To investigate the influence of the inhomogeneity and uncertainty of porosity and permeability on gas production, a mathematical model for shale gas nonlinear seepage problem with random distributions of inhomogeneous equivalent porosity and permeability is established. Based on the statistical characteristic of the artificial fracture density distribution and incompletely controllable hydraulic fracturing technology, the random distribution models of continuous inhomogeneous equivalent porosity and permeability are proposed to simulate the uncertainty of the porosity and permeability distribution in SRV. Coupled with multi-scale flow and adsorption effects, a mathematical model of shale gas nonlinear seepage problem is presented to address the inhomogeneity and uncertainty of equivalent porosity and permeability. By Boltzmann transformation and local homogenization approximation, a semi-analytical method and the corresponding explicit iterative scheme are developed.Simulation results match well with field data, which verifies the validity of the presented mathematical model and approach. The morphology of the SRV has significant influence on gas production, followed by the uncertainly of the permeability distribution and the hydraulic fracture half-length. When the horizontal width reaches its maximum in the front part of the macro-fracture zone, shale gas production reaches its peak and increases by 60%. The uncertainty of the permeability distribution is resulted from the deviation of the hydraulic fracture. As the deviation angle increases from 0° to 10°, shale gas production drops by 16%. The greater the gas production, the bigger the drop rate. When the hydraulic fracture half-length is 50 m, gas production reaches its peak, however it drops by 13% if the hydraulic fracture half-length increases to 70 m.

Permeability is a crucial parameter determining methane gas recovery. Hydrate reformation has a significant impact on reservoir permeability during methane hydrate (MH) exploitation and it is often ignored. In this paper, the effect of hydrate reformation on gas permeability was investigated by remolded cores with different hydrate saturations and effective stresses. The results show that hydrate reformation exacerbates the heterogeneous distribution and reduces the reservoir permeability. The permeability damage rate (PDR) of hydrate reformation is greater than the hydrate first formation owing to the inhomogeneity of water caused by hydrate decomposition. When hydrate saturation is increased from 22.26% to 40.44%, the PDR range caused by hydrate formation varies from 19.89% to 98.02%. In addition, the permeability after hydrate decomposition decreases with increasing effective stress. When the effective stress is absent or small, the permeability after secondary decomposition is lower than the first decomposition at the same hydrate saturation. However, the opposite is true when the effective stress is reached 3 MPa. Due to the memory effect of MH in marine sediments, the hydrate reformation induction time is shorter and the reformation rate is faster. However, the gas consumption of the hydrate reformation is less than the first, causing lower hydrate saturation. This work supports the exploitation of gas hydrate and numerical simulation studies in marine sediments.

Quantification of methane content in shales is a critical parameter for estimation of their potential gas production capacity. Traditional gravimetric methods for estimation of this quantity are sensitive only to adsorbed methane and are difficult to apply either to intact shale rock cores or via field measurements. Here non-invasive low-field nuclear magnetic resonance (LF-NMR) is applied to quantify excess methane adsorption capacity in two intact shale rock plugs at pressures up to 150 bar; validation is provided against destructive gravimetric methods performed on fragments from the same shale rock plugs. The resultant NMR transverse relaxation time (T2) distributions contain three distinct peaks (referred to as peaks P1 – P3) which are allocated to adsorbed methane in organic pores, methane constrained to inorganic pores and bulk methane located predominately in fractures, respectively. The area of peak P1 is observed to increase with pressure up to 100 bar, after which it reaches a plateau, whilst the area of peaks P2 and P3 both increase linearly with pressure up to 150 bar. The most accurate estimate of excess methane adsorption capacity is obtained via a combination of an overall system mass balance and the methane located in inorganic pores and fractures (peaks P2 and P3, respectively), where excellent agreement is produced with corresponding gravimetric measurements for both shale samples studied.

Bypass pigging technology is an emerging strategy with promising potential to reduce the velocity of pipeline inspection gauge (PIG) and mitigate pigging-induced slug volume for oil and gas transportation systems. Nonetheless, the critical issue of bypass pigs being blocked in pipelines is a major concern for wide implementations of this new technology. To this end, this study newly proposes an intelligent self-regulated bypass pig prototype by developing an internal bypass regulating module to enhance the anti-blocking capability for pigging operations. To facilitate the optimal design of the bypass regulating module, force variation characteristics of the bypass valve in blocked bypass pigs are of great significance. Accordingly, this study thoroughly investigates bypass valve forces for bypass pigging under the blockage status both experimentally and numerically. The experimental results show that an increase in gas velocity can almost linearly increase the valve force, which is mainly affected by the driving gas flow rate. Specifically, when the gas velocity increases from 1.26 to 4.4 m/s, the valve force can be increased from 1.46 to 12.88 N on average. In addition, a CFD-based numerical model was developed and experimentally validated to calculate valve forces. The numerical model, which has the mean bias error below −0.886 N with the index of agreement over 0.98, can be used as an effective approach to valve force analyses. Finally, the optimal design scheme for bypass pigging with anti-blocking capability was proposed, which can considerably facilitate the secure and efficient pigging performance and natural gas transportation.

