Total Gas Content Research Articles

Gas Migration Patterns with Different Borehole Sizes in Underground Coal Seams: Numerical Simulations and Field Observations

Gas flow in a coal seam is a complex process due to the complicated coal structure and the sorption characteristics of coal to adsorbable gas (such as carbon dioxide and methane). It is essential to understand the gas migration patterns for different fields of engineering, such as CBM exploitation, underground coal mine gas drainage, and CO2 geo-sequestration. Many factors influence gas migration patterns. From the surface production wells, the in-seam patterns of gas content cannot be quantified, and it is difficult to predict the total gas production time. In order to understand the gas flow patterns during gas recovery and the gas content variations with respect to production time, a solid-fluid coupled gas migration model is proposed to illustrate the gas flow in a coal seam. Field data was collected and simulation parameters were obtained. Based on this model, different scenarios with different borehole sizes were simulated for both directional boreholes and normal parallel boreholes in coal seams. Specifically, the borehole sizes for the directional boreholes were 10 m, 15 m, and 20 m. The borehole sizes for the normal parallel boreholes were 2 m, 4 m, and 6 m. Under different gas drainage leading times, the total gas recovery and residual gas contents were quantified. In Longwall Panel 909 of the Wuhushan coal mine, one gas drainage borehole and five 4 m monitoring boreholes were drilled. After six months of monitoring, the residual gas content was obtained and compared with the simulation results. Of the total gas, 61.36% was drained out from the first 4 m borehole. In this field study, the effective drainage diameter of the drainage borehole was less than 8 m after six months of drainage. The gas drainage performance was tightly affected by the borehole size and the gas drainage time. It was determined that the field observations were in line with the simulation results. The findings of this study can provide field data for similar conditions.

Shale gas enrichment model and exploration implications in the mountainous complex structural area along the southwestern margin of the Sichuan Basin: A new shale gas area

Marine shale gas in the southern Sichuan Basin is the most successful area of shale gas exploration and development in China. In order to open up new shale gas fields and search for new shale gas reserves and production replacement blocks, it is necessary to continuously establish and complete the standards on shale gas reservoir evaluation and area selection under different structural settings. The early exploration practice shows that shale in the mountainous complex structural area along the southwestern margin of the Sichuan Basin varies greatly in the gas bearing property, so systematical analysis and study on the shale gas enrichment mechanisms in this area is of great significance to searching for new shale gas exploration areas. Based on drilling data of 5 wells in the mountainous complex structural area along the southwestern margin of the Sichuan Basin, the main factors controlling the shale gas bearing property and the shale gas enrichment model were discussed based on the systematical experiments and analysis of the outcrops, cores and cuttings of Longmaxi Formation shale from the aspects of organic geochemistry, physical property, gas content, hydrocarbon generation history and pore evolution history, so as to lay a solid geological basis for the birth of a new shale gas area. And the following research results were obtained. First, the shale of the first submember of first Member of Longmaxi Formation (S1l11) in the mountainous complex structural area along the southwestern margin of the Sichuan Basin has an average TOC of 3.02%–4.97% and Ro of 2.38%–3.37%, and the average total gas content in local enrichment zones is up to 4.62 m3/t, so it is classified as quality shale. Second, the detailed studies on hydrocarbon generation history indicate that the shale has the characteristics of “low thermal evolution rate and low maturity”. It is characterized by late hydrocarbon generation, low thermal evolution rate, low current maturity and short late diffusion time, which are favorable for shale gas enrichment. Third, the pore evolution history reveals that shale pore evolution can be divided into six stages, i.e., sharp pore reduction, pore reduction, organic pore formation, pore preservation, organic pore dissipation and karstification, and organic pore and TOC are the most direct control factors of shale gas content. Fourth, favorable shelf facies belt is conducive to the formation of large-scale reservoir space and effective pores, and diversities of preservation conditions under different structural styles and at different structural positions control different pore evolution stages. The shale gas in the mountainous complex structural area is characterized by horizontal zoning and differential enrichment. “Low thermal evolution rate and low maturity” and “slow structural uplifting” are beneficial to the long-term enrichment and preservation of shale gas. In conclusion, the mountainous complex structural area along the southwestern margin of the Sichuan Basin has a shale gas enrichment model of “sedimentation controlling source rocks, diagenesis controlling reservoirs and structure controlling preservation”. This research result provides idea and reference for searching for new shale gas areas and fields.

