) and tight sandstone gas, are abundant in China. Presently, there is an issue of low production and high cost in single-layer mining of CBM and tight sandstone gas. Co-mining of CBM and tight sandstone gas has received extensive attention. Studies on co-mining are still in the field test stage, lack theoretical support, and require further study. Based on reservoir geologic conditions in the Linfen block, a non-channeling geological model for tight sandstone and coal seam is established using Eclipse to perform a numerical simulation of co-mining and simulate the effects of different parameters. Effects of permeability, porosity, reservoir thickness, water saturation, and Langmuir Volume on the contribution of gas production to different production layers were analyzed. A comprehensive evaluation index is established and used to judge the co-mining feasibility of 14 wells (J-1 to J-14) in the No. 8 coal seam and adjacent sandstone layers in the Linfen block. Results show that with increasing ratio of permeability, ratio of porosity, and ratio of reservoir thickness (sandstone/coal), the accumulative gas contribution rate of sandstone for 20 years increases gradually. With increasing water saturation in sandstone and increasing Langmuir Volume in the coal seam, the accumulative gas contribution rate of sandstone for 20 years gradually decreases. The Linfen block has favorable strata characteristics for co-mining, well J-1, well J-3, well J-4, well J-8, well J-9, well J-10, well J-12, and well J-13 in No. 8 coal seam are suitable for co-mining. Wells J-2, J-5, J-6, J-7, J-11, and J-14 are suitable for single mining.

Heat integration of natural gas combined cycle power plant integrated with post-combustion CO2 capture and compression

The geological structure is complex in the plate margin zone, and the occurrence of coal bed methane (CBM) is nonuniform with an obvious zoning phenomenon. It plays an important role to reveal the spatial distribution of CBM and its influence factors in plate margin zone for CBM exploitation and gas disaster prevention in coal mines. Based on the data of gas emission during mining, CBM content, and gas pressure in the Pingdingshan Coalfield, lying on the south edge of North China plate, the distribution characteristics of CBM and its influence factors using theories of CBM (gas) geology and statistical analysis method are investigated. The research area is divided into four CBM occurrence belts. There are its own CBM occurrence feature and control structural type in each CBM belt. Likou syncline is the structure that controls the overall distribution of CBM. NW‐trending fold‐fault belt, Guodishan fault, and Jiaxian fault are the structures that control the CBM occurrence in CBM belt IV, CBM belt II, and CBM belt I, respectively. And the difference in structural types is the main factor of CBM zoning.

Preliminary Understanding of CO2 Sequestration and Enhanced Methane Recovery in Raniganj Coalfield of India by Reservoir Simulation

Gastric HGD in FAP may be more common than previously appreciated. The natural history of HGD is variable, and most patients with HGD do not appear to progress to GC.

Gas consumption in India has grown at an annual rate of 10% from 2001–2011. To meet an increase in gas demand, India needs to develop unconventional gas resources like coal bed methane (CBM) and shale gas. India has 91 trillion cubic feet (Tcf) of CBM resource. To develop CBM resource in India, CBM policy was frame in 1997 and first round of bidding took place in 2001. Till the end of round-IV of CBM bidding, Government of India awarded 33 CBM blocks to public and private industries. The prognosticated CBM resource for the awarded 33 CBM blocks is about 52 Tcf. Commercial CBM production has started from Raniganj (South) block since 14July 2007 which now contributes 7.7 million standard cubic feet per day (MMscfd). In this study, the commercially successful global CBM basins have analyzed to understand important parameters for CBM productivity. Indian CBM blocks compared with commercially successful global CBM basins for depth, thickness and gas content. Study shows good CBM production potential in Indian CBM blocks. Technical, regulatory, environment and infrastructural aspects for CBM development in India is discussed. Keywords: India, coal bed methane, CBM basins, production, resource

The coalbed methane industry has become an important source of natural gas production. Proper dewatering of coalbed methane (CBM) wells is the key to efficient gas production from these reservoirs. This paper presents the Hydraulic Gas Pump as a new alternative dewatering system for CBM wells. The Hydraulic Gas Pump (HGP) concept offers several operational advantages for CBM wells. Gas interference does not affect its operation. It resists solids damage by eliminating the lift mechanism and reducing the number of moving parts. The HGP has a flexible production rate and is suitable for all production phases of CBM wells. It can also be designed as a wireline retrievable system. We conclude that the Hydraulic Gas Pump is a suitable dewatering system for coalbed methane wells.