The present research explores the differences in induction time between methane and carbon dioxide hydrates. This parameter was calculated by considering the heat released during the formation of hydrates. Being the process exothermic, the heat released, in conjunction with the enthalpy of formation, allowed to calculate the quantity of hydrates formed as soon as the process became detectable. This information was then combined with the measure of time to define the induction period. The procedure was selected in order to avoid possible errors related to the dissolution of carbon dioxide in water, which may affect the accuracy of detection. It was found that the induction time is significantly longer for carbon dioxide hydrates. It can be explained with the non-hydrophobicity of the molecule and with the higher Gibbs free energy barrier which must be overcome to produce the first nuclei of CO2 hydrates. The reliability of the proposed method was verified by evaluating the gas absorption over time for methane, whose dissolution in water can be considered negligible. Finally, it was proved that, after the formation of the first conglomerates, the growth of carbon dioxide hydrates is faster than that of methane hydrates, due to the higher degree of mixing between water and gas molecules within the whole formation environment.

Continuous flaring of natural gas remains a great environmental threatening practice going on in most upstream hydrocarbon production industry across the globe. About 150 billion m3 of natural gas are flared annually, producing approximately 400 million tons of carbon dioxide alone among other greenhouse gases. A search into a viable method for natural gas conversion to methanol becomes imperative not only to save the soul of the ever-changing climate but also to bring an end to wastage of valuable resources by converting hitherto wasted natural gas to wealth. Currently the technologies of conversion of natural gas to methanol could be categorized into the conventional and the innovative technologies. The conventional technology is sub-divided into the indirect method also called the Fischer-Tropsch Synthesis (FTS) method and the direct method. The major commercial technology currently in use for production of methanol from methane is the FTS method which involves basically two steps which are the steam reforming and the syngas hydrogenation steps. The FTS method is highly energy intensive and this is a factor responsible for its low energetic efficiency. The direct conversion of methane to methanol is a one-step partial oxidation and lower temperature method having higher energetic efficiency advantage over the FTS method. The direct method occurs at temperature range of 380–470 °C and pressure range of 1–5 MPa while the FTS occurs at temperature range of 700–1100 °C and atmospheric pressure. Both methods are carried out under effect of metallic oxide catalysts such as Mo, V, Cr, Bi, Cu, Zn, etc. The innovative methods which include electrochemical, solar and plasma irradiation methods can be described as an approach to either of the two conventional methods in an innovative way while the biological method is a natural process driven by methane monooxygenase (MMO) enzyme released by methanotrophic bacteria. The aim of this study is to review the current state of the technology for conversion of methane to methanol so as to make abreast the recent advances and challenges in the area.

Matrix shrinkage is a factor that must be considered in the dynamic permeability model of coal reservoirs. The mechanism of matrix shrinkage affecting confining pressure (confining pressure mechanism) has been modeled by analogy with thermal expansion, and it is widely used in permeability model construction. However, the mechanism of matrix shrinkage affecting porosity (porosity mechanism) has not been widely recognized and modeled, and this mechanism independently controls porosity even though neither confining pressure nor pore pressure changes (only the replacement of different adsorbed gases occurs). The porosity mechanism and a permeability model that takes into account the dual mechanism have been modeled recently. This study compares the two mechanisms of matrix shrinkage by theoretical analysis of the mathematic relations in the permeability models considering different mechanisms and by finite element numerical simulations of coalbed methane development considering different mechanisms. Theoretical analysis shows that the effect of the porosity mechanism on permeability is more than 1.5 times that of the confining pressure mechanism. the numerical simulations results show that: considering the porosity mechanism and the confining pressure mechanism simultaneously allows for a larger and earlier improvement in permeability and a larger reservoir area to improve, and a significant improvement of 28% in gas production rate occurs compared with the case only the confining pressure mechanism were considered. This study reveals the importance of porosity mechanism in describing the dynamic evolution of reservoir permeability and production dynamics accurately, and provides a scientific basis for coalbed methane development.