Shale Gas Exploration Potential in Southwestern Shandong Province of Eastern China

The shale layers of the Permian Shanxi Formation and Taiyuan Formation in the southwestern part of Shandong Province are marine-continental transitional sedimentary facies. When compared with the Ordos Basin, which was a typical breakthrough in marine-continental transitional shale gas exploration, the geological characteristics, exploration, and development prospects of marine-continental transitional shale gas in the southwestern section of Shandong Province are more defined. The shale gas deposits of the Shanxi and Taiyuan Formations in southwestern Shandong Province have the following geological characteristics. The sedimentary environments of Shanxi and Taiyuan Formations are considered to be stable and characterized with widely distributed organic-rich shale, which can be used as composite evaluation layers. The total thickness of the shale range is between 140 and 350 m, with an average of 230 m. The main types of organic matter in the Shanxi Formation are Type Ⅲ and Type Ⅱ2 kerogen, while the main types of organic matter in the Taiyuan Formation are rock types. The abundance and maturity of the organic matter are high, and the gas generating capacity is strong. The reservoir rock mineral composition is complex in the region. The clay mineral content is relatively high and the brittle mineral content is rich. Also, the shale fracturing ability is good. The region has the characteristics of a low porosity and low permeability reservoir, with relatively good reservoir capacity. Three primary points of interest have stably been developed within the region, which are located in the upper high water level system, near the initial flood surface, and the majority of flood surface, including a transgressive system tract and high level system tract. The total gas content is estimated to range between 0.03 and 4.47 m3/t, with an average of 0.30 m3/t. The shale gas resources are rich, including one favorable Class I location with an area of 819.06 km2 and a resource amount of 985.84 × 108 m3; four favorable Class Ⅱ locations with an area of 1,979.68 km2 and a resource amount of 2,278.14 × 108 m3; and five prospective locations with an area of 8,385.52 km2 and a resource amount of 7,299.48 × 108 m3. Therefore, the region was considered to have major exploration potential.

A composition-based model for methane adsorption of overmature shales in Wufeng and Longmaxi Formation, Sichuan Basin

The Wufeng-Longmaxi Formation shale in Sichuan Basin is the main strata of shale gas exploration and development in China. Adsorbed methane is an important part of the total shale gas content. The influence of shale composition on adsorption characteristics is complex, and it is difficult to obtain a comprehensive understanding without a sufficient amount of data. In this work, the total organic carbon (TOC), X-ray diffraction (XRD) mineral analysis, and the excess methane adsorption isotherms with pressure up to 50 MPa at 40 °C of 106 overmature shale samples with TOC of 0.8%-9.0% and clay content of 2%-58% that belong to Wufeng-Longmaxi formation from 10 shale gas wells in Sichuan Basin, China are experimentally investigated and analyzed. New correlations found between compositions and methane adsorption characteristic parameters guide the establishment of a composition-based methane adsorption model that the excess adsorption isotherm of shale is the content-weighted sum of equivalent unit-content excess isotherms for organic matter and clay. With this model, the differences of excess isotherms of these two compositions and the differences of clay-contribution to methane adsorption for different sublayers are disclosed. It is beneficial to improve the accuracy of shale reservoir evaluation of studied blocks under the condition of limited coring and deepening the understanding of the underlying mechanism of methane adsorption characteristics.

Geological conditions and exploration potential for shale gas in Upper Permian Wujiaping Formation in the region of western Hubei-eastern Chongqing

The Upper Permian Wujiaping Formation shale in the region of western Hubei and eastern Chongqing has been found qualified for shale gas accumulation in early exploration activities, but the potential for shale gas exploration is still unclear. Based on the core analysis and test data of well Jy3, combined with regional seismic, testing and logging data of this well and wells nearby, the shale distribution, quality, gas-bearing properties, preservation conditions and resource scale of the second member of Wujiaping Formation were discussed. The results showed that the organic-rich shale of deep-water shelf facies and slope to shallow shelf facies were developed and they appeared to be thin in the southwest and thick in the northeast. The shale was mainly composed of quartz (averages 43.10%), clay minerals (average 21.95%) and calcite (averages 17.20%). The organic matter is rich (average TOC value of 8.77%), mainly of type Ⅱ1 kerogen, high thermal maturity (average converted %Ro value of 2.06%), excellent porosity (average value of 5.59%) and good gas bearing property (total gas content averages 3.73 m3/t). The Wujiaping Formation in the Hongxing area is the most promising replacement strata and area for shale gas exploration and development, which shares the largest shale thickness, the best preservation condition, and the most abundant resource.

Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m3/t and 3.719 m3/t, and the total gas contents were between 0.44 m3/t and 5.19 m3/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas.

Preliminary Assessment of the Resource and Exploitation Potential of Lower Permian Marine-Continent Transitional Facies Shale Gas in the Huainan Basin, Eastern China, Based on a Comprehensive Understanding of Geological Conditions.

The Huainan Basin in eastern China contains abundant shale gas resources; the Lower Permian is an exploration horizon with a high potential for shale gas in marine-continent transitional facies. However, few detailed analyses have investigated shale gas in this area. In this paper, a comprehensive investigation of the geochemical characteristics, physical properties, and gas-bearing capacities of shale reservoirs was conducted, and the resource and exploitation potential were evaluated. The results show that the cumulative thicknesses of the Shanxi Formation (P1s) and lower Shihezi Formation (P2xs) are mostly greater than 35 and 65 m, respectively. The TOC contents of the P1s and P2xs shale vary from 0.11 to 8.87% and from 0.22 to 14.63%, respectively; the kerogens predominantly belong to type II with minor amounts of type I or type III kerogens; average Ro values range between 0.83 and 0.94% and between 0.82 and 1.02% in P1s and P2xs, respectively; the shale samples are primarily at a low maturity, while some shale samples have entered the high-maturity stage. The shale reservoirs have low permeability and porosity in P1s and P2xs, respectively. The pores of the P1s shale reservoir are characterized by well-developed micropores and transition pores and poorly developed mesopores, while the pores in the P2xs shale reservoir are all characterized by well-developed micropores and transition pores and some well-developed macropores; the different pore types in the shale reservoirs developed in the organic matter, clay minerals, and pyrite, while a few endogenous fractures developed in the organic matter and structural fractures developed in the minerals. The total shale gas contents in P1s and P2xs are 2.85 and 2.96 m3 t–1, respectively. The P2xs shale reservoir has a higher hydrocarbon generation potential than P1s and has a lower gas generation potential. The total shale gas amounts in P1s and P2xs are 3602.29–4083.04 × 108 and 2811.04–3450.77 × 108 m3, respectively. Further research on shale gas exploration and exploitation for these formations needs to be performed.

Unveiling the nature of 11 dusty star-forming galaxies at the peak of cosmic star formation history

ABSTRACT We present a panchromatic study of 11 (sub-)millimetre selected DSFGs with spectroscopically confirmed redshift (1.5 < zspec < 3) in the GOODS-S field, with the aim of constraining their astrophysical properties (e.g. age, stellar mass, dust, and gas content) and characterizing their role in the context of galaxy evolution. The multiwavelength coverage of GOODS-S, from X-rays to radio band, allow us to model galaxy SED by using cigale z with a novel approach, based on a physical motivated modelling of stellar light attenuation by dust. Median stellar mass (≃ 6.5 × 1010 M⊙) and SFR (≃ 241 M⊙ yr−1) are consistent with galaxy main sequence at z ∼ 2. The galaxies are experiencing an intense and dusty burst of star formation (medianLIR ≃ 2 × 1012L⊙), with a median age of 750 Myr. The high median content of interstellar dust (Mdust ≃ 5 × 108 M⊙) suggests a rapid enrichment of the ISM (on time-scales ∼108 yr). We derived galaxy total and molecular gas content from CO spectroscopy and/or Rayleigh–Jeans dust continuum (1010 ≲Mgas/M⊙ ≲ 1011), depleted over a typical time-scale τdepl ∼ 200 Myr. X-ray and radio luminosities (LX = 1042–1044 erg s−1,L$_{1.5\, {\rm GHz}}=10^{30}\!-\!10^{31}$ erg s−1,L$_{6\, {\rm GHz}}=10^{29}\!-\!10^{30}$ erg s−1) suggest that most of the galaxies hosts an accreting radio-silent/quiet SMBH. This evidence, along with their compact multiwavelength sizes (median rALMA ∼ rVLA = 1.8 kpc, rHST = 2.3 kpc) measured from high-resolution imaging (θres ≲ 1 arcsec), indicates these objects as the high-z star-forming counterparts of massive quiescent galaxies, as predicted e.g. by the in situ scenario. Four objects show some signatures of a forthcoming/ongoing AGN feedback, which is thought to trigger the morphological transition from star-forming discs to ETGs.

