Methane is emitted from oil and gas operations alongside heavier hydrocarbons and non-hydrocarbon gases, shaping emissions management decision-making, including air quality impacts. Yet, most assessments assume fixed gas composition, overlooking significant spatial and temporal variations. Here, we generate a high-resolution, data-driven map of natural gas composition across the United States, reconstructing methane, heavier hydrocarbons, and non-hydrocarbon species using spatio-temporal interpolation and oil-and-gas production patterns. Our approach is able to reduce composition prediction errors by 39% in terms of Mean Absolute Error (MAE) compared to standard techniques and reveals that methane loss rates have been underestimated by more than 50% in some regions. Beyond methane, we uncover substantial variability in co-emitted gases, exposing blind spots in current emissions inventories and emissions management frameworks. Our work enables more accurate emissions assessments, guides targeted measurement strategies, and informs emissions management decision-making. It also provides a general framework for prediction in environmental applications that integrate sparse measurements with auxiliary variables.

The Lower Cambrian shale gas resources in southern Chinahave hugepotential. However, the reservoirs generally contain a relativelyhigh content of nonhydrocarbon gases, which has a significant impacton the exploration and development of shale gas. The source of nonhydrocarbongases in the Lower Cambrian shales has become a research hotspot.Based on recently published data, this paper systematically summarizesthe geological and distribution characteristics, gas-bearing properties,and genesis mechanism of Lower Cambrian shale gas in southern China.The Lower Cambrian shales in southern China are widely distributedin the Yangtze Platform. The overall total organic carbon (TOC) contentis relatively high. The kerogen type is mainly type I, and the equivalentvitrinite reflectance (EqRo) value ranges from 2.5 to 6.0%. The mineralcomponents of the Lower Cambrian shales are mainly quartz, clay minerals,and carbonate minerals, and the main lithofacies types are mainlysiliceous shale and mixed (siliceous-clay) shale. The gas-in-place(GIP) content of the Lower Cambrian shales varies greatly in differentregions. Currently, shale gas, mainly composed of CH4,has only been discovered in the southwestern Sichuan, western Hubei,northeastern Chongqing, and northern Guizhou areas, while in otherYangtze regions, the GIP content of shales is very low or almost nonexistent.The distribution of δ13C1, δ13C2, and δ13C3 in theLower Cambrian shale gas shows a significant inversion. Among thenonhydrocarbon gases, N2 mainly originates from atmosphericand/or pyrolysis, CO2 is mainly of organic origin, whileHe exhibits typical shell-source characteristics, which may be fromthe ancient basement and/or the radioactive decay accumulation ofU and Th in the shale. On this basis, an evolution model of the LowerCambrian shale gas was constructed. Hydrocarbon generation in theLower Cambrian shales can continue until EqRo = 3.5%, after whichN2 is mainly produced. CO2 is mainly formedin the low mature stage, and the He content shows continuous generationthroughout the shale evolution process.

The shale gas content of the Longmaxi Formation exhibits significant spatial variation in different structural parts of the Sangzhi area in Hubei Province, reflecting differences in preservation conditions. To quantitatively evaluate these conditions, this study integrates analyses of structural features, fault distribution, formation water chemistry, and shale gas composition from four wells. Results show that preservation is primarily controlled by the F1 and F3 faults. Wells distant from these faults (SY3 and SY5) display weak connectivity with surface water, feature CaCl2-type formation water with high salinity and diagnostic ion coefficients, and contain hydrocarbon gases derived from organic pyrolysis. These characteristics lead to high gas content and favorable preservation conditions. In contrast, wells adjacent to faults (SY1 and SY6) exhibit strong connectivity with the surface, NaHCO3-type water of low salinity, high N2 and CO2} contents of atmospheric origin, and low gas content, indicating poor preservation. These findings demonstrate that shale gas preservation in the Longmaxi Formation is jointly controlled by structural settings, water--rock interactions, and nonhydrocarbon gas sources, providing a quantitative framework for assessing preservation conditions in shale gas exploration.

