Laboratory Experiments of Hydraulic Fracturing in Unconsolidated Sands

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... This result implies that hydraulic fracturing for ice in the reservoir was executed because of the pressure gradient between both wells, and the flow path with high permeability was formed, as shown in step 2 of Fig. 8. Other groups have reported that a similar tendency of the pressure change occurred when hydraulic fracturing was executed for unconsolidated porous media (Bohloli and de Pater, 2006;Ito, et al., 2008;Ito, et al., 2011). The pressure in injection well then decreased drastically to approximately 0.5 MPa in Run 1. ...
The objective of this study is to visualize the flow pattern in methane hydrate (MH) reservoir model under atmospheric pressure condition. A method to mimic a real MH reservoir was introduced into the present research to visualize the multiphase flow pattern in porous media under thermal fluid injection. First, porous media mimicking real MH reservoir were prepared in a visualization cell with dual horizontal wells, which were composed of glass beads, ice of sodium bicarbonate (NaHCO3) aqueous solution and ethanol (C2H5OH). Thereafter, hydraulic fracturing by injecting C2H5OH aqueous solution was executed to generate flow path that increases permeability between the injection well and production well. The flow pattern in the reservoir model with the flow path was then visualized during the injection of hydrochloric acid (HCl) aqueous solution. The dominant factors governing the multiphase flow in fractured porous MH mimicking reservoir were evaluated. It was found that the flow path formation with high permeability by hydraulic fracturing and permeability increment by ice melting are of critical importance for the reservoir mimicking system. In addition, it is found that the liquid phase flow may also be affected by the formation of gas phase inside the porous media that mimic the dissociation process in the real MH reservoir.
... The results suggest that microwave stimulation is more suitable for the HBS with high initial water and hydrate saturation and low absolute permeability. 21 For the last essential factor, in order to study the feasibility of in situ reservoir stimulation, Ito et al. 22,23 studied the hydraulic fracturing behavior of an HBS similitude material through a laboratory-scale physical simulation experiment. The experimental results prove the feasibility of fracturing in an unconsolidated sand−clay inter layer under different conditions. ...
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The depressurization and backfilling with in-situ supplemental heat method had been proposed to enhance the gas production of methane hydrate reservoir. This novel method is evaluated by a numerical simulator based on the finite volume method in this work. Based on the typical marine low-permeability hydrate-bearing sediments (HBS), a reservoir model with gas fracturing and CaO powder injection is constructed. The simulation results show that the stimulated fractures could effectively enhance the pressure drop effect. Moreover, the CaO injection could provide in-situ heat simultaneously. Based on the sensitivity analysis of the equivalent permeability of fractures and the mass of CaO injection, it is found that a threshold fracture permeability exists for the increasing of gas production. The gas production increases with the equivalent permeability only when the permeability is smaller than the threshold value. Meanwhile, the more CaO are injected into reservoir, the larger volume of gas production. In general, this work theoretically quantifies the potential value of the depressurization and backfilling with in-situ supplemental heat method for marine gas hydrate recovery.
Horizontal well multistage fracturing technology has potential as a technical method to improve the permeability of clayey silt natural gas hydrate (NGH) reservoirs as it can increase the contact area between a horizontal well and an NGH reservoir. Although this technology has been successfully applied to the exploitation of shale gas and coalbed methane, the relevant technical experience cannot be directly applied to clayey silt NGH reservoirs. Based on the properties of the clayey silt NGH reservoir at the SH2 site in the Shenhu area of the South China Sea, herein, we established a three-dimensional hydraulic fracturing model based on cohesive elements to analyze the influence of the fracturing fluid injection rate on the initiation and propagation of single-cluster fractures and the influence of fracture spacing on simultaneous fracturing and sequential fracturing of multi-cluster fractures. We comprehensively analyzed the distribution characteristics of fracture morphology and the phenomenon of stress interference between fractures under different conditions. The results showed that without fracture interference, fractures tend to propagate to the middle and upper parts of the reservoir owing to the low fracture propagation resistance. Simultaneous fracturing and sequential fracturing produce different staggered fracture distribution patterns, which are caused by the geostress field changing owing to the generation of fractures. Our findings broaden the understanding of hydraulic fracturing in clayey silt NGH reservoirs.
