Geofluids
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Acceptance rate33%
Submission to final decision85 days
Acceptance to publication41 days
CiteScore1.850
Impact Factor1.437
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Relationship between Tectonism and Composition and Pore Characteristics of Shale Reservoirs

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Geofluids publishes research relating to the role of fluids in mineralogical, chemical, and structural evolution of the Earth’s crust.

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Research Article

Quantitative Study on the Contact Force and Force Chain Characteristics of Ore Particle Systems during Ore Drawing from a Single Drawpoint under the Influence of a Flexible Barrier

It is of great significance to carry out quantitative research on the contact force chain characteristics of ore particle systems during ore drawing to reveal the microscopic and mesoscopic characteristics of ore particle systems during implementation of the synchronous filling shrinkage stoping method. Based on the particle discrete element method, combined with the relevant knowledge of contact mechanics and statistical mechanics, microscopic properties of the ore particle system were studied quantitatively. (1) The probability distributions of the normal and tangential contact forces during ore drawing from a single drawpoint under a flexible barrier are similar, and both show exponential decay. (2) In the regions on both sides of the model, the ore particles will not be released because they are far from the drawpoint; there, the coordination number is stable, and the density of contact network is large. In the upper part of the drawpoint, ore particles flow, the coordination number fluctuates violently, and the density of contact network is small. (3) In the initial stage, the stress distribution of the ore particle system is uniform, and the strong force chain does not show obvious directivity. After that, the directions of the strong force chains in the ore particle system are inclined to the vertical direction, and the strong force chains mainly bear the load in the vertical direction. (4) In the initial stage of drawing, the normal contact force is mainly concentrated in the vertical direction. With the progression of drawing, the normal contact force at an angle of 30° to the horizontal direction increases gradually, and the number of the main direction of the average contact force distribution changes from one to three (the vertical direction and the direction with a ±30° angle to the horizontal direction).

Research Article

Study on the Permeability Evolution and Its Formation Mechanism of Xiaojihan Aquifer Coal Seam under Plastic Flow

Study on permeability evolution of an aquifer coal seam in Western China is of great significance for preventing water inrush disaster and realizing water-conserving coal mining. The permeability evolution of an aquifer coal seam is related to a loading path closely under plastic flow. In this work, permeability variations of the Xiaojihan water-bearing coal seam and Longde nonwater coal seam are researched using a transient method under plastic flow. The experiment results indicated the following: (1) Under the same axial strain, the permeability, relative residual strain, and confining pressure influence coefficient of Xiaojihan coal specimens all decrease in plastic flow with the increase of loading-unloading times and confining pressure, while the permeability recovery coefficient increases during this process. (2) The permeability of Xiaojihan water-bearing coal specimens decreases with the growth of axial strain in plastic flow, resulting in the increase of relative residual strain and reinforcement of plasticity. Besides, the confining pressure influence coefficient decreases and the permeability recovery coefficient decreases slightly with the axial strain. (3) Finally, the permeability of Xiaojihan coal specimens is greater than that of Longde coal specimens, while the confining pressure influence coefficient and permeability recovery coefficient of Longde coal specimens are greater than those of Xiaojihan coal specimens. The closure rate of internal cracks of the water-bearing coal specimen is lower than that of the nonwater coal specimen, which is beneficial for water storage and transport.

Research Article

Dispersion and Intersection of Hydrothermal Plumes in the Manus Back-Arc Basin, Western Pacific

The composition of hydrothermal plumes reflects the physical and chemical characteristics of seafloor hydrothermal fluids, which in turn reflects the host rock and subseafloor reaction conditions as well as the water column processes that act to alter the plumes as they disperse and age. Here, we show that the turbidity, current, pH value, dissolved Fe (dFe), and dissolved Mn (dMn) compositions of hydrothermal plumes can be used to understand the spatial distribution and source of hydrothermal systems in the submarine geological environment. Data were obtained from 18 hydrocast stations, among which the water column samples were collected at 8 stations during the MANUS cruise of R/V KEXUE in 2015. The results showed that the Satanic Mills plume and Fenway plume rose approximately 140 m and 220 m above the seafloor, respectively. In the Satanic Mills plume, dFe remained longer than dMn during lateral plume dispersal. There was a clear intersection of the Satanic Mills plume and Fenway plume between 1625 m and 1550 m in the PACMANUS hydrothermal field, and the varied dispersion trends of the mixed plumes were affected by current velocities at different depths. The physical and chemical properties of the seawater columns in the Manus Basin were affected by the input of high-Mn, high-Fe, and low-Mg vent fluids. The turbidity and dFe, dMn, and dissolved Mg concentrations in the sections of the plumes proximal to the Satanic Mills, Fenway, and Desmos vent sites were generally higher (turbidity, Mn, and Fe) and lower (Mg) than those in the sections of the plumes that were more distal from the vent sites. This implied that the plumes proximal to their vent fluid sources, which were interpreted to have relatively young ages, dispersed chemically over time, and their concentrations became more similar to those of the plumes that were more distal from their vent fluid sources.