An economy based on hydrogen is widely regarded as the potential successor of the fossil-fuel-driven present energy sector. One major obstacle in developing the hydrogen economy is the suitable storage systems for different applications. This article presents an overview of the role of different storage technologies in successfully developing the hydrogen economy. It reviews the present state of various hydrogen storage systems from the surface and underground storage methods, their applications, and the associated scientific challenges. The integration of renewable energy in existing energy infrastructure requires developing suitable storage solutions along the energy supply chain. Large-scale seasonal hydrogen storage can be achieved through a subsurface geologic medium such as salt caverns, depleted hydrocarbon reservoirs, aquifers and hard rock caverns. The suitability of the geostructures depends on the desired storage cycles, capacities, and purity of stored hydrogen. The storage of hydrogen for stationary and mobile applications according to end user demands, generally less in capacity and requiring rapid storage cycles, is facilitated by surface storage methods. The physical storage of hydrogen is trapping it in vessels in its different physical states, such as compressed gaseous, cryogenic and cryo-compressed forms. Material-based storage of hydrogen is by adsorbing or absorbing hydrogen using solid-state materials. The performance of surface storage technics is characterized by gravimetric and volumetric densities, storage uptake and release kinetics, the cost involved, and operational safety. The technical insights of each storage technology are presented with recommendations and relevant fields of applications. No storage technic in its ideal conditions can be considered the best fit for all the applications, and each technic requires intense work to become acceptable for energy application.

The cement sheath of CCUS well is vulnerable to carbonization corrosion upon protracted exposure to a CO2-rich setting, which reduces the strength of the cement sheath and increases the porosity, eventually leading to CO2 leakage. Predicting the carbonation depth and regularity of the cement sheath of CO2 injection wells allows an estimation of the service life , to ensure safe operation of CO2 injection wells. However, most of the current prediction models for CO2 corrosion depth are still semi-empirical models, which are fitted to experimental data but are not universally applicable. This may be resolved by our CO2 corrosion depth prediction model supported by the law of mass conservation, diffusion convection equation, and calcium precipitation rate. The influence of seven factors on the corrosion depth was analyzed and ranked. The rise in corrosion time, temperature, chloride ion content, CO2 partial pressure, water-cement ratio, and water saturation increases corrosion depth and CO2 content, in addition to porosity and permeability, while increasingly corrosion-resistant material causes the opposite effect. The cement sheath begins to be seriously corroded by CO2 partial pressure exceeding 10 MPa, chloride ion content over 0.20 mol/L, or temperature higher than 70 °C. Water saturation significantly affects corrosion, and the CO2 corrosion depth at 0.8 is 10.16 times that at 0.6. The CO2 content at the distance of 0.2 m–0.93 m from the corroded end surface basically does not change after 7 years of corrosion. Water-cement ratio increased to 0.48 provides conditions for a large amount of CO2 accumulation in the cement sheath. The addition of corrosion-resistant materials can reduce the initial porosity and permeability of cement sheath. The seven factors is ranked in descending order of influence as water saturation, corrosion-resistant material, water-cement ratio, CO2 partial pressure, corrosion time, chloride ion content, and temperature.

Tight shale reservoirs exhibit high heterogeneity and strong anisotropy in multiscale pore/fracture networks, with highly variable properties. The local equilibrium or non-equilibrium states vary spatially and are strongly controlled by the gas transport modes at each scale. A fundamental understanding of the coupling effects of gas flow in heterogeneous porous media with arbitrary scale ratios is crucial but not yet available. Here, we systematically and theoretically study the gas transport modes and gas flow velocity in multiscale matrix-fracture systems using the asymptotic homogenization method. A series of exact scaling laws for the gas velocity in heterogeneous porous media with arbitrary multiscale configurations are established, and the local equilibrium/non-equilibrium effects at each scale are analyzed in detail. It is shown that the gas transport modes between two adjacent porous media can be classified into four distinct types governed by two characteristic time scales (rather than two types as commonly reported). We demonstrate an ultrahigh pressure gradient in a thin depressurized zone in the matrix that can reach 103∼105 times the macroscopic pressure gradient, greatly increasing gas flow rates by three to five orders of magnitude. The hydraulically-created fractures not only provide preferential flow pathways, but more importantly, they increase the gas velocity in the matrix (which does not contain any fractures) by several orders of magnitude. The work also sheds light on the discrepancy between the observed high gas production and the experimentally measured low permeability in drilled cores.