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Understanding the conversion characteristics of pore water is crucial for investigating the mechanism of hydrate accumulation; however, research in this area remains limited. This study conducted methane hydrate formation experiments in unconsolidated sands using an in-house low-field nuclear magnetic resonance (NMR) system. It focused on pore water conversion characteristics and influencing factors such as initial water saturation and sand particle sizes. Results show that methane hydrate formation enhances the homogeneity of the effective pore structure within sand samples. The conversion rate of pore water is significantly influenced by differences in heat and mass transfer capacity, decreasing as initial water saturation and sand size increase. Pore water cannot be fully converted into hydrates in unconsolidated sands. The final conversion ratio of pore water in water-poor sand samples nears 97%, while in water-rich sand samples, it is only 65.80%. Sand particle size variation has a negligible impact on the final conversion ratio of pore water, with ratios exceeding 94% across different particle sizes, differing by less than 3%. [ABSTRACT FROM AUTHOR]

Understanding the conversion characteristics of pore water is crucial for investigating the mechanism of hydrate accumulation; however, research in this area remains limited. This study conducted methane hydrate formation experiments in unconsolidated sands using an in-house low-field nuclear magnetic resonance (NMR) system. It focused on pore water conversion characteristics and influencing factors such as initial water saturation and sand particle sizes. Results show that methane hydrate formation enhances the homogeneity of the effective pore structure within sand samples. The conversion rate of pore water is significantly influenced by differences in heat and mass transfer capacity, decreasing as initial water saturation and sand size increase. Pore water cannot be fully converted into hydrates in unconsolidated sands. The final conversion ratio of pore water in water-poor sand samples nears 97%, while in water-rich sand samples, it is only 65.80%. Sand particle size variation has a negligible impact on the final conversion ratio of pore water, with ratios exceeding 94% across different particle sizes, differing by less than 3%.

Polymer flooding technology has shown satisfactorily acceptable performance in improving oil recovery from unconsolidated sandstone reservoirs. The adsorption of the polymer in the pore leads to the increase of injection pressure and the decrease of suction index, which affects the effect of polymer flooding. In this article, the water and oil content of polymer blockages, which are taken from Bohai Oilfield, are measured by weighing method. In addition, the synchronous thermal analyzer and Fourier transform infrared spectroscopy (FTIR) are used to evaluate the composition and functional groups of the blockage, respectively. Then the core flooding experiments are also utilized to assess the effect of polymer plugs on reservoir properties and optimize the best degradant formulation. The results of this investigation show that the polymer adsorption in core after polymer flooding is 0.0068 g, which results in a permeability damage rate of 74.8%. The degradation ability of the agent consisting of 1% oxidizer SA-HB and 10% HCl is the best, the viscosity of the system decreases from 501.7 to 468.5 mPa‧s.

Unconsolidated sandstone has the characteristics of poor cementation, loose structure, and low intensity. It is difficult to obtain representative cores, and coring from reservoirs is expensive. Thus, artificial cores have been widely used in core flooding experiments instead of natural cores. We found that, during the process of making artificial cores, formation water has an important influence on the physical properties of artificial cores; this factor has been neglected in making of artificial cores thus far. This study investigated the influence of formation water on the cementation and pore throats of artificial cores. In this research, river sand with a similar size distribution to the reservoir samples was chosen as the granule of framework. The results show that the addition of a certain amount of formation water better controls the degree of cementation of artificial cores, and the cores do not need to expand the pores and are relatively easy to mould under the same size composition and dosage of cementing agent. This research demonstrates that formation water is a main factor in making artificial cores of unconsolidated sandstone by comparing parameters such as the porosity, permeability, method of cementing, cementation exponent, and seepage characteristics of natural and artificial cores. The cementation, porosity, and permeability of artificial cores with formation water are better, and the cores have high similarity with natural cores. Consequently, the artificial cores can be used in laboratory experiments instead of natural cores. [ABSTRACT FROM AUTHOR]

