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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.

Sand production poses a major challenge in offshore heavy oil development, leading to casing erosion, equipment damage, and wellbore instability, which ultimately results in production decline. Conventional mechanical and chemical sand control methods often exhibit limited effectiveness in fine-grained or high-salinity formations and may induce formation damage or high operational costs. This study developed a self-generated foam-resin composite sand consolidation system to address these issues. The system integrated a controllable gas-generating subsystem and a melamine-formaldehyde (MF) resin matrix, thus enabling in-situ foam generation and sand consolidation. Laboratory experiments were conducted in three stages: optimization of gas and foaming agent subsystems, formulation and evaluation of the resin-based consolidant, and integration testing of the composite system. The optimized formulation resulted in controllable gas production, high foam stability, and consolidated sand cores with compressive strength >7 MPa. The system exhibited thermal stability up to 90 °C, salinity resistance, moderate permeability (~4 μm2), non-adhesion to metal surfaces, and negligible sand production (<0.1%) under dynamic water flooding. These results indicate that the foam-resin composite system provides an efficient, environmentally compatible, and cost-effective solution for sand control in complex offshore heavy oil reservoirs.

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.

Sand production in oil wells is recognized as a persistent challenge during oilfield development, adversely affecting well productivity and operational stability. Chemical sand control methods, particularly resin-based sand consolidation, are considered a promising solution due to their operational simplicity and effectiveness. However, conventional emulsified resins are known to be highly sensitive to high-salinity environments, which can lead to emulsion destabilization and reduced consolidation strength. To address this limitation, a novel emulsified epoxy resin system was developed in this study using a nonionic emulsifying curing agent—fatty amine poly(epoxy ethyl ether)—by which salinity tolerance is significantly enhanced, supporting dilution water salinity up to 3.8 × 10⁴ mg/L. Through single-factor experiments, an optimal formulation was identified as 16% epoxy resin, 24% emulsified curing agent, 1% coupling agent, and 5.6% stabilizer. The molecular structure of the emulsified resin and the stability of the cured matrix were thoroughly characterized. The effects of curing temperature, time, sand particle size, and stabilizer dosage on compressive strength and permeability were systematically evaluated. It was demonstrated that after being cured at 80 °C for 12 hours, the consolidated cores achieved a compressive strength exceeding 3 MPa with permeability retention above 75%. Furthermore, the consolidated cores were shown to exhibit excellent long-term stability, maintaining their mechanical and flow properties after 30-day immersion in kerosene, 10% HCl, and formation water. This study bridges a critical research gap in high-salinity applications of water-based resin emulsions and provides a robust technical solution for sand control in challenging reservoir environments.

In the development of high-temperature and high-salinity oil fields, biopolymer scleroglucan flooding technology faces significant challenges. Traditional scleroglucan products exhibit poor injectability and high extraction costs. This study investigated the application potential of the original fermentation broth of exopolysaccharides (EPS) produced by microorganisms in a simulated high-temperature and high-salinity oil reservoir environment. The polysaccharide was identified as scleroglucan through IR and NMR analysis. Its stability and rheological properties were comprehensively evaluated under extreme conditions, including temperatures up to 150 °C, pH levels ranging from 1 to 13, and salinities up to 22 × 104 mg/L. The results demonstrated that EPS maintained excellent viscosity and stability, particularly at 76.6 °C and 22 × 104 mg/L salinity, where its viscosity remained above 80% for 35 days. This highlights its significant viscoelasticity and stability in high-temperature and high-salinity oil reservoirs. Additionally, this study, for the first time, examined the rheological properties of the original fermentation broth of scleroglucan, specifically assessing its injectability and enhanced oil recovery (EOR) performance in a simulated Middle Eastern high-temperature, high-salinity, medium-low permeability reservoir environment. The findings revealed an effective EOR exceeding 15%, confirming the feasibility of using the original fermentation broth as a biopolymer for enhancing oil recovery in extreme reservoir conditions. Based on these experimental results, it is concluded that the original fermentation broth of Athelia rolfsii exhibits superior performance under high-temperature and high-salinity conditions in medium–low permeability reservoirs, offering a promising strategy for future biopolymer flooding in oil field development.

Carbon capture and storage technology can improve the crude oil collection rate. It can also reduce carbon emission, and has great application prospect. However, under the complex terrain conditions of the oil field, the risk of CO 2 leakage is higher, which is easy to cause personnel asphyxiation. To effectively control the harm of CO 2 leakage and diffusion in this kind of situation, it is necessary to study the law of CO 2 leakage and diffusion under complex terrain conditions. In this study, a full-scale CO 2 leakage and diffusion experiment was carried out in combination with the topography of CO 2 capture and oil displacement in an oilfield. The results showed that under different leakage conditions, the time-average concentration of CO 2 satisfies the exponential distribution law from near to far. The influence range of 1% CO 2 volume concentration under stepped terrain is about 65 m, which is 30% more than that under on lawn ground. As the leakage time increases, the temperature gradually decreases. Besides, the closer to the leakage port, the faster the temperature drop rate. The average temperature gradient is about 0.39°C/ m.

The imbibition of water into the pores of tight oil/gas reservoir can displace the oil/gas out. Thus it is an important method to improve the recovery efficiency of tight shale gas and oil. This paper investigated the influence of four main dimensionless parameters on the spontaneous imbibition based on a pores distribution of a real shale sample. The results show that the connectivity has the greatest impact on the average imbibition velocity while the impact of the contact angle is the smallest. The capillary number has the greatest impact on the oil displacement efficiency. The impact of main factors on imbibition and displacement is not monotonic, but rather a combination of these factors.

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.

The Upper Cretaceous Qingshankou Formation’s lacustrine shales in the Songliao Basin are among China’s most promising shale oil reservoirs. To elucidate their pore and fractal characteristics, a comprehensive set of analyses encompassing total organic carbon (TOC), X-ray diffraction (XRD), and low-temperature N 2 adsorption (LTNA), Rock-Eval pyrolysis experiments and two-dimensional nuclear magnetic resonance (2D-NMR) were conducted. Using the Frenkel-Halsey-Hill (FHH) method, fractal dimensions (D) were calculated, and their relationship with pore metrics and shale compositions were explored. Two distinct fractal dimensions, D 1 (0 < P/P 0 < 0.5) and D 2 (0.5