Measurement of Fluid Phase Equilibria for High Gas Ratio Mixtures of Carbon Dioxide, Methane, and Brazilian Presalt Crude Oil

The phase behavior of petroleum fluids under reservoir conditions provides fundamental information for an adequate crude oil production scheme. Recently, complex phase transitions have been studied for presalt crude oils, involving atypical liquid–liquid–vapor and liquid–liquid–asphalt phase transitions. In this paper, the phase behavior of synthetic mixtures containing carbon dioxide, methane, and a Brazilian presalt crude oil was investigated using PVT, coupled with near-infrared (NIR) transmittance and high-pressure microscopy (HPM) measurements. Crude oil (API 28.0, 0.68 wt % of asphaltenes) was mixed with 25.0 wt % gas (for a CH4/CO2 ratio from 0 to 62.5 wt %), and the phase behavior of the mixture was evaluated at a reservoir temperature of 343.15 K and pressures up to 100 MPa. Black oil phase behavior was detected for systems with a lower CH4/CO2 ratio and lower gas volume fraction, with no asphaltenes precipitation observed. As the CH4/CO2 ratio increased, pressure–volume curves showed a slight phase transition, with a not evident sharp break in the slope because of the minor difference of fluid compressibility. Moreover, a phase insolubility was confirmed by NIR and HPM tests for a high CH4/CO2 ratio that can be associated with the formation of an asphaltic phase. When total molar gas content increases by increasing the CH4/CO2 ratio, the asphaltic phase is formed at higher pressures. However, asphaltenes were detected as an uncommon fine dispersion with no larger fractal aggregates formation, even at pressures far below the asphaltenes onset pressure (AOP). Additionally, a nontypical behavior was observed in HPM tests with a total asphaltene dissolution when pressure reached the bubble pressure point. This atypical redissolution is in accordance with an instantaneous phase dissolving at pressures higher than the AOP, observed for the same oil at high methane ratios.

The Gas Content Characteristics of Nanopores Developed in a Normal Pressure Shale Gas Reservoir in Southeast Chongqing, Sichuan Basin, China.

To evaluate the gas content characteristics of nanopores developed in a normal pressure shale gas reservoir, the Py1 well in southeast Chongqing was selected as a case study. A series of experiments was performed to analyze the total organic carbon content, porosity and gas content using core material samples of the Longmaxi Shale from the Py1 well. The results show that the adsorbed gas and free gas content in the nanopores developed in the Py1 well in the normal pressure shale gas reservoir range from 0.46-2.24 m₃/t and 0.27-0.83 m₃/t, with average values of 1.38 m₃/t and 0.50 m₃/t, respectively. The adsorbed gas is dominant in the shale gas reservoir, accounting for 53.05-88.23% of the total gas with an average value of 71.43%. The Gas Research Institute (GRI) porosity and adsorbed gas content increase with increasing total organic carbon content. The adsorbed gas and free gas contents both increase with increasing porosity value, and the rate of increase in the adsorbed gas content with porosity is larger than that of free gas. Compared with the other five shale reservoirs in America, the Lower Silurian Longmaxi Shale in the Py1 well developed nanopores but without overpressure, which is not favorable for shale gas enrichment.