Natural gas hydrates in the Shenhu area of the South China Sea occur in clayey silt sediments, and its occurrence environment has low permeability characteristics, making it difficult to commercialise gas production from gas hydrates. A feasibility study of hydraulic fracturing and horizontal well applied to the hydrate reservoir in China's first offshore hydrate production site to increase gas production from hydrates was done. According to the well logging curve, a numerical model was built by Tough+Hydrate to study the influences of horizontal well location and horizontal fracture length on gas production. It was found that compared with the cases without fracturing, the total gas production of the cases with 5 m horizontal fracture length when the horizontal well was in the middle of the gas hydrate-bearing layer (GHBL), the middle of the three-phase layer (TPL), and the top of free gas layer (FGL) increased by 53.20%, 60.29%, and 16.68%, respectively. However, when the fracture length increased from 5 to 20 m, the gas production increased only by 5.41%, 7.77%, and 2.27%, respectively. This meant that the preferred fracture length in this study was 5 m, which could effectively increase the production and reduce the construction cost. Meanwhile, the promotion effects of horizontal fracture on the gas production of the horizontal well at the top of the FGL was smaller than that in the middle of the GHBL or TPL. However, higher gas production could be achieved when the horizontal well was at the top of the FGL with a fracture length of 5 m during 1 and 3 years of production, which was 2.61 and 1.61 times of that in the middle of GHBL, respectively; however, the total gas production of 10 years when the horizontal well was in the middle of GHBL was comparable to that at the top of FGL when horizontal fracture length was 5 m.
There are major problems in offshore hydrate production tests, such as low gas production, limited hydrate decomposition area, and short stable production duration. Hydraulic fracturing is regarded as an effective way to improve gas production from a natural gas hydrate (NGH) reservoir. However, the fracture initiation, propagation, and morphology of hydraulic fracturing in the NGH reservoir are rarely investigated. In this work, a 2D numerical model based on the cohesive element is built to study the effects of reservoir properties and fracturing execution parameters on hydraulic fracturing of the NGH reservoir. With the increase of gas hydrate saturation, the fracture initiation pressure increases obviously, and the fracture becomes longer and narrower, which can be attributed to the increase of the strength and elastic modulus of hydrate-bearing sediments. Fracture initiation pressure decreases with the increase of reservoir intrinsic permeability due to the filtration of fracturing fluid. The stress in the normal direction of the fracture surface has a more significant influence on the initiation, propagation, and size of the fracture. With the increase of in situ horizontal stress, the strength of hydrate-bearing sediments increases, leading to an obvious increase of fracture initiation pressure and the formation of wider and shorter fractures. In addition, a higher injection rate of fracturing fluid is conducive to the formation of wider and longer fractures. At high injection rates, the effects of fracturing fluid viscosity on fracture initiation pressure and fracture morphology are more obvious. The results obtained in this work will bring a better understanding of hydraulic fracturing in NGH reservoirs and help to construct potential reservoir stimulation strategies.
The stratification split grouting foam mortar method (SPGFM) was first proposed to stimulate the low-permeability gas hydrate reservoir through constructing the fast flow channel for enhancing gas production. Based on the low-permeability hydrate-bearing sediments (HBS) at SH2 site in the Shenhu area of South China Sea, the foam mortar layer (FML) reservoir model was constructed. The numerical simulation that coupled thermal-hydraulic-mechanical (THM) processes was employed to evaluate the efficiency and feasibility of this method. Results show that the FML could effectively promote the expansion of the low-pressure zone into the hydrate reservoir, and enhance gas hydrate dissociation rate, cumulative gas production and energy efficiency. The FMLs have significant influence on the spatial distribution and the evolution characteristics of reservoir thermophysical and geomechanical parameters during gas production. The sensitivity analysis of FML shows the number of layers, thickness and permeability of FML exist the critical values for meeting the demand of promoting hydrate dissociation and gas production. Although the cumulative gas production and gas production rate will greatly increase with enlarging the radius, the gas-to-water ratio increase slightly. In view of the hydrate reservoir at SH2 site, the recommended number of FMLs is 4-6, and the distance between the FML and overburden/underburden should be more than 7.5 m. In addition, the optimal values of thickness, radius and permeability of FML are 5 cm, 40 m and 1×10⁻¹⁰ m², respectively. The geomechanical response indicates that the FMLs are beneficial for reservoir stability while improving gas production.
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