Laboratory characterisation of fracture compressibility for coal and shale gas reservoir rocks: A review (original) (raw)
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Laboratory study of proppant on shale fracture permeability and compressibility
Fuel, 2018
Hydraulic fracturing is key for shale gas production and fracture permeability or conductivity is one of the most important parameters for gas production rate. Investigating the proppant distribution and fracture permeability in the field is difficult, therefore, laboratory study is a good alternative. In this work, the effect of the layer number and type of proppant on fracture permeability and compressibility were investigated. A cubic shale sample from the Cambrian Niutitang Formation at Sangzhi, Hunan Province, China, was used in this work. Sands and glass beads of different number of layers were added into an artificial fracture and seven cases, including original sample, non-propped fracture, and four kinds of propped fractures were considered. Permeability at three gas pressure steps and five confining pressure steps were measured in each case at two flow directions. Microscopic X-ray computed tomography was used to detect the distributions of proppant, and the relationship with permeability and its anisotropy was studied. A permeability model combining the stress and Klinkenberg effects was used to match experimental data and a new fracture compressibility model was proposed to predict the change of fracture compressibility with the layer number of proppant. It was found that permeability and compressibility of proppant supported fracture are closely related to proppant packing pattern and layer number, as well as the permeability anisotropy. These results improve our understanding on permeability behaviour for the proppant supported fracture and can assist in the model of fracture permeability and simulation of shale gas production.
Journal of Natural Gas Science and Engineering, 2021
Proppants hold fractures open and increase fracture conductivity but must survive and remain functional during pressure drawdown. The shale reservoir usually suffers a high effective stress during gas depletion whilst most previous experiment works are conducted under a relative low stress level. In this work, permeability evolution was explored in a proppant-supported natural fracture of Longmaxi shale from the Sichuan Basin, China under a large effective stress range (1.5-59.5 MPa). Proppant performance was examined via continuous permeability measurements and by optical microscopy and laser-classifier measurements of particle size distributions (PSD) recored both pre-and post-loading. The permeability of the propped shale fracture is two orders of magnitude higher than that of the non-propped fracture and strongly controlled by the proppant behaviour. Surprisingly, overall permeability of the proppant pack decreases with an increase in thickness of the enclosed proppant. The decrease in the permeability with high stresses is largest for unpropped fractures and decreases with an increase in the number of layers. Most important, the mean compressibility of the non-propped and propped fracture is not constant but reduces with an increase in confining stress. This indicates that the compaction, crushing, embedment and repacking of the proppant particles, because of high effective stress, resulting in a decrease in the porosity of the proppant pack further reducing the compressibility and permeability of the supported fracture.
Experimental study of permeability change of organic-rich gas shales under high effective stress
Journal of Natural Gas Science and Engineering, 2019
Shale permeability and its variation under high stress are vital for gas production from deep shale gas reservoirs. Most experiments of stress-dependent permeability for organic-rich shale were conducted under lower stress less than 40 MPa, therefore, shale permeability evolution under high stress is not clear. In this work, the effects of high stress on the permeability and fracture compressibility of shales were investigated experimentally. Moreover, the impact of stress cycling on permeability were also studied. Four shale samples including two intact samples and two fractured samples from Cambrian Niutitang Shale formation and Silurian Longmaxi Shale formation were used. Permeability was measured using Helium under different stress conditions, including different confining pressure, different gas pressure, and constant effective stress. The highest effective stress and gas pressure in this work was 59.5 MPa and 10 MPa, respectively. Fracture compressibilities were calculated using the stress-dependent permeability data. The results show that the permeability of the intact samples and fractured samples decreased by one order of magnitude and three orders of magnitude, respectively, with the effective stress changing from 1.5 MPa to 59.5 MPa. The shale permeability results show a two-stage characteristic and nonlinearly decreasing trend with the increase of effective stress, demonstrating that the fracture compressibility is stress dependent and decreases with stress. The permeability hysteresis occurs between the loading and unloading cycles due to the inelastic compression of the pore. The modelling results also show that the Klinkenberg constant show a positive correlation with effective stress, as effective stress reduces the fracture opening and absolute permeability.