Micropore Characteristics and Gas-Bearing Characteristics of Marine-Continental Transitional Shale Reservoirs in the East Margin of Ordos Basin

In order to deeply study the exploration potential of Carboniferous-Permian marine-continental transitional shale reservoirs in the Ordos Basin, the shale samples from well Y1 in the central-southern part of the Hedong Coalfield were used as the research object. The organic geochemical test, scanning electron microscope, X-ray diffraction, and high pressure mercury injection and low-temperature nitrogen adsorption experiments have studied the microscopic characteristics and gas content characteristics of shale reservoirs. The results show that the organic matter type of the sample is type III; the TOC content ranges from 0.28% to 16.87%, with an average of 2.15%; [Formula: see text] is from 2.45% to 3.36%, with an average value of 2.86%; the shale pores in the study area are well developed, containing more organic pores and intergranular pores of clay minerals. Based on the two-dimensional SEM image fractal theory to study different types of pores, the fractal dimension of shale pore fracture morphology is between 2.34 and 2.50, and the heterogeneity is moderate. The high-pressure mercury intrusion experiment characterizes the pore size distribution of shale macropores and transition pores. The pore diameters are mostly nm-scale. Transition pores are the main pores of the shale in the study area. Based on the characteristics of the pore structure, the adsorption capacity and gas content of CH4 in shale reservoir were analyzed by methane isothermal adsorption and gas content experiments. The results showed that the pore volume and specific surface area were positively correlated with clay mineral content, TOC, and RO, but negatively correlated with the quartz content. In clay minerals and brittle minerals, pore volume and specific surface area are positively correlated with illite content and negatively correlated with the quartz and kaolinite content. The measured total gas content and desorbed gas content are significantly positively correlated with TOC, but are weakly positively correlated with the quartz and illite content. This study finely characterizes the physical properties, micropore characteristics, gas-bearing characteristics, and influencing factors of shale reservoirs, which has certain theoretical guiding significance for the research and development of coal-measure shale in the Ordos Basin.

Micro-Pore Reservoir Spaces and Gas-Bearing Characteristics of the Shale Reservoirs of the Coal Measure Strata in the Qinshui Basin.

To study the exploration potential of the Carboniferous-Permian transitional shale reservoirs in the Qinshui Basin, the Y5 well was selected as the research object, and experiments including organic geochemical tests, microscopic observations, scanning electron microscopy, X-ray diffraction analysis, high-pressure mercury intrusion, methane isothermal adsorption, and low-temperature nitrogen adsorption were carried out to analyse the physical properties of the shale reservoirs of interest. The results show that (1) The organic matter type of the samples is type III, the total organic carbon contents range from 0.27% to 20.52% (avg. 3.15%), the RO values are between 2.45% and 3.36% (avg. 2.86%), and the Tmax values range from 311.00 °C to 575.20 °C (avg. 493.31 °C). These results indicate that the organic matter in the study area is abundant and has experienced a high degree of thermal evolution. (2) The brittleness index is low (avg. 43.81%), and the shale pores in the study area are well developed. The pores contain organic matter-hosted pores, intraparticle pores, interparticle pores, and micro-cracks. (3) The methane isotherm adsorption average contents of the two samples are 0.2968 m³/t and 1.0824 m³/t, and the average contents of the on-site desorbed gas content and measured total gas content are 0.55889 m³/t and 0.8624 m³/t, respectively. (4) The kaolinite and illite contents have a significant negative effect on the specific surface area of the macro-pores and the specific pore volume of the meso-pores. The illite content is conducive to the development of the pore diameter and specific surface area of the meso-pores, and the quartz content has a positive correlation with the specific pore volume of the macro-pores. (5) The measured total gas content has a significant positive correlation with the total organic carbon and a weak positive correlation with the contents of quartz and illite, and the desorbed gas content shows the same correlations. This study demonstrates the physical properties, microscopic pore characteristics, and gas-bearing characteristics of shale reservoirs and their influencing factors in detail.