Carbon capture and geological storage (CCS) is a core element in the global strategy to reduce greenhouse gas (GHG) emissions. This paper characterizes and contrasts the emission quantification methods associated with CCS projects from the perspective of voluntary emission reduction initiatives and recent regulatory reporting requirements under the U.S. Environmental Protection Agency (EPA) Greenhouse Gas Reporting Program (GHGRP). From the regulatory perspective, the U.S. EPA is addressing the mandatory GHG reporting for CO2 injection and potential geological storage, providing a different approach for facilities that supply CO2 to the market, those that inject CO2 for purposes of enhanced oil and gas recovery, and those that are engaging in long-term geological storage. Information gathered under the GHGRP will enable EPA to track the amount of CO2 supplied to the market, injected, and/or stored by U.S. facilities. In addition, where the CO2 injection facilities are also associated with other oil and gas operations, the GHGRP requires quantifying and reporting GHG emissions from those operations where the facilities meet specified regulatory thresholds. This information will be a key element in providing baseline data and activity information for the development of future emission standards and control techniques for GHG emission mitigation in the U.S. In addition to reporting initiatives, industry is providing guidance to support voluntary GHG reduction initiatives. The American Petroleum Institute (API) and the International Petroleum Industry Environmental Conservation Association (IPIECA) have collaborated on a guideline document to promote the credible, consistent, and transparent quantification of GHG emission reductions from CCS projects (IPIECA/API, 2007). This document emphasizes that the entire range of activities associated with CCS - capture, transport, injection and storage - must be considered in quantifying emissions and emission reductions from CCS operations. This paper will examine common aspects and notable differences between the mandatory reporting programs and voluntary GHG emission reduction activities. It will specifically emphasize collateral characteristics such as the scope of emission sources, accuracy of quantification methods, reporting and monitoring requirements. Introduction to CCS CCS applies established technologies to capture, transport and store CO2 emissions from large point sources. Wide deployment of CCS techniques is viewed as essential for addressing climate change, while also providing energy security, creating jobs, and economic prosperity. The International Energy Agency (IEA) states that CCS could reduce global CO2 emissions by 19%, and that without CCS, overall costs to reduce emissions to 2005 levels by 2050 would increase by 70% (IEA, 2009). CCS refers to the chain of processes that are designed to collect or capture a CO2 gas stream, transport the CO2 to a storage location, and inject the CO2 into a geological formation1 for long-term isolation from the atmosphere (See Figure 1). CCS involves avoiding the release of CO2 emissions to the atmosphere by injecting CO2 and ultimately storing it in a geological formation. The assessment of GHG emission reductions from CCS projects should address all of these elements.

Postcombustion CO2 capture from natural gas combined cycle (NGCC) power plants is challenging due to the large flow of flue gas with low CO2 content (∼3–4 vol %) that needs to be processed in the capture stage. A number of alternatives have been proposed to solve this issue and reduce the costs of the associated CO2 capture plant. This work focuses on the selective exhaust gas recirculation (S-EGR) configuration, which uses a membrane to selectively recirculate CO2 back to the inlet of the compressor of the turbine, thereby greatly increasing the CO2 content of the flue gas sent to the capture system. For this purpose, a parallel S-EGR NGCC system (53% S-EGR ratio) coupled to an amine capture plant (ACP) using monoethanolamine (MEA) 30 wt % was simulated using gCCS (gPROMS). It was benchmarked against an unabated NGCC system, a conventional NGCC coupled with an ACP (NGCC + carbon capture and storage (CCS)), and an EGR NGCC power plant (39% EGR ratio) using amine scrubbing as the downstream capture technology. The results obtained indicate that the net power efficiency of the parallel S-EGR system can be up to 49.3% depending on the specific consumption of the auxiliary S-EGR systems, compared to the 49.0% and 49.8% values obtained for the NGCC + CCS and EGR systems, respectively. A preliminary economic study was also carried out to quantify the potential of the parallel S-EGR configuration. This high-level analysis shows that the cost of electricity (COE) for the parallel S-EGR system varies from 82.1 to 90.0 $/MWhe for the scenarios considered, with the cost of CO2 avoided (COA) being in the range of 79.7–105.1 $/ton CO2. The results obtained indicate that there are potential advantages of the parallel S-EGR system in comparison to the NGCC + CCS configuration in some scenarios. However, further benefits with respect to the EGR configuration will depend on future advancements and cost reductions achieved on membrane-based systems.

Methane gas obtained from coal sources can be classified into two categories i.e Coal Bed Methane (CBM) and Underground Coal Gasification (UCG) gases. The Industry today often neglects the importance of capturing the UCG as important source of methane potential besides the surface gasification potential. This research will evaluate on the new resource estimation of methane as reserves with application of new technological advances in exploitation. As an analysis, the UCG energy return is significantly higher than that of CBM. Both CBM and UCG output gas can be liquefied, or used as a direct feedstock to local power stations. The CO2 generated from UCG process may be used for Enhanced Coal Bed Methane (ECBM) process because of more adsorption capacity than methane, may lead to additional methane potential. Deeper coal seams may be targeted for CBM, followed by UCG for additional resources in the form of coal gas. A depleted CBM area may be targeted for UCG with some modification on the well profile. Developing an integrated and centrally controlled approach to exploit the coal resources in which, the appropriate extraction methodology should be identified for each particular target coal-seam or groups of coal seam. It is important to strategize the sequencing of energy extraction methods to provide an optimal balance between the energy delivery for sustainable future and its true socio-economic value. As from this analysis, with 245.6 acres of coal, estimated gas can be produced is 3.25 TSCF which is 101 BSCF is coming from CBM, 3.14 TSCF from UCG and another 14.45 BSCF is from ECBM.

Nowadays the energy demand has become tripled resulting in advancingof the development activities in the petroleum industry to enhance hydrocarbon recoveries. It is reviewed from the literature that the current worldwide facts of research and technical observations have proved that the coal containing methane gas is not much efficient in terms of power, cost and environment friendly energy source. The objective of this research is to determine the technical and economic feasibility of carbon dioxide (CO2) and nitrogen gas (N2). Moreover, sequestration in coal seams and their environmental consequences for coal based methane recovery project. This research study is also covers the effective and efficient methodologyforextraction of methane gas from coal, which is coupled with the injection of CO2 and N2 into the coal seam complex structure. Moreover, this methodology is applied individually and simultaneously, along with the after effects of injection of CO2 and N2 on Coal bed methane (CBM) recovery. The results of this research study suggestsa method for generation of electric power in which CBM gas is used as an input source whilst the combustion gas, CO2 emissions are sequestrated into coal seams for environmental protection, extending the CBM recovery and reducing CO2 availability cost.