Characterization of anisotropy in the permeability of organic-rich shales

Mokhtari, Mehdi; Tutuncu, Azra N.

doi:10.1016/j.petrol.2015.05.024

Cited by 77 publications

(21 citation statements)

References 35 publications

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“…For example, the emergence of oil and gas recovery from shale formations has led to renewed interest in laboratory measurements of anisotropic permeability properties of shale samples from major shale plays (e.g., Eagle Ford, Barnett in the US, and emerging plays elsewhere, e.g., Longmaxi formation, Sichuan Basin, China, and Vaca Muerta, Argentina). Numerous studies have detailed the permeability properties (e.g., [37,39]). For example, in Pan et al [39], the authors measured that the shale reservoir could have a horizontal permeability (about 200 nD) that is 25 times the vertical permeability (about 8 nD), and Mokhtari and Tutuncu [37] showed that the horizontal permeability is almost 4 times the vertical permeability.…”

Section: Discussionmentioning

confidence: 99%

“…Numerous studies have detailed the permeability properties (e.g., [37,39]). For example, in Pan et al [39], the authors measured that the shale reservoir could have a horizontal permeability (about 200 nD) that is 25 times the vertical permeability (about 8 nD), and Mokhtari and Tutuncu [37] showed that the horizontal permeability is almost 4 times the vertical permeability. More permeability measurement results are given in Table 2.…”

Section: Discussionmentioning

confidence: 99%

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Rules for Flight Paths and Time of Flight for Flows in Porous Media with Heterogeneous Permeability and Porosity

Zuo

Weijermars

2017

Geofluids

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Porous media like hydrocarbon reservoirs may be composed of a wide variety of rocks with different porosity and permeability. Our study shows in algorithms and in synthetic numerical simulations that the flow pattern of any particular porous medium, assuming constant fluid properties and standardized boundary and initial conditions, is not affected by any spatial porosity changes but will vary only according to spatial permeability changes. In contrast, the time of flight along the streamline will be affected by both the permeability and porosity, albeit in opposite directions. A theoretical framework is presented with evidence from flow visualizations. A series of strategically chosen streamline simulations, including systematic spatial variations of porosity and permeability, visualizes the respective effects on the flight path and time of flight. Two practical rules are formulated. Rule 1 states that an increase in permeability decreases the time of flight, whereas an increase in porosity increases the time of flight. Rule 2 states that the permeability uniquely controls the flight path of fluid flow in porous media; local porosity variations do not affect the streamline path. The two rules are essential for understanding fluid transport mechanisms, and their rigorous validation therefore is merited.

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Section: Discussionmentioning

confidence: 99%

Section: Discussionmentioning

confidence: 99%

Rules for Flight Paths and Time of Flight for Flows in Porous Media with Heterogeneous Permeability and Porosity

Zuo

Weijermars

2017

Geofluids

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“…It was deposited during the Late Cretaceous and has an estimated 595 billion cubic meters of recoverable gas. 32,33 According to Mokhtari and Tutuncu, 34 the permeability of Mancos shale varies between 9 × 10 −19 and 3 × 10 −17 m 2 . The samples investigated were gray in color with light gray interbedding.…”

Section: Methodsmentioning

confidence: 99%

Spontaneous Imbibition of a Wetting Fluid Into a Fracture With Opposing Fractal Surfaces: Theory and Experimental Validation

et al. 2019

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Spontaneous imbibition (SI) is a capillary-driven flow process, in which a wetting fluid moves into a porous medium displacing an existing non-wetting fluid. This process likely contributes to the loss of fracking fluids during hydraulic fracturing operations. It has also been proposed as a method for an enhanced recovery of hydrocarbons from fractured unconventional reservoirs. Numerous analytical and numerical approaches have been employed to model SI. Invariably, these idealize a fracture as the gap formed between parallel flat surfaces. In reality, rock fracture surfaces are rough over multiple scales, and this roughness will influence the contact angle and rate of fluid uptake. We derived an analytical model for the early-time SI behavior within a fracture bounded by parallel impermeable surfaces with fractal roughness assuming laminar flow. The model was tested by fitting it to experimental data for the SI of deionized water into air-filled rock fractures. Twenty cores from two rock types were investigated: a tight sandstone (Crossville) and a gas shale (Mancos). A simple Mode I longitudinal fracture was produced in each core by compressive loading between parallel flat plates using the Brazilian method. Half of the Mancos cores were fractured perpendicular to bedding, while the other half were fractured parallel to bedding. The two main parameters in the SI model are the mean separation distance between the fracture surfaces, [Formula: see text], and the fracture surface fractal dimension [Formula: see text]. The [Formula: see text] was estimated for each core by measuring the geometric mean fracture aperture width through image analysis of the top and bottom faces, while [Formula: see text] was estimated inversely by fitting the SI model to measurements of water uptake obtained using dynamic neutron radiography. The [Formula: see text] values ranged from 45[Formula: see text][Formula: see text]m to 190[Formula: see text][Formula: see text]m, with a median of 93[Formula: see text][Formula: see text]m. The SI model fitted the height of uptake versus time data very well for all of the rock cores investigated; medians of the resulting root mean squared errors and coefficients of determination were 0.99[Formula: see text]mm and 0.963, respectively. Estimates of [Formula: see text] ranged from 2.04 to 2.45, with a median of 2.24. Statistically, all of the [Formula: see text] values were significantly greater than two, confirming the fractal nature of the fracture surfaces. Future research should focus on forward prediction through independent measurements of [Formula: see text] and extension of the existing SI model to late times (through the inclusion of gravity) and fractures with permeable surfaces.