Gas composition and carbon isotopic variation during shale gas desorption: Implication from the Ordovician Wufeng Formation - Silurian Longmaxi Formation in west Hubei, China

This paper focuses on the gas composition and carbon isotopic variation during gas desorption from the shale in Ordovician Wufeng Formation-Silurian Longmaxi Formation. The results show that the desorbed shale gases are predominately comprised of methane (content: 98.36–98.76%) and thus are typical dry gas. As the desorption proceeded, the content of methane gradually decreased, and the drying coefficient (C1/C1-5) of the desorbed shale gases also gradually decreased. The drying coefficient decreased from 98.58 to 99.04% (98.81% on average) of the initial desorbed samples to 88.72–96.78% (94.15% on average) of the final desorbed samples. Based on the variation patterns of gas component ratios during the shale gas desorption, the order of the shale's absorption capacity for different gas components is determined as CO2 > H2 > C3H8 > C2H6 > CH4 > He. The drying coefficient of the shale gas is negatively correlated with the total shale gas content due to the different adsorption capability of shale for gaseous hydrocarbons. The δ13C values tended to become heavier during desorption in general. The δ13C1 values of the initial desorbed samples were the lowest, ranging from −30.71‰ to −25.63‰. In detail, the δ13C values of methane increased by 5.41–25.93‰, while those of ethane increased within a relatively smaller range. The carbon isotopic fractionation is mainly ascribed to diffusion and adsorption/desorption. Moreover, the carbon isotopic fractionation degree of methane was correlated with the shale gas content during the field desorption, suggesting that the carbon isotopic fractionation degree of methane is a potential tool for the identification and selection of favorable sweet spots of shale gas. In addition, the shale gas from Wufeng-Longmaxi Formation in west Hubei consists of highly mature oil-cracking gas and kerogen-cracking gas. All of the desorbed shale gas is characterized by isotopic reversal and the extent of the isotopic reversal increased as desorption continued. This is primarily caused by the mixing of the gas from thermal degradation of kerogen with the gas from residual oil cracking and wet gas as well as the diffusion of the shale gas. The carbon isotope reversal of methane and ethane is not directly related to shale gas content.

Cenozoic exhumation and shale-gas enrichment of the Wufeng-Longmaxi formation in the southern Sichuan basin, western China

Based on low-temperature thermochronological data (i.e., apatite fission-track (AFT) and (U–Th)/He (AHe)), structural evolution, burial and thermal history, this paper examines the relationship of multi-stage evolution between the upper Ordovician Wufeng and lower Silurian Longmaxi formations (i.e., the WL formation) and rapid exhumation at the Changning shale gas field in the southern Sichuan basin. AFT ages are generally young from southeast to northwest, decreasing from ca. 40 to 15 Ma while AHe single-grain ages range from ~35 to ~5 Ma. Inverse thermal histories show that a multi-stage cooling history with initial cooling began in the Late Cretaceous to early Cenozoic (middle Eocene), followed by accelerated rapid cooling in the late Cenozoic, with cooling rates of 2–4 °C/Myr across the Changning shale gas field. In particular, thermal models of samples in the western Changning area show a substantial increase in the cooling rates, i.e., from less than 1 °C/Myr to 3–5 °C/Myr in the Miocene. Integrated with inverse T-t models of low-temperature thermochronological data, the burial history indicates a four-stage thermal evolution of the WL Formation in the Changning shale-gas field: Early Mature from the middle Silurian to middle Permian, Middle Mature from the late Permian to Late Triassic, Late Mature from the Early Jurassic to Early Cretaceous, and Over mature since the middle Cretaceous, reaching a maximum burial depth of ~6000 m and maximum temperature of 190–200 °C at ca. 70–80 Ma. This evolution further suggests that a normal hydrostatic pressure index dominated the WL Formations in the Paleozoic. The gas generation and pressure index, however, have substantially increased since the Late Jurassic, particularly from the Early to middle Cretaceous, with a maximum pressure index of 2.1, which is indicative of the main shale gas accumulation and enrichment period in the WL Formation. Post-gas-generation structural deformation, uplift, and exhumation had a significant impact on shale gas enrichment, mainly through their influence on shale gas preservation. This suggests some relationships among the higher pressure coefficient of the WL Formation, the higher productivity and total gas content of the WL Formation, a weaker post-gas-generation structural deformation, and a weaker uplift, as indicated by the erosion and burial depth across the Changning shale gas field. Due to a significantly stronger cooling and uplift that occurred the in Late Cenozoic across the western Changning area, the pressure index decreased rapidly from ~2.0 to 1.0 with a normal pressure condition, indicating the destruction of the reservation condition in the WL Formation.

