Seismic data and nuclear magnetic resonance (NMR) data are two of the highly trustable kinds of information in hydrocarbon reservoir engineering. Reservoir fluids influence the elastic wave velocity and also determine the NMR response of the reservoir. The current study investigates different pore types, i.e., micro, meso, and macropores’ contribution to the elastic wave velocity using the laboratory NMR and elastic experiments on coal core samples under different fluid saturations. Once a meaningful relationship was observed in the lab, the idea was applied in the field scale and the NMR transverse relaxation time (T2) curves were synthesized artificially. This task was done by dividing the area under the T2 curve into eight porosity bins and estimating each bin’s value from the seismic attributes using neural networks (NN). Moreover, the functionality of two statistical ensembles, i.e., Bag and LSBoost, was investigated as an alternative tool to conventional estimation techniques of the petrophysical characteristics; and the results were compared with those from a deep learning network. Herein, NMR permeability was used as the estimation target and porosity was used as a benchmark to assess the reliability of the models. The final results indicated that by using the incremental porosity under the T2 curve, this curve could be synthesized using the seismic attributes. The results also proved the functionality of the selected statistical ensembles as reliable tools in the petrophysical characterization of the hydrocarbon reservoirs.

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Clay minerals significantly alter the pore size distribution (PSD) of the gas hydrate-bearing sediments and sandstone reservoir rock by adding an intense amount of micropores to the existing intragranular pore space. Therefore, in the present study, the internal pore space of various clay groups is investigated by manually segmenting Scanning Electron Microscopy (SEM) images. We focused on kaolinite, smectite, chlorite, and dissolution holes and characterized their specific pore space using fractal geometry theory and parameters such as pore count, pore size distribution, area, perimeter, circularity, and density. Herein, the fractal properties of different clay groups and dissolution holes were extracted using the box counting technique and were introduced for each group. It was observed that the presence of clays complicates the original PSD of the reservoir by adding about 1.31-61.30 pores/100 μm2 with sizes in the range of 0.003-87.69 μm2. Meanwhile, dissolution holes complicate the pore space by adding 4.88-8.17 extra pores/100 μm2 with sizes in the range of 0.06-119.75 μm2. The fractal dimension ( D ) and lacunarity ( L ) values of the clays’ internal pore structure fell in the ranges of 1.51-1.85 and 0.18-0.99, respectively. Likewise, D and L of the dissolution holes were in the ranges of, respectively, 1.63-1.65 and 0.56-0.62. The obtained results of the present study lay the foundation for developing improved fractal models of the reservoir properties which would help to better understand the fluid flow, irreducible fluid saturation, and capillary pressure. These issues are of significant importance for reservoir quality and calculating the accurate amount of producible oil and gas.

Methane hydrate (MH) dissociation will decrease the strength of methane hydrate-bearing sediments (MHBSs) and induce the deformation of the submarine sediment. Considering that such deformation could trigger the submarine landslide during the gas production, it is essential to understand it correctly. However, few studies have investigated a MH exploitation of what scale could affect the submarine slope stability and sand production near the wellbore. The present study adopted the numerical simulation approach where a thermal-fluid-mechanical coupled model was established. Then, the deformation response of a marine slope was analyzed considering the influence of the slope angle, the cyclic loading condition, and the decompression amplitude condition, during MH exploitation. Depressurization in a vertical well was used as the exploitation technique. According to the obtained results, when the slope angle is horizontal, the MHBS layer and the upper sediment layer deform around the wellbore symmetrically; the deformation degree increases and deformation distribution expands with the increase in loading amplitude and decompression amplitude. The exceeding pore water pressure in the upper sediment layer increases more significantly with the increase in loading amplitude. The MH regeneration area will be formed more efficiently with the increase in loading amplitude. The higher the decompression amplitude is, the wider the MH dissociation area will be. It was also found that sand production always starts on the upper and the bottom sections of the MHBS layer around the wellbore, and the predicted distance of sand production increases with the increase in mining time. The research results lay the theoretical foundation for the accurate understanding of the MHBS layer as well as the marine sediments’ stability and sand production during natural gas production from MH reservoirs.