Journal of Natural Gas Science and Engineering最新文献

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.

Marine gas hydrate always occurs in clayey silt sediments partially or fully saturated with water. Pore water is involved in gas hydrate formation and decomposition, which plays an important role in gas recovery from hydrate during depressurization. In this work, the depressurization of methane hydrate in the clayey silt sediments was experimentally investigated in a one-dimensional reactor. The variation of gas production and pressure gradient under the gas-rich and water-rich condition were studied. It was found that the gas production in water-rich environment was much lower than that in gas-rich environment as the movement of hydrate dissociating front is slower in water-rich environment. The permeability of the clayey silt sediments was measured before hydrate formation and after hydrate decomposition, which indicated that there was a large depression in the permeability of the clayey silt sediments after hydrate decomposition, which could be attributed to the hydration swelling of clay minerals with the expansion of diffuse double layer caused by the release of water with lower salinity from gas hydrate dissociation. And the permeability depression of the clayey silt sediments caused by hydrate decomposition was more obvious in water-rich environment, reaching up to ∼50%, and increased with the content of clay minerals. In addition, inorganic salt-based clay stabilizer solution was pre-injected into the clayey silt gas hydrate-bearing sediments before depressurization to mitigate the formation damage during gas hydrate production. The results showed the permeability of the sediments pre-saturated with NH₄Cl was maintained at ∼75% of the initial values after gas hydrate decomposition as the exchange of Na⁺ with NH₄⁺ in sediments was proved to decrease the bound water in montmorillonite interlayers by NMR analysis and inhibit the hydration swelling of clay particles.

Porous flow is typically analyzed by the Kozeny–Carman equation using geometric variables, such as hydraulic diameter and tortuosity. The hydraulic tortuosity was first described by Kozeny, and later redefined by Carman as the tortuosity square term in the Kozeny–Carman equation. However, the revised term correlating the flow velocity with path length square would be physically ambiguous. Moreover, the hydraulic diameter, which is directly correlated to the permeability and interstitial velocity in the Kozeny–Carman equation, is an isotropic constant property; thus, it should be verified whether the isotropic hydraulic diameter can reasonably correlate each anisotropic directional flow feature passing through heterogeneous complex media. Accordingly, the Kozeny–Carman equation was theoretically examined and experimentally verified in this study to obtain the proper correlation based on the definitions of truly equivalent diameter and tortuosity. Therefore, the effective variables of porous media were presented, and it confirmed that the effective diameter corresponded to the physically equivalent diameter of anisotropic porous media. Moreover, using the mass conservation relation, it was verified that Kozeny's tortuosity is exactly associated with the truly equivalent flow model, and then the Kozeny constant must be differently defined from the original Kozeny equation. Accordingly, the Kozeny–Carman equation was improved by appertaining either effective diameter or tortuosity, and the momentum conservation relation was used to verify it. The pore-scale simulations using 5-sorts of 25-series porous media models were performed to test the validity of derived effective variables and revised equations. Finally, the alternative flow model of anisotropic porous media was presented using equivalent geometric and frictional flow variables. Subsequently, their practical and more accurate estimations were achieved by introducing the concentric annulus flow model under the special hydraulic condition. The new variables and relations are expected to be usefully applied to various porous flow analyses, such as interstitial velocity estimations, geometric condition variations, flow regime changes, and anisotropic heat and multiphase flows.

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 ${10}^3\sim {10}^5$ 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.

Acid stimulation is commonly used for carbonate reservoirs to enhance wells’ productivity by creating highly conductive channels called wormholes. The success of the stimulation depends on how deep these channels penetrate the formation. Hydrochloric acid (HCl) is commonly used for the carbonate stimulation process with carbon dioxide (CO₂) as a byproduct of the reaction between HCl and calcium carbonate (CaCO₃). Depending on the operating temperature and pressure, CO₂ can form a gaseous phase (bubbles) or be dissolved completely in the fluid. To achieve an understanding of the effect of CO₂ bubble formation on wormhole development, we used a low acid concentration (not more than 1 wt% HCl) at a range of flow rates. In this study, an elevated back pressure of 8.2 MPa is applied to keep the CO₂ dissolved in the solution and then compared with another set of experiments where no back pressure is applied. Sensitivity runs on various back pressures (while keeping all other parameters constant) are conducted to acquire a detailed understanding of the wormhole behaviour at a range of back pressures (0.1, 2.7, 5.5 and 8.2 MPa). We test the results in the dissolution phase space of Peclet and Damköhler dimensionless numbers. Although we show that for constant flow rate conditions, the existence of gaseous CO₂ significantly increases the pressure prior to the wormhole breakthrough, surprisingly no noticeable effect on the wormhole initiation process itself was found.