The link between star formation and gas in nearby galaxies

Observations of the interstellar medium are key to deciphering the physical processes regulating star formation in galaxies. However, observational uncertainties and detection limits can bias the interpretation unless carefully modeled. Here I re-analyze star formation rates and gas masses of a representative sample of nearby galaxies with the help of multi-dimensional Bayesian modeling. Typical star forming galaxies are found to lie in a ‘star forming plane’ largely independent of their stellar mass. Their star formation activity is tightly correlated with the molecular and total gas content, while variations of the molecular-gas-to-star conversion efficiency are shown to be significantly smaller than previously reported. These data-driven findings suggest that physical processes that modify the overall galactic gas content, such as gas accretion and outflows, regulate the star formation activity in typical nearby galaxies, while a change in efficiency triggered by, e.g., galaxy mergers or gas instabilities, may boost the activity of starbursts.

Implications of geological conditions on gas content and geochemistry of deep coalbed methane reservoirs from the Panji Deep Area in the Huainan Coalfield, China

The objective of this study is to reveal the implications of geological conditions on gas content and geochemistry of deep coalbed methane (CBM) reservoirs. It is of great practical significances to improve the theory and technology for deep CBM development. In this work, the gas content and geochemistry of selected samples were obtained by canister desorption method, gas chromatography (GC) and GC–Mass Spectrometry (GC–MS). On the basis of geological conditions, the Panji Deep Area was confirmed as a mining block of high gas content, high ground stress and reservoir temperature, multiple sets of coal seams, and complex mining conditions. Deep-buried coals from No.13–1 and No.11–2 coal seams are generally low-mineral bituminous coals, which show similar coal rank (Ro,max = 0.71%–0.85%) but vary in maceral and chemical components. In addition, the estimated total gas contents of No.13–1 and No.11–2 coal seams are 9.58–23.59 m3/t and 9.46–13.72 m3/t, respectively. Notably, the growth rate of total gas content exhibits two different stages and shows a logarithmic correlation with reservoir temperature, effective thickness of overlying strata, burial depth and gas pressure. The carbon isotopic value of methane (δ13C1) of No.13–1 coal seam varies from −45.09‰ to −39.23‰ (average, −41.90‰), and that for No.11–2 coal seam ranges from −44.92‰ to −38.45‰ (average, −41.90‰). δ13C1 is unrelated with Ro,max but is positively correlated with burial depth and effective thickness of overlying strata, this indicates that δ13C1 value becomes heavier as burial depth increases, which may be related to the desorption-diffusion-migration effect caused by deeper burial depth and in-situ stress exertion. Moreover, δ13C1 shows a positive linear correlation with total gas content, it is inferred that δ13C1 has a correlation with the control factors of total gas content.

Study on the characteristics of in-situ gas desorption from the Wufeng - Longmaxi shale in the Sichuan Basin

Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation shale in the Sichuan Basin and its periphery is an important horizon for shale gas exploration and development in my country. The rapid on-site desorption instrument independently developed by Sinopec Wuxi Institute of Petroleum Geology was used to test the desorption gas volume, lost gas volume, total gas content, natural gas components of desorbed gas and carbon isotope of methane in typical shale gas wells in this area. Data analysis shows that the carbon isotope value and characteristics of the first sample of methane can predict shale gas enrichment layers, and the total gas content and desorbed natural gas components can identify shale gas sweet spots; shale gas components and carbon isotope values can jointly identify shale gas Genesis type, kerogen carbon isotope characteristics and shale gas carbon isotope characteristics can be used as effective means for gas source comparison; shale gas composition characteristics can distinguish the preservation conditions of the area, which are indicative for the study of the degree of shale gas loss; The combined application of total gas content and initial dissipation index can better identify the sweet spots of shale gas, and avoid single-factor identification of sweet spots; the carbon isotope value of methane shows obvious fractionation effect with desorption time, which can predict shale gas production stage and residual gas content.