Nonhydrocarbon gases are significant components of natural gas, and their concentration levels are crucial factors affecting reservoir development value. While explorations have progressively moved from shallow to deep and now ultradeep reservoirs, research on the geochemical characteristics of nonhydrocarbon gases in such extreme depths remains limited, leaving their origins and types poorly understood. This paper analyzes the geochemical characteristics and origins of ultradeep nonhydrocarbon gases (CO 2 , H 2 S, N 2 , He, and H 2 ) across major global basins to determine their origins. CO 2 concentrations reach up to ~40% but are generally below ~15%. The concentration increases with depth, primarily due to inorganic origins, with thermochemical sulfate reduction (TSR) and magmatic CO 2 being the main causes. Depths are mainly between 6000 and 7100 m. N 2 concentrations peak at ~26% but are generally below ~6%. It mainly originates from crustal sources and the high‐temperature cracking of sedimentary organic matter during postmature. Depths are mainly between 6000 and 7100 m. H 2 concentrations reach up to ~1.6% but are generally below ~0.2%. It is concentrated at depths between 7100 and 7800 m and may primarily have a biological origin. He concentrations are generally below ~0.07% and are mainly found at depths between 6000 and 7700 m. The concentrations fall well short of the commercial threshold (0.1%), indicating limited potential for He enrichment in ultradeep reservoirs. H 2 S concentrations reach up to 46% but are generally below 10%. The concentration slightly increases with depth, mainly due to TSR processes. Depths are primarily between 6000 and ~7600 m. Understanding these common and varying patterns of nonhydrocarbon gases may provide theoretical guidance for future exploration targets in ultradeep nonhydrocarbon gases like He and H 2 .

Experimental investigation of the adsorption potential of pomegranate peel for hydrocarbon and non-hydrocarbon gases

Abstract Rare gas helium is widely used in industrial and high-tech areas, is the national important strategic resources, to lead the scientific and technological innovation has the increasingly important role, helium production capacity in China is relatively scarce, helium gas resources long-term dependence on imports. In order to strengthen the helium resource guarantee capacity of our country and ensure the advantageous position in the international development competition. In recent years, helium detection and analysis in real-time while drilling at wellsite has been gaining interest in the oil and gas industry, the detection of non-hydrocarbon gases such as helium has become the focus of current exploration. In order to meet the demand of hydrogen and helium exploration and development, a set of hydrogen-helium chromatography analyzers is developed. A separation method of helium and hydrogen combined with the pre-analysis column and the main analysis column is proposed to realize the efficient separation of hydrogen and helium, the wide spectrum TCD (Thermal Conductivity Detector) is used as the analyzer to achieve the high efficiency detection of hydrogen and helium. Field application shows that the system can detect hydrogen and helium efficiently within 30 seconds analysis cycle while drilling, which provides a technical means for the detection of hydrogen and helium in the exploration process. It provides a good technical reserve for the future large-scale development and utilization of natural hydrogen and helium.

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ13C1, δ13C2 and δ13C3 values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO2 in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH4) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH4 from highly evolved, underlying coal-bearing source rocks. Consequently, the CH4 content in the mixed gas is generally high (Ln (C1/C2) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area.

Helium resources accumulation regulations and their development prospects in China

Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the interface of the bit and rock due to the overheating of the bit. The heat generated by the drill when drilling into a rock formation promotes the generation of artificial hydrocarbon and non-hydrocarbon gas, changing the composition of the gas. The objective of this work is to recognize and evaluate artificial gases originating from DBM in wells targeting oil accumulations in pre-salt carbonates in the Santos Basin, Brazil. For the evaluation, chromatographic data from advanced mud gas equipment, drilling parameters, drill type, and lithology were used. The molar concentrations of gases and gas ratios (especially ethene/ethene+ethane and dryness) were analyzed, which identified the occurrence of DBM. DBM is most severe when wells penetrate igneous and carbonate rocks with diamond-impregnated drill bits. The rate of penetration, weight on bit, and rotation per minute were evaluated together with gas data but did not present good correlations to assist in identifying DBM. The depth intervals over which artificial gases formed during DBM are recognized should not be used to infer pay zones or predict the composition and properties of reservoir fluids because the gas composition is completely changed.

