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The switch from the use of coal to natural gas or oil for energy generation potentially reduces greenhouse gas emissions and thus the impact on global warming and climate change because of the higher energy creation per CO2 molecule emitted. However, the climate benefit over coal is offset by methane (CH4) leakage from natural gas and petroleum systems, which reverses the climate impact mitigation if the rate of fugitive emissions exceeds the compensation point at which the global warming resulting from the leakage and the benefit from the reduction of coal combustion coincide. Consequently, an accurate quantification of CH4 emissions from the oil and gas industry is essential to evaluate the suitability of natural gas and petroleum as bridging fuels on the way to a carbon-neutral future. We show that regional CH4 release from large oil and gas fields can be monitored from space by using dense daily recurrent measurements of the TROPOspheric Monitoring Instrument (TROPOMI) onboard the Sentinel-5 Precursor satellite to quantify emissions and leakage rates. The average emissions for the time period 2018/2019 from the five most productive basins in the United States, the Permian, Appalachian, Eagle Ford, Bakken, and Anadarko, are estimated to be 3.18±1.13, 2.36±0.88, 1.37±0.63, 0.89±0.56, and 2.74±0.74 Mt yr−1, respectively. This corresponds to CH4 leakage rates relative to the associated production between 1.2 % and 1.4 % for the first four production regions, which are consistent with bottom-up estimates and likely fall below the break-even leakage rate for immediate climate benefit. For the Anadarko Basin, the fugitive emission rate is larger and amounts to 3.9±1.1 %, which likely exceeds the break-even rate for immediate benefit and roughly corresponds to the break-even rate for a 20-year time horizon. The determined values are smaller than previously derived satellite-based leakage rates for the time period 2009–2011, which was an early phase of hydraulic fracturing, indicating that it is possible to improve the climate footprint of the oil and gas industry by adopting new technologies and that efforts to reduce methane emissions have been successful. For two of the world's largest natural gas fields, Galkynysh and Dauletabad in Turkmenistan, we find collective methane emissions of 3.26±1.17 Mt yr−1, which corresponds to a leakage rate of 4.1±1.5 %, suggesting that the Turkmen energy industry is not employing methane emission avoidance strategies and technologies as successfully as those currently widely used in the United States. The leakage rates in Turkmenistan and in the Anadarko Basin indicate that there is potential to reduce fugitive methane emissions from natural gas and petroleum systems worldwide. In particular, relatively newly developed oil and gas plays appear to have larger leakage rates compared to more mature production areas.

Natural gas from tight shale formations will provide the United States with a major source of energy over the next several decades. Estimates of gas production from these formations have mainly relied on formulas designed for wells with a different geometry. We consider the simplest model of gas production consistent with the basic physics and geometry of the extraction process. In principle, solutions of the model depend upon many parameters, but in practice and within a given gas field, all but two can be fixed at typical values, leading to a nonlinear diffusion problem we solve exactly with a scaling curve. The scaling curve production rate declines as 1 over the square root of time early on, and it later declines exponentially. This simple model provides a surprisingly accurate description of gas extraction from 8,294 wells in the United States’ oldest shale play, the Barnett Shale. There is good agreement with the scaling theory for 2,057 horizontal wells in which production started to decline exponentially in less than 10 y. The remaining 6,237 horizontal wells in our analysis are too young for us to predict when exponential decline will set in, but the model can nevertheless be used to establish lower and upper bounds on well lifetime. Finally, we obtain upper and lower bounds on the gas that will be produced by the wells in our sample, individually and in total. The estimated ultimate recovery from our sample of 8,294 wells is between 10 and 20 trillion standard cubic feet.

In the Sichuan Basin, seismic activity has been low historically, but in the past few decades, a series of moderate to strong earthquakes have occurred. Especially since 2015, earthquake activity has seen an unprecedented continuous growth trend, and the magnitude of events is increasing. Following the M 5.7 Xingwen earthquake on 18 Dec. 2018, which was suggested to be induced by shale gas hydraulic fracturing, a swarm of earthquakes with a maximum magnitude up to M6.0 struck Changning and the surrounding counties. Questions arose about the possible involvement of industrial actions in these destructive events. In fact, underground fluid injection in salt mine fields has been occurring in the Sichuan Basin for more than 70 years. Disposal of wastewater in natural gas fields has also continued for about 40 years. Since 2008, injection for shale gas development in the southern Sichuan Basin has increased rapidly. The possible link between the increasing seismicity and increasing injection activity is an important issue. Although surrounded by seismically active zones to the southwest and northwest, the Sichuan Basin is a rather stable region with a wide range of geological settings. First, we present a brief review of earthquakes of magnitude 5 or higher since 1600 to obtain the long-term event rate and explore the possible link between the rapidly increasing trend of seismic activity and industrial injection activities in recent decades. Second, based on a review of previous research results, combined with the latest data, we describe a comprehensive analysis of the characteristics and occurrence conditions of natural and injection-induced major seismic clusters in the Sichuan Basin since 1700. Finally, we list some conclusions and insights, which provide a better understanding of why damaging events occur so that they can either be avoided or mitigated, point out scientific questions that need urgent research, and propose a general framework based on geomechanics for assessment and management of earthquake-related risks.