Research Article

Experimental Investigation of the Dependence of Accessible Porosity and Methane Sorption Capacity of Carbonaceous Shales on Particle Size

Crushing and grinding of carbonaceous shale samples is likely to enhance the accessibility of pores and embedded organic matter as compared to the intact rock. This may lead to an overestimation of the total (volume and sorptive) gas storage capacity. In order to investigate the importance of these effects we have measured unconfined apparent grain densities (helium pycnometry) and methane sorption capacities (high-pressure methane excess sorption) of four carbonaceous shales (Cambro-Ordovician Alum Shale, Jurassic Kimmeridge Clay, Jurassic/Cretaceous Bazhenov Shale, and Late Cretaceous Eagle Ford Shale) as a function of particle size. Measurements were first conducted on 38 mm diameter core plugs, which then were crushed and milled to successively smaller particle sizes (<10 mm, <2 mm, <64 μm, and <1 μm). Apparent grain densities of the smallest particle fractions of the Alum, Bazhenov and Kimmeridge samples were consistently higher by 0.5 to 1% than apparent grain densities of the original sample plugs. Methane excess sorption capacity increased significantly for particle sizes for the Alum and <1 μm for the Bazhenov and Kimmeridge samples while no significant changes upon grinding were observed for the Eagle Ford Shale. For the Bazhenov Shale, the apparent grain density increased slightly from 2.446 g/cm3 to 2.450 g/cm3 upon particle size reduction from <64 μm to <1 μm while the maximum sorption capacity (“Langmuir volume”) increased substantially from 0.11 mmol/g to 0.19 mmol/g. Similarly, for the Kimmeridge Clay and Alum Shale, a slight increase of the apparent grain density from 1.546 g/cm3 to 1.552 g/cm3 and from 2.362 g/cm3 to 2.385 g/cm3, respectively, was accompanied by increases in sorption capacity from 0.37 mmol/g to 0.45 mmol/g and from 0.14 mmol/g to 0.185 mmol/g, respectively. The increase in sorption capacity indicates an opening of a considerable amount of micropores with large internal surface area upon physical disruption of the rock fabric and/or removal of included fluids. It may also be due to increased swelling abilities of clay minerals and organic matter upon destruction of the stabilizing rock fabric with decreasing particle size. Grain density and sorption isotherms measured on small particle sizes are likely to overestimate the gas storage capacities and the amounts of producible gas-in-place since under field conditions (largely undisrupted rock fabric), significant portions of this storage capacity are essentially inaccessible. Poor interconnectivity of the pore system and slow, diffusion-controlled transport will massively retard gas production. Based on these findings, particle sizes should be used for porosity and sorption measurements because they are more likely to retain the properties of the rock fabric in terms of accessible pore volume and sorptive storage capacity.

Research Article

Flow Unit Model of Channel Sand Body and Its Effect on Remnant Oil Distribution: A Case Study of PI Formation in the Eastern Transition Zone of Daqing Oilfield

To analyze the effect of various flow units in a channel sand body on remnant oil, we established a connection between various flow unit types and the remnant oil distribution. Using stratigraphic correlation and the characterization of sedimentary microfacies, we describe a single sand body, point bar, and narrow channel located at the injection-production well pattern of well B2-60-FB271 in the Eastern transition zone of the Daqing Placanticline. Architecture models of the point bar and narrow channel are also established using a series of parameters from different measurement methods. Four types of flow units (strong-current limiting, medium-current limiting, weak-current limiting, and none-current limiting) in the point bar sand body were identified, whereas one type, unshielded unit, was identified in the narrow channel. Geological parameters, such as porosity, permeability, and pore-throat radius (50), were optimized to quantitatively characterize these various flow units. Samples were obtained from well B2-60-FB271 and analyzed by the freeze-fluorescence thin section technique. According to the displacement degree, the microscopic remnant oil was divided into three types: (1) free-state remnant oil, (2) semi-free-state remnant oil, and (3) bound-state remnant oil. We found that the strong-current limiting flow unit in the point bar is the enrichment area of free-state microscopic remnant oil and that the medium-current limiting and weak-current limiting flow units also have relatively high free microscopic remnant oil. These constitute the remaining oil enrichment areas in the study area.

Research Article

Elastic-Impedance-Based Fluid/Porosity Term and Fracture Weaknesses Inversion in Transversely Isotropic Media with a Tilted Axis of Symmetry

The rock containing a set of tilted fractures is equivalent to a transversely isotropic (TTI) medium with a tilted axis of symmetry. To implement fluid identification and tilted fracture detection, we propose an inversion approach of utilizing seismic data to simultaneously estimate parameters that are sensitive to fluids and tilted fractures. We first derive a PP-wave reflection coefficient and elastic impedance (EI) in terms of the dip angle, fluid/porosity term, shear modulus, density, and fracture weaknesses, and we present numerical examples to demonstrate how the PP-wave reflection coefficient and EI vary with the dip angle. Based on the information of dip angle of fractures provided by geologic and well data, we propose a two-step inversion approach of utilizing azimuthal seismic data to estimate unknown parameters involving the fluid/porosity term and fracture weaknesses: (1) the constrained sparse spike inversion (CSSI) for azimuthally anisotropic EI data and (2) the estimation of unknown parameters with the low-frequency constrained regularization term. Synthetic and real data demonstrate that fluid and fracture parameters are reasonably estimated, which may help fluid identification and fracture characterization.

Geofluids
 Journal metrics
Acceptance rate33%
Submission to final decision85 days
Acceptance to publication41 days
CiteScore1.850
Impact Factor1.437
 Submit
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