Energy from Earth resources (geoenergy) in the form of coal, oil and gas has fuelled the global society since the Industrial Revolution began. Amongst the consequences of fuelling society and associated population growth, is climate change, driven by the emission of greenhouse gases liberated through unabated combustion of fossil fuels. There is much more to Earth energy systems, however, than just coal oil and gas. The Earth contains, in human terms, an unlimited supply of accessible heat and pressure (differences), as well as copious quantities of storage space, non-hydrocarbon gases and valuable solutes. These resources can be targeted to provide sustainable energy sources with low to zero carbon footprints. This report does not contain any new radical technologies that will deliver energy free from all environmental impacts but it does show that, when considering geoenergy, society needs to look at the whole system, which combines chemical, thermal, potential, kinetic, gravitational and other energy forms that could be used from individual developments to minimize waste, maximize efficiency and reduce unwanted impacts. We demonstrate that geoenergy will continue to play a key role in decarbonized energy systems for centuries to come.

Prerequisites for the study are selection of the optimal agent to maintain reservoir pressure and setting the optimal conditions under which the maximum condensate recovery factor is achieved. The aim of the article is to assess the technological efficiency of methods for increasing condensate recovery while maintaining reservoir pressure by injecting hydrocarbon (methane) and non-hydrocarbon (nitrogen, carbon dioxide) gases. The subject of this study is the Ach3-4 reservoir within the Novo-Urengoyskoye license area of the Urengoy field. The most effective methodology for identifying the stated issue is the outcome of hydrodynamic calculations conducted on a composite hydrodynamic model implemented in ECLIPSE 300 format. In order to model one of the sections of the Ach3-4 reservoir, a development element was selected in which the average parameters corresponded to those of the full-scale model. The efficiency of the selected methods was evaluated by comparing them with the baseline scenario, which represents the conventional approach to the development of the Ach3-4 reservoir on depletion. The injection start was set in a dynamic model after removal of 30, 50 and 85 % of gas initially in-place and at a steady pressure of 18, 37 and 40 MPa, provided that gas recovery factor was achieved on depletion. The technological efficiency of the development options was evaluated by examining the dynamics of the condensate recovery factor in relation to the dynamics of the gas recovery factor. The optimal option was identified based on the maximum value of the condensate recovery factor. The results of the studies conducted to increase condensate recovery from reservoirs indicate the effectiveness of using carbon dioxide as an agent. The condensate recovery factor depends on the ratio of injection and production wells, the time of the start of reservoir pressure maintenance and the number of pore volumes pumped. The efficiency of carbon dioxide injection at late stages of development increases dramatically when the minimum mixing pressure is reached.

Partial upgrading of bitumen with supercritical water— liquid products characteristics, gas composition and coke morphology

Chemical characterization of refuse derived fuel (RDF) using Py-GC/MS

A significant amount of natural gas resources has been discovered in the Ordovician reservoirs under a thick layer of gypsum-salt strata as a result of ongoing research into deep natural gas in China’s Ordos Basin, however, the genetic type and source of the Ordovician sub-salt natural gas remain contentious. These limits understanding how the geochemical properties of the natural gas in Ordos Basin have evolved and how to best guide future exploration and development. Based on the components, carbon and hydrogen isotopic ratios of natural gas from the latest exploration wells, combined with the geological background, this study systematically analyzed the genetic types and sources of sub-salt natural gas of the central and eastern Ordos Basin. The results show that the Ordovician natural gas is mainly composed of hydrocarbon gases with low content of heavy hydrocarbons and dryness (CCH4/CCH4+) above 0.95, belonging to typical dry gas. Non-hydrocarbon gases mainly include N2 and CO2, and some natural gas samples contained H2S. The Ordovician sub-salt natural gas is primarily a self-generating and self-preserving oil-cracking gas with relatively high maturity (Ro ranging from 1.5% to 2.1%) mixed with coal-derived gas generated from upper-Paleozoic coal with relatively low maturity (Ro ranging from 1.1% to 1.5%). Due to the dual-source hydrocarbon supply, the Ordovician sub-salt reservoirs provide favorable gas accumulation conditions and development prospects. This study offers a reasonable explanation for the anomalous geochemical characteristics of the Ordovician sub-salt reservoirs in the Ordos Basin, and also may serve as a guide for future exploration of natural gas in the carbonate gypsum-salt sedimentary system in other basins.