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“…Transient permeability measurement approach can be performed on crashed cores, commonly known as Gas Research Institute (GRI) method (Luffel et al, 1993;API 1998;Cui et al, 2009;Passey et al, 2010;Profice et al, 2012;Tinni et al, 2012;Heller, et al, 2014;Civan and Devegowda, 2014), or on intact cores Lin, 1977;Haskett et al, 1988;Dicker and Smith 1988;Jones 1997;Akkutlu and Fathi, 2012;Mokhtari and Tutuncu, 2015;Jin et al, 2015;Zhou et al, 2016). Unsteady state (transient) methods are the alternatives to measure micro and nano-Darcy permeability formations at a reasonably short time.…”

Section: Permeability Measurement Methodologymentioning

confidence: 99%

Experimental Investigation on Permeability and Porosity Hysteresis in Low-Permeability Formations

Teklu

Zhou

et al. 2016

SPE Low Perm Symposium

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Permeability and porosity decrease with increasing net stress in consolidated and unconsolidated porous media is a well-known phenomenon to petroleum and geomechanics engineers. Conversely, permeability and porosity are observed to increase when net stress decreases, however typically follow a different path, this discrepancy is known as hysteresis. The trend of permeability and porosity hysteresis is a signature of porous medium that depends on several physical and mechanical properties.Understanding permeability and porosity hysteresis plays a significant role in production strategies of hydrocarbon reservoirs. Hysteresis effect on production strategies can be even more important in very low permeability reservoirs such as tight sandstone, tight carbonate, and shale formations. The reason is that the stress change associated with permeability and porosity hysteresis can affect adsorption/desorption and diffusion transport mechanisms which are among the main driving mechanisms in low or ultra-low permeability reservoirs.In this study, permeability and porosity hysteresis of nano, micro, and milli-Darcy core samples are measured for a wide range of net stress and the results are correlated with pore structures observed by Field Emission Scanning Electron Microscopy (FE-SEM) images. The nano and micro-Darcy core samples are from the Niobrara, Bakken, Three Forks, and Eagle Ford formations. The milli-Darcy core samples are from Middle East carbonate, Indiana Limestone, and Torrey Buff Sandstone formations. Bakken, Three Forks, and Middle East carbonate are core samples from oil producing reservoirs, whereas others are from outcrop. Our experimental observations show that: (a) compared to steady state method, the unsteady state permeability measurement used here can shorten the time required to measure permeability of nano and micro-Darcy cores without significant measurement error; (b) stress dependency of permeability and porosity and their hysteresis during loading and unloading of outcrop cores were observed to be very small compared to those of reservoir cores; (c) generally, the stress dependency and hysteresis of permeability and porosity was observed to be inversely related permeability and porosity at initial stress conditions; hence, these characteristics are more pronounced and important in organic rich shale reservoirs; (d) porosity decrease with stress and its hysteresis were observed to be much smaller than that of permeability; (e) our results generally follow the experimental and theoretical relationship between cubic root of permeability and logarithmic of net stress reported by many researchers; and (f) an increase in permeability with temperature (and decrease in permeability with hysteresis during temperature unloading) is observed in organic rich mudrocks. This is due to dilation, diffusion, and adsorption effects of organic rich pores. Hence, a temperature correction factor is required to estimate the exact in-situ permeability of organic rich mudrocks.Finally, we would like to comment that und...

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Characterization of anisotropy in the permeability of organic-rich shales

Cited by 77 publications

References 35 publications

Rules for Flight Paths and Time of Flight for Flows in Porous Media with Heterogeneous Permeability and Porosity

Rules for Flight Paths and Time of Flight for Flows in Porous Media with Heterogeneous Permeability and Porosity

Spontaneous Imbibition of a Wetting Fluid Into a Fracture With Opposing Fractal Surfaces: Theory and Experimental Validation

Experimental Investigation on Permeability and Porosity Hysteresis in Low-Permeability Formations

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