Methane microseepage from oil and gas fields significantly contributes to atmospheric methane level, making it a critical factor in global climate change. Therefore, accurate monitoring of surface flux and investigating migration mechanism are pivotal to evaluating and mitigating the impact of methane microseepage. In this study, methane microseepage from natural gas reservoirs in a mild climate was investigated, using Xinchang gas field as a case study. Soil samples were collected to analyze geochemical anomalies of acid-hydrolyzed hydrocarbons (AHH) and altered carbonates (AC). Surface methane flux from natural gas reservoirs were monitored, using a greenhouse gas analyzer and static gas collection chambers. Methane release patterns and migration mechanism were then discussed. Headspace and soil gas samples were collected to determine the hydrocarbon composition and carbon isotope profile. The results indicate that surface methane flux in Xinchang gas field is weak, exhibiting three release patterns: continuous, episodic, and flat. Spiked anomalies of AHH and AC co-exist in the test area, suggesting methane migration from reservoirs to surface. Hydrocarbon composition and carbon isotope profile in headspace and soil gas samples confirm thermogenic origin of methane. These findings offer new insights into the behavior of methane microseepage from natural gas reservoirs in mild climate. It is also suggested that close monitoring and stringent regulation of methane microseepage, as well as continuous investigation on factors affecting this phenomenon, are essential to the management of geological methane emissions. The conclusions of this work align with previous studies and are applicable to managing methane microseepage from oil and gas reservoirs in a wider scope.

With the extensive exploitation of shale gas fields in southern Sichuan, China, the Weiyuan Area – a key production zone within this region – has experinced a growing gas well plugging problem, which significantly hampers production efficiency. This study presents a comprehensive analysis of plugging problems in this area. Plugging samples were obtained from typically affected gas wells and subjected to a suite of analytical techniques. Results indicated that plugging materials were predominantly inorganic, primarily comprising iron-based impurities and mineral scale deposits, while organic components—present in minor proportions—primarily composed of long-chain alkanes. The formation of these plugs is attributed to downhole corrosion, high-salinity formation water, and complex chemical interactions occurring within the wellbore. In response, specialized plugging removal agents were developed: an organic composite acid-organic solvent system achieved up to 98% dissolution efficiency for iron oxide-dominated plugs; a chelating agent based on CDTA was optimized for iron sulfide-based plugging; and the DTPA-based system exhibited superior dissolution efficiency for barium sulfate/calcium carbonate scale deposits. This research provides a scientific basis for effectively mitigating plugging issues in comparable shale gas fields.

Saline aquifers have been used for CO2 storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO2. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO2 injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO2 instead of dense-phase CO2 typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO2-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO2 trapping in saline aquifers will be dominated by buoyancy processes with residual CO2 and dissolved CO2 developing over time whereas depleted gas fields will be dominated by a sinking body of CO2 that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO2 (i.e., low storage efficiency factors between 2 and 20%) as the injected CO2 is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO2 in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO2 to mitigate greenhouse gas emissions and minimise global heating.