CO₂ intrusion has a crucial effect on the pore structure of mineral-bearing coal. In this study, we selected long flame coal, lean coal, and anthracite after CO₂ adsorption at different pressures and tested the coal samples using X-ray diffraction, mercury intrusion porosimetry, and N₂ (77 K) adsorption methods. The tests were conducted to determine the variations in mineral content, pore structure, and fractal characteristics. The results showed that supercritical CO₂ had a greater ability to dissolve minerals in coal than that of subcritical CO₂. Although the total pore volume and BET specific surface area gradually increased with the increase in CO₂ intrusion pressure in coal, the transformation of different pores and partial new pores caused by the dissolution of minerals and the adsorption swelling of coal matrix caused the micro-macropores in the three coal samples to exhibit different trends. The pore surface roughness and pore structure complexity of seepage pore in the long-flame coal after CO₂ adsorption increased while those of the lean coal and anthracite decreased. Meanwhile, CO₂ intrusion caused the surface of the adsorption pore in coal to become smooth, and the pore structure was more regular, except for the lean coal. A conceptual model of the mineral-bearing coal was developed to describe the relationship between the mineral composition and pore structure induced by CO₂ intrusion. These findings help to understand the transformation effect of CO₂ on coal seams. Thus, a higher CO₂ injection pressure should be used to obtain a larger injection volume and shorter injection time during CO₂ storage implementation.

In this study, an in situ synchrotron radiation small-angle X-ray scattering (SAXS) experiment is used to characterize the evolution of coal nanopore structures under uniaxial compression. The variation in the coal nanopores is measured by analyzing the obtained scattering data. From the results, the coal scattering data show a positive Porod deviation in which the deviation slope decreases with increasing stress. Smaller nanopores are more sensitive to uniaxial compressive stress. There is a positive correlation between scattering intensity I and stress at less than 30 nm. The scattering intensity I of pores larger than 30 nm is negatively correlated with uniaxial compressive stress. The structure of smaller pores is more complex. The surface fractal dimension D_S and pore fractal dimension D_P increases and decreases with increasing uniaxial compressive stress, respectively. The specific surface area is positively correlated with D_S. In the measuring range of 3–80 nm, the coal nanopores show a bimodal distribution. At the stage of below 0.6σ_p, the average diameter decreases by 1.98%, the porosity and specific surface area increases by 6.21% and 31.5%, respectively; At the stage of above 0.6σ_p, the average diameter decreases by 1.04%, the porosity and specific surface area increases by 1.18% and 5.57%, respectively. These results suggest that the variation of coal nanopores with stress have phased characteristics, and the evolution of the coal nanopores under uniaxial stress can be divided into two stages. In the nanopore fracture stage, the nanopores are deform, fracture and create new smaller pores with increasing stress, and the roughness of pore surface increase. In the nanopore closure stage, high stress intensifies the degree of pore fracture, and nanopores begin to close and disappear. This study reveals the evolution characteristics of the pore structures of coal under uniaxial compression at the nanoscale.

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.

Liquid surge refers to an excessive liquid inflow to a slug catcher or a separator and is one of the main issues in flow assurance. The wellhead choke valves of gas wells must be adjusted to maintain the target flow rate as the reservoir pressure drops. The wellhead choke opening can be determined by conducting multiphase pipeline transient flow simulations to achieve the target flow rate and avoid liquid surges. However, it is not financially and computationally practical to conduct many multiphase transient pipeline flow simulations simultaneously for hundreds of wells. We found that flow rates and maximum liquid surge volumes for gas wells can be predicted accurately using simple machine learning models when the wellhead choke valve is adjusted. The machine learning models provided accurate predictions (R² > 0.99) regarding flow rates and maximum liquid surge volumes for different wellhead pressure drop plans, vertical and horizontal well lengths, and current operating conditions in cases involving two real fields, the Horn River Basin (HRB) and Rakhine Basin field. The wellhead operating conditions that are appropriate for achieving the target flow rate and avoiding liquid surges can be efficiently determined using the machine learning models instead of multiphase transient pipeline flow simulators. The proposed approach also accurately estimated downhole pressures that are necessary to evaluate reservoir performances given wellhead pressures and flow rates. Lastly, we presented what features are dominant in predicting liquid surge volumes, flow rates, and downhole pressures in feature importance analyses.

Natural gas hydrate is a strategic alternative energy source which are widely founded in seabed sediments. The study of the mechanical properties of hydrate-bearing sediments is the key content to ensure the safe exploitation of gas hydrate. Hydrate occurring mechanisms and saturation are important factors affecting the mechanical properties of hydrate-bearing sediments. In this work, simplified discrete element models that consider the hydrate occurring mechanism, hydrate saturation and confining pressure, were generated based on PFC code. Three main hydrate occurring mechanisms including pore filling, load bearing and cementation were characterized. The triaxial compression simulation was then conducted to investigate the model mechanical properties. The results show that the hydrate of cementation mode has the most obvious strength-enhancing effect on sediments, followed by the load bearing model and pore filling model. Hydrate occurring mechanism also affect the increasing trend of sediment strength and deformation modulus with hydrate saturation and confining pressure. The influence of hydrate occurrence mechanism on the mechanical behavior of sediment is largely controlled by the interaction between hydrate and sand particles interface. The hydrate of cementation mode increases the cohesion of the sediment particles, the hydrate of pore filling mode increases the friction between particles, and the hydrate of load bearing mode has the combined effects of the above two.