The prediction of effective elastic properties of a granular medium using ultrasonic data based on contact models has been studied widely in both laboratory experiments and numerical simulations. In contrast, a calculation of the elastic properties of the constituent grains using similar data by inverting the equations from those models is a rather new concept. To do so, we have developed a controlled experiment technique that includes a uniaxial compaction test and measures ultrasonic velocities of four unconsolidated quartz sand samples with different sorting and grain shapes. We observe that both P‐ and S‐wave velocities are significantly influenced by the microstructure or internal arrangement of the grains. Well sorted and more spherical and rounded samples show higher velocities than the poorly sorted and less spherical and rounded samples. A microstructural parameter – namely coordination number – we have calculated from high resolution micro computed tomography images provides a good match between the model and dynamic effective bulk moduli of the sand pack. Combining this coordination number with a frictional parameter calculated from the measured velocity ratios has been very effective to fit the model with the dynamic effective shear moduli. Using these two key parameters along with the experiment results in the contact model we have been able to obtain the elastic parameters of the quartz sand grains in the sample. Elastic parameters obtained thus are very close to the actual values of the quartz grains found in the literature. This technique can be useful in hard rock mineral exploration where missing core samples or an absence of well logs can be replaced by laboratory measurements of powders to find the elasticity or velocities of the rocks. Moreover, the elastic properties of the solid phase calculated using this technique can be used as input parameters for the fluid substitution and rock physics characterization of unconsolidated reservoir sands. [ABSTRACT FROM AUTHOR]

Unconsolidated sands often appear as places of unconventional resources under development, but the mechanisms of phenomena occurring during development, such as sand production and hydraulic fracturing, are not well understood yet. This paper experimentally examined the fracture phenomenon accompanying fracturing. To this end, a method to simulate hydraulic fracturing of unconsolidated strata in laboratory experiment was constructed. In the experiments using a specimen made from a mixture of silica sand and kaolin and a fracturing fluid of machine oil, a linearly extending fracture was formed similarly to the case of hard rocks when the proportion of kaolin was large. However, when the proportion of kaolin is small, fracture was not formed at all. This phenomenon can be interpreted if the fracture is formed by compressive deformation/failure, which is completely different from conventional theory of hydraulic fracturing. That is, since tensile force is not transmitted in unconsolidated sands, gaps are created by pushing the part where the fluid pressure acts and the grains in the vicinity thereof. Also, in the mixture of silica sand and kaolin, as the proportion of kaolin decreases, the interlocking between the grains improves and compressive deformation/failure hardly occurs, so it is considered difficult to form gaps/fracture in hydraulic fracturing. [ABSTRACT FROM AUTHOR]

The effects exerted by the adsorption of vapors of a non-polar compound (deuterated benzene) and a polar compound (water) on the surface of Ottawa sand and a sample of reservoir sand (Channel), which was previously impregnated with silicon oil or two kinds of surfactants, (2-hydroxyethyl) trimethylammonium oleate (HETAO) and (2-hydroxyethyl)trimethylammonium azelate (HETAA), were studied by diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) and thermogravimetric analysis (TGA). The surface chemistry of the sandstone rocks was elucidated by X-ray photoelectron spectroscopy (XPS) and scanning electron microscopy (SEM) with energy dispersive X-ray spectroscopy (EDX). Terminal surface groups such as hydroxyls can strongly adsorb molecules that interact with these surface groups (surfactants), resulting in a wettability change. The wettability change effect suffered by the surface after treating it with surfactants was possible to be detected by the DRIFTS technique, wherein it was observed that the surface became more hydrophobic after being treated with silicon oil and HETAO; the surface became more hydrophilic after treating it with HETAA. [ABSTRACT FROM AUTHOR]

To properly understand seismic wave propagation in unconsolidated sand layers, it is important to estimate the parameters of their continuous velocity-depth functions. This study proposes a procedure to estimate the V and k parameters of a specific velocity function, where V is the direct P-wave velocity at the ground surface and k is the velocity gradient. The V and k parameters are generally independent of each other. However, it is possible to relate them numerically because both depend strongly on the porosity (ϕ) and water saturation ( S). The proposed procedure starts by tabulating V and k for 0.05 ≤ ϕ ≤ 0.5 sampled at Δϕ = 0.05 and S = 0.6, so that only V is needed for fitting. Then, time-distance (T-X) type curves of the direct arrival are calculated for the corresponding values of V and k parameters values. The type curves are fitted then to the observed shot gather through a modification of the classic semblance velocity analysis method. Once the best-fit V value is found, the corresponding k, ϕ, and S values are picked from a V- k-ϕ lookup table. The procedure is applied on synthetic shot gathers with various amounts of additive Gaussian random noise. Results show that the method is robust and tolerant to low to moderate amounts of noise. [ABSTRACT FROM AUTHOR]