DF13-2 and YC13-1 are two large gas fields found in Yinggehai and Qiongdongnan Basins, respectively, and the gas-source correlation is a very challenging scientific exercise due to the similarity of their hydrocarbon isotoperatios and gas dryness. In this study, the chemical and isotopic compositions of natural gases (including rare gases and bulk gases) and the biomarkers of condensate were comprehensively integrated to identify their origins. The gases from the two fields are composed primarily of methane (87–91%), and isotope ratios of hydrocarbon compounds exhibit a thermogenic origin, with δ 13 C 1 values ranging from − 40.7 to 35.0‰, and δ 13 C 2 from − 27.0 to − 25.4‰. There are small yet distinct differences in the genetic characteristics of CH 4 He, Ar, CO 2 , N 2 and condensate between the samples from two regions. The δ 13 C 1 values of DF13-2 (− 36.8 to − 33.7‰) are slightly larger than those (− 40.7 to − 35.5‰) of YC13-1, suggesting a slightly higher thermal maturity in DF13-2 field. In addition, DF13-2 gases contain lower Ar (0.0096–0.016%) and He (11–15 ppm). The 3 He/ 4 He ratios range from 3.31 × 10 −8 to 7.72 × 10 −8 , indicating a typical crustal origin, likely representative of pristine source-rock signatures. The gases have higher N 2 (8.4–9.66%) but lower CO 2 contents (0.10–0.36%), which are co-generated with the thermogenic hydrocarbon gases. The condensate coexisted with gas contains abundant terrestrial-derived oleanane but a low abundance of bicadinanes. These characteristics correlate well with the Miocene neritic shales in Yinggehai Basin. Fractures associated with the diapiric activity provide key conduits for gas up-migration into the Huangliu Formation reservoir, implying that the flank of a diapiric structure is a favorable site for gas accumulation. In contrast, the gases from YC13-1 field show lower N 2 but higher CO 2 amounts. He and Ar abundances are both higher with a small amount contribution (2–9%) of mantle-derived He. The elevated amounts of mantle-derived 3 He may come from mantle-enriched groundwater circulating in the petroleum system. The coexisted condensate is rich in terrestrial biomarkers such as oleanane and bicadinane, which is significantly different from DF13-2 condensate, and has a close affinity with the coal-bearing source rocks of the Oligocene Yacheng Formation. Unconformities and faults serve as important conduits for lateral and vertical migration from the source rocks to the traps. This suggests that short-distance migration and source facies control the distribution of the natural gases in Qiongdongnan Basin. This study provides novel insights into the origin and accumulation model of natural gases in Yinggehai and Qiongdongnan Basins.

Helium gas is a scarce but important strategic resource, which is usually associated with natural gas. Presently, only one extra-large helium-rich gas field has been found in China: the Hetianhe Gas Field in the Tarim Basin. This paper reports a new example, the Dongsheng Gas Field (DGF) in the Ordos Basin. In this study, 92 natural gas samples from the DGF were analyzed for helium content and isotope composition using isotope mass spectrometry. The natural gas samples were found to have an average helium content of 0.133%, with 65 (70.7%) of the samples having a helium content of 0.1% or more. Based on the proven natural gas reserves of the DGF, the proven geological helium reserves were calculated to be 1.96×10 8 m 3 , suggesting that it represents the first extra-large helium-rich natural gas reservoir to be hosted in tight sandstone in China. The 3 He/ 4 He ratios of 5 natural gas samples from the DGF are within the range of 3.03×10 −8 −3.44×10 −8 . Therefore, the helium in the gas field is thought to be of typical crustal origin and to have formed in the granitic basement that is rich in uranium and thorium. The accumulation of helium-rich natural gas was controlled by regional tectonic activities. Activity along the fault connecting the reservoir with the basement caused release of the helium gas, which entered the overlying strata along the fault and accumulated with conventional hydrocarbon gas. Based on the structural background and the distribution of helium source rocks in the Ordos Basin, the main helium source rocks with high exploration potential are located in deep strata within the north and middle parts of the basin.

Subsurface petroleum reservoirs are an important component of the deep biosphere where indigenous microorganisms live under extreme conditions and in isolation from the Earth’s surface for millions of years. However, unlike the bulk of the deep biosphere, the petroleum reservoir deep biosphere is subject to extreme anthropogenic perturbation, with the introduction of new electron acceptors, donors and exogenous microbes during oil exploration and production. Despite the fundamental and practical significance of this perturbation, there has never been a systematic evaluation of the ecological changes that occur over the production lifetime of an active offshore petroleum production system. Analysis of the entire Halfdan oil field in the North Sea (32 producing wells in production for 1–15 years) using quantitative PCR, multigenic sequencing, comparative metagenomic and genomic bins reconstruction revealed systematic shifts in microbial community composition and metabolic potential, as well as changing ecological strategies in response to anthropogenic perturbation of the oil field ecosystem, related to length of time in production. The microbial communities were initially dominated by slow growing anaerobes such as members of the Thermotogales and Clostridiales adapted to living on hydrocarbons and complex refractory organic matter. However, as seawater and nitrate injection (used for secondary oil production) delivered oxidants, the microbial community composition progressively changed to fast growing opportunists such as members of the Deferribacteres , Delta- , Epsilon - and Gammaproteobacteria , with energetically more favorable metabolism (for example, nitrate reduction, H 2 S, sulfide and sulfur oxidation). This perturbation has profound consequences for understanding the microbial ecology of the system and is of considerable practical importance as it promotes detrimental processes such as reservoir souring and metal corrosion. These findings provide a new conceptual framework for understanding the petroleum reservoir biosphere and have consequences for developing strategies to manage microbiological problems in the oil industry.