Rock Mechanics and Rock Engineering, 2018
Shale gas has recently gained significant attention as one of the most important unconventional gas resources. Shales are fine-grained rocks formed from the compaction of silt-and clay-sized particles and are characterised by their fissured texture and very low permeability. Gas exists in an adsorbed state on the surface of the organic content of the rock and is freely available within the primary and secondary porosity. Geomechanical studies have indicated that, depending on the clay content of the rock, shales can exhibit a brittle failure mechanism. Brittle failure leads to the reduced strength of the plastic zone around a wellbore, which can potentially result in wellbore instability problems. Desorption of gas during production can cause shrinkage of the organic content of the rock. This becomes more important when considering the use of shales for CO 2 sequestration purposes, where CO 2 adsorption-induced swelling can play an important role. These phenomena lead to changes in the stress state within the rock mass, which then influence the permeability of the reservoir. Thus, rigorous simulation of material failure within coupled hydro-mechanical analyses is needed to achieve a more systematic and accurate representation of the wellbore. Despite numerous modelling efforts related to permeability, an adequate representation of the geomechanical behaviour of shale and its impact on permeability and gas production has not been achieved. In order to achieve this aim, novel coupled poro-elastoplastic analytical solutions are developed in this paper which take into account the sorption-induced swelling and the brittle failure mechanism. These models employ linear elasticity and a Mohr-Coulomb failure criterion in a plane-strain condition with boundary conditions corresponding to both open-hole and cased-hole completions. The post-failure brittle behaviour of the rock is defined using residual strength parameters and a non-associated flow rule. Swelling and shrinkage are considered to be elastic and are defined using a Langmuir-like curve, which is directly related to the reservoir pressure. The models are used to evaluate the stress distribution and the induced change in permeability within a reservoir. Results show that development of a plastic zone near the wellbore can significantly impact fracture permeability and gas production. The capabilities and limitations of the models are discussed and potential future developments related to modelling of permeability in brittle shales under elastoplastic deformations are identified.
Fracture-permeability behavior of shale
Journal of Unconventional Oil and Gas Resources, 2015
The fracture-permeability behavior of Utica shale, an important play for shale gas 6 and oil, was investigated using a triaxial coreflood device and x-ray tomography in combination 7 with finite-discrete element modeling (FDEM). Fractures were generated in both compression 8 and in a direct-shear configuration that allowed permeability to be measured across the faces of 9 cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed 10
Experimental study of permeability and its anisotropy for shale fracture supported with proppant
Journal of Natural Gas Science and Engineering, 2017
Shale gas is an important unconventional natural gas resource, but shale has extremely low permeability. Production of shale gas can be improved by using proppants for hydraulic fracturing and maintaining fracture conductivity, and a better understanding of the permeability and its anisotropy of proppant-supported fractures would be useful in optimising gas production. This paper described experiments on shale permeability and its anisotropy with respect to gas pressure, effective stress and gas type for a natural fracture supported with two sizes of proppant. A cubic sample from the Silurian Longmaxi formation in the Sichuan Basin, China, was used in the study; the testing direction of the sample was altered, and both helium (non-sorbing) and methane (sorbing) were tested. Microscopic X-ray computerised tomography (CT) scanning was used to reveal the proppant distribution and fracture shape. Finally, an analytical model was applied to describe the permeability with respect to pore pressure and effective stress and the results were used to determine the relationships between initial fracture compressibility, Klinkenberg coefficient and absolute permeability. The permeabilities of propped fractures were found to be a few hundred or even a few thousand times higher than those of the natural fracture under the same experimental conditions, with both the proppant size and the amount of proppants added affecting this increase. The permeability was anisotropic in two horizontal directions. The direction and ratio of permeability anisotropy of the proppant-supported fracture differed from those of the natural
Applied Sciences, 2017
The aim of this study was to identify the influence of reservoir depth on reservoir rock mass breakdown pressure and the influence of reservoir depth and injecting fluid pressure on the flow ability of reservoirs before and after the hydraulic fracturing process. A series of fracturing tests was conducted under a range of confining pressures (1, 3, 5 and 7 MPa) to simulate various depths. In addition, permeability tests were conducted on intact and fractured samples under 1 and 7 MPa confining pressures to determine the flow characteristic variations upon fracturing of the reservoir, depending on the reservoir depth and injecting fluid pressure. N 2 permeability was tested under a series of confining pressures (5, 10, 15, 20 and 25 MPa) and injection pressures (1-10 MPa). According to the results, shale reservoir flow ability for gas movement may reduce with increasing injection pressure and reservoir depth, due to the Klinkenberg phenomenon and pore structure shrinkage, respectively. The breakdown pressure of the reservoir rock linearly increases with increasing reservoir depth (confining pressure). Interestingly, 81% permeability reduction was observed in the fractured rock mass due to high (25 MPa) confinement, which shows the importance of proppants in the fracturing process.