Reservoir Characteristics of the Lower Silurian Longmaxi Shale in Zhaotong Region, Southern China

The lower Silurian Longmaxi Formation hosts a highly productive shale gas play in the Zhaotong region of southern China. According to core observation, X-ray diffraction analyses, and scanning electron microscopy (SEM) observations, the shale comprises primarily quartz, carbonate minerals, and clay minerals, with minor amounts of plagioclase, K-feldspar, and pyrite. The clay mineral content ranges from 15.0% to 46.1%, with an average of 29.3% in the Zhaotong region. Organic geochemical analyses show that the Longmaxi Formation has good potential for shale gas resources by calculating total organic carbon, vitrinite reflectance, and gas content. Scanning electron microscope images demonstrate that reservoir pore types in the Longmaxi shale include organic pores, interparticle pores, intercrystalline pores, intraparticle pores, and fractures. Reservoir distribution is controlled by lithofacies, mineral composition, and geochemical factors. In addition, we investigated the relationships between reservoir parameters and production from 15 individual wells in the Zhaotong region by correlation coefficients. As a result, the brittleness index, total organic carbon (TOC), porosity, and gas content were used to define high-quality reservoirs in the Longmaxi shale. Based on these criteria, we mapped the thickness and distribution of high-quality reservoirs in the Longmaxi Formation and selected highlighted several key sites for future exploration and development.

Gas-bearing property of the Lower Cambrian Niutitang Formation shale and its influencing factors: A case study from the Cengong block, northern Guizhou Province, South China

To gain a better understanding of the gas-bearing property of Lower Cambrian Niutitang Formation shale and its influencing factors, the shale gas-bearing conditions, gas content, and composition in the Cengong block were investigated in this work based on wells CY1, TX1, and TM1. The Niutitang shale reservoir is characterized by large thickness, abundant organic matter with an average total organic carbon content of 4.74%, and high quartz content averaging 53.9%; therefore, it has good shale gas-bearing potential. The results of water immersion and ignition tests intuitively revealed the existence of shale gas based on the occurrence of continuous dense clusters of bubbles and long flames of 1–2 m. The Langmuir volumes of shale samples from well TM1, which ranged from 1.70 to 5.53 m3/t, were positively associated with TOC content and Brunauer–Emmett–Teller surface area, indicating a strong adsorption capacity and significant adsorbed gas potential. However, large differences were observed among the three wells with regard to gas-bearing properties; wells CY1 and TX1 had average total gas contents of 1.25 and 0.33 m3/t, respectively; the gas composition of well TM1 was dominated by nitrogen (N2), with contents generally exceeding 95%. Furthermore, the gas from well TX1 was mainly composed of methane with an average content exceeding 80%. Burial depth and TOC and quartz contents had significant control on the vertical distribution of gas content, and local tectonic preservation conditions resulted in differences of gas-bearing properties among various wells. The measured, lost, and total gas contents all presented positive correlations with TOC, quartz contents, and porosity, and were negatively related to clay content. The shale formed in deep-water shelf environments had better gas-bearing properties than that formed in shallow-water shelf environments. The broad axis of the box syncline in the Cengong block is a favorable location for shale gas accumulation, and fault development affects the shale gas plane distribution. Because of the influence of faults, the shale of well TM1 had low hydrocarbon content. Furthermore, based on the combined patterns of folds and faults as well as other special specific factors, a classification scheme of shale gas accumulation patterns in South China was developed.

A new approach to estimating coal gas content for deep core sample

Method to accurately estimate gas content in the deep-burial coals is still unavailable. To this end, a new method which avoids the underestimation of lost gas content during the retrieval process of deep-burial coal sample within boreholes was well established in the text. This method, which is based on nonlinear curve-fit of measured gas content, contains two parameters to be determined. The two key parameters, referred to the lost gas and total gas, were precisely determined through the best matching with the experimental data with the aid of additional residual gas as a part of the total desorbed gas. As a case study, a suggested error analysis method was used to verify the accuracy of the lost gas of two coal cores based on extended desorption data more than 1 000 min or field customized data of 120 min including the supplemental data of residual gas. Utilizing the present method to calculate the gas content of fifteen core coal samples with standard field cases in the study area, the calculated lost gas and total gas content are 0.88–1.54 times and 1.15–1.96 times with an average of 1.17 and 1.47 times of the measured values obtained by the direct method, respectively. The new method offers an accurate estimation of gas content, which has a wide application potential that the traditional methods are not applicable for deep-burial coal seam.