Genesis and source of natural gas in Well Mitan-1 of Ordovician Majiagou Formation, middle-eastern Ordos Basin, China

It is important to study the control mechanism of geological factors (coal bed structure and hydrodynamics) on the evolution of coalbed methane (CBM) gas components. In this paper, the tectonic, hydrochemical, and hydrodynamic field distributions in the Daning-Jixian block, the eastern edge of the Ordos Basin, were obtained by using well logging, seismic, and water sample testing data. The CBM origin was obtained by analyzing methane carbon isotope abundance (δ13C1) in gas sample tests. The results show that (1) the 5# coal seam in the study area is a monoclinic structure with deeper burial in the northwest and shallower burial in the southeast, and the direction of groundwater transportation is consistent with the slope direction of the terrain; (2) CBM in the study area is thermogenic gas and undergoes diffusion, dissolution, and transportation processes. As the hydrodynamics changed from high to low, the percentage of CH4 concentration increased, the percentage of CO2 and N2 composition decreased, pH became smaller, total dissolved solid increased, and δ13C1 became heavier; (3) at the early stage of drainage mining, δ13C1 increased significantly, the CH4 component showed a decreasing trend, and nonhydrocarbon gas components increased. As the discharge mining proceeds, the CH4 component tends to increase and the nonhydrocarbon gas components decreases.

Summary As the exploration of the South China Sea continues into deeper water, the chances of encountering nonhydrocarbon gas (CO2, N2, etc.) reservoirs rise. The question of how to avoid the risks associated with the discovery of nonhydrocarbon gas reservoirs becomes an issue for deepwater (DW) oil and gas exploration. Geomicrobial hydrocarbon detection (GMHD) is a nonseismic hydrocarbon detection technology that is able to predict the hydrocarbon potential of a prospective area at depth. This is accomplished via the detection of specific hydrocarbon-oxidizing bacteria in both onshore soils and offshore sea bottom sediment samples. The effectiveness of this method has been proved repeatedly in DW explorations of the northern South China Sea. It documents a possible solution to nonhydrocarbon gas risk prediction by combining the oil and gas prediction results of geomicrobial hydrocarbon detection with results from geological and geophysical studies to analyze the different microbial responses above nonhydrocarbon gas and hydrocarbon gas reservoirs. This was verified in the DW exploration practices undertaken in the Pearl River Mouth Basin and Qiongdongnan Basin of South China Sea.

Geochemistry and origins of hydrogen-containing natural gases in deep Songliao Basin, China: Insights from continental scientific drilling

In designing pipeline facilities for production and transportation of oil, hydrocarbon gases or non-hydrocarbon gases – CO2 and H2 , consideration is given to pipeline integrity, flow assurance, operation and health/safety issues. Erosion-corrosion of the inner pipeline wall and/or high-pressure losses is of great concern. For many years now, many oil and gas field operators have adopted the America Petroleum Institute recommended practice 14E (API RP 14E) equation to estimate the erosional velocity. Unfortunately, the C-factor (which is an empirical constant) in the API RP 14E equation has been generalized to all field conditions. In addition, there is no concrete scientific evidence behind the basis of its formulation, and various values have been adopted based on field and laboratory experiences. In this work, we present how oil and gas companies could formulate safer erosional velocity models for their sand free or ‘clean service’ pipelines, based on the velocities calculated for the equilibrium flow rate (that is, the intersection of vertical lift performance (VLP) and inflow performance relationship (IPR)). The developed erosional velocity models can be applied, and compared with in-house correlations, for erosional velocity predictions

Geochemical parameters of thermal simulation of gas generation on lacustrine Type II shales in semi-open pyrolysis system