Electrical resistivity measurements of reservoir rocks are usually applied to identify fluid type and saturation. Although it has been widely studied, the effect of fluid saturation on electrical resistivity is not yet fully understood, especially when considering the spatial distribution of fluids. Hysteresis and electrical resistivity jump in the imbibition process are two of the phenomena that remain unclear. Microscopical evaluation would be useful in understanding these phenomena. In this paper, we analyzed the influence of the micro-spatial distribution of fluids on electrical resistivity. In order to achieve the objective, laboratory measurements and computer modeling of electrical resistivity were carried out. Measurements were made on unconsolidated sand samples that were saturated with brine. Two categories of samples were prepared based on the position of the brine injection to obtain fluid spatial distribution variations in rock pores. Measurement results showed that the electrical resistivity varies depending on the brine injection position. Subsequently, 3-D microcomputed tomography images were acquired to analyze sample microstructure and model fluid spatial distribution. We implemented three different saturation models made up of varying fluid filling mechanisms onto digital images of samples, then used them to compute the electrical resistivity of the sub-sample using the finite element method. The measurement and calculation of electrical resistivity showed good agreement. These results indicate that the proposed model is capable of representing spatial fluid distribution in pore spaces of measured samples. This fluid distribution is most responsible for the variation of the electrical resistivity in the samples. Furthermore, the electrical resistivity jump phenomenon in the imbibition process was successfully explained through the proposed model. Based on this study's results, it can be concluded that the spatial distribution of fluids needs to be considered in the estimation of electrical resistivity. The research findings provide insight into how micro-spatial distribution affects electrical properties of rocks of importance to the interpretation of electrical resistivity data. • The fluid spatial distribution is crucial in estimation of electrical resistivity. • A new saturation model can explain the imbibition data. • The electrical resistivity jump can be clarified by our proposed model. • The Digital Rock Physics method is effective for analyzing porous medium. [ABSTRACT FROM AUTHOR]

High fluid leak-off rate and low pressurization rate are great challenges for hydraulic fracturing in unconsolidated sands. In this paper, the design of an injection plugging agent as a pad for fracture initiation aid in unconsolidated sands is presented. We have carried out tri-axial hydraulic fracturing tests, focusing on super-high- and high-permeability unconsolidated sands with AE (acoustic emission) monitoring. Powdered oil-soluble materials are used as temporary plugging agents. The laboratory tests demonstrated that three types of fracture geometry, multiple fracture, bi-wing fracture and single-wing fracture, are created. Furthermore, there are continuous AE energy signals with the increase of plugging agent injection, which is a good match with the fluctuated pressure. Moreover, multiple peak fracture points can be observed due to intense grains interaction. In addition, the breakdown pressure has positive relationships with the pump rate and concentration of injection of plugging agents. Multiple fractures only exist for super-high-permeability unconsolidated sands with high pumping rate and low plugging agent concentration, which is primarily due to the plugging agent seal for both hydraulic fracture and the rock matrix. A low injection rate with low plugging agent concentration led to single-wing fracture for high-permeability unconsolidated sands, whereas a high injection rate with high plugging agent concentration led to single-wing fracture for low-permeability unconsolidated sands. Low plugging agent concentration is beneficial for aiding hydraulic fracture propagation along the maximum horizontal stress direction. In addition, the high-pump-rate and low-plugging-agent-concentration scenario and low-pump-rate and high-plugging-agent-concentration scenario have a greater chance of creating bi-wing fracture for super-high-permeability unconsolidated sands, whereas low pump rate and high plugging agent concentration are beneficial for bi-wing fracture for high-permeability unconsolidated sands. Local tortuous fracture path indicate tensile and fracture both exist during unconsolidated sands fracturing. With respect to sand control and large contact area, these treatments should be the better fracturing scenario for unconsolidated sand fracturing design with injection of a plugging agent. The findings of this study can help for better understanding of the fracturing mechanism and optimizing treatment parameters in unconsolidated sands fracturing. • We offer an approach to assist hydraulic fracture initiation on unconsolidated sands. • We perform tri-axial fracturing tests on unconsolidated sands with plugging agent as pad. • The fracture geometry with different agent injection scenarios is compared. [ABSTRACT FROM AUTHOR]