2016
To assess how fractures affect the fluid flow in shale plugs, we conducted stressdependent permeability measurements on both intact and fractured shale samples. We characterized the degree of fracturing with the help of micro X-ray CT images. As expected, permeabilities decreased significantly during the initial effective stress increase. During the subsequent effective pressure decrease, the permeability remained relatively unchanged. The degree of hysteresis depended on the sample integrity, i.e. fracture density, type, and distribution. We recorded an average hysteresis loss of 35% for intact samples, 55% for samples with a low density of hairline or discontinuous midsized fractures, and over 75% for samples with thick fractures, high fracture density, or continuous mid-sized cracks. Micro X-ray CT images acquired of fractures subjected to increasing confining stress showed that both, hairline and mid-sized fractures closed up completely at sufficiently high confining pressure. W...
The Impact of Stress on Propped Fracture Conductivity and Gas Recovery in Marcellus Shale
SPE Hydraulic Fracturing Technology Conference and Exhibition, 2018
It is commonly observed that the production rates from unconventional reservoirs decline rapidly as compared to conventional reservoirs. The net stress increases with the production because the pore (fluid) pressure decreases while the overburden pressure remains constant. This leads to the fracture compaction and conductivity impairment due to proppant embedment. Even though advances in technology have unlocked considerable reserves of hydrocarbon, the impact of the net stress changes on proppant conductivity, i.e. stress-dependent propped fracture conductivity, is not well understood. The objective of this study is to investigate the impact of the net stress propped fracture conductivity from the horizontal wells with multiple hydraulic fractures completed in Marcellus Shale. A commercial reservoir simulator was used to develop the base model for a Marcellus Shale horizontal well. The model incorporated various storage and production mechanisms inherent in Shales i.e. matrix, natural fracture, and gas adsorption as well as the hydraulic fracture properties (half-length and conductivity). The core, log, completion, stimulation, and production data from wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the formation and completion properties for the simulation model. MSEEL is a Marcellus Shale dedicated field laboratory and a research collaboration
Brittleness of gas shale reservoirs: a case study from the North Perth basin, Australia
Journal of Natural Gas Science and Engineering, 2016
Shale reservoirs have gained the attention of many in recent years due to their potential as a major gas resource. Production from this kind of formation, however, requires an accurate estimation of brittleness and employments of hydraulic fracturing. There have been many studies as to how brittleness can be estimated, but few research works were carried out so far indicating how brittleness indices vary in gas shale formations. The aim of this paper is to evaluate the variation of brittleness in one of the gas shale reservoirs located in the north Perth Basin of Australia. The results obtained indicated that the lower part of the Carynginia shale should be selected for a hydraulic fracturing job due to a high brittleness index, although a careful analysis of Total Organic Content (TOC) might be required before initiating any plans. The mineralogical report and interpretations revealed that the space created by cross-plotting the elastic parameters is able to identify dominant minerals contributing into brittleness. Performing a series of true triaxial tests, which are capable of simulating the real field condition by applying three independent principal stresses, implied that as the stress anisotropy increases, a transition takes place from brittle towards the ductile behaviours. However, when this anisotropy becomes significant, samples regain their strength. This study, therefore, recommends more studies to get a practical conclusion on brittleness under true triaxial conditions.