A comparison of shale permeability coefficients derived using multiple non-steady-state measurement techniques: Examples from the Duvernay Formation, Alberta (Canada)

Ghanizadeh, Amin; Bhowmik, Santanu; Ardakani, Omid H.; Sanei, Hamed; Clarkson, Christopher R.

doi:10.1016/j.fuel.2014.09.073

Cited by 89 publications

(28 citation statements)

References 52 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…But, in Aljamaan et al 's [35] experiment, the measurements are conducted on dried samples. Ghanizadeh et al [48] indicated that permeability values measured on dried samples are higher than those measured on "as-received" samples, which is due to the presence of pore fluid (bound/adsorbed water and hydrocarbon) in "as-received" samples [48]. The bound/adsorbed water and hydrocarbon partially block pore channels, which results in the decrease of permeability [49].…”

Section: Model Validation With Experimental Datamentioning

confidence: 99%

A Theoretical Analysis of Pore Size Distribution Effects on Shale Apparent Permeability

Tian

Ren

et al. 2017

Geofluids

View full text Add to dashboard Cite

Apparent permeability is an important input parameter in the simulation of shale gas production. Most apparent permeability models assume a single pore size. In this study, we develop a theoretical model for quantifying the effect of pore size distribution on shale apparent permeability. The model accounts for the nonuniform distribution of pore sizes, the rarefaction effect, and gas characteristics. The model is validated against available experimental data. Theoretical calculations show that the larger the pore radius, the larger the apparent permeability. Moreover, the apparent permeability increases with an increase in the width of pore size distribution, with this effect being much more pronounced at low pressure than at high pressure.

show abstract

Section: Model Validation With Experimental Datamentioning

confidence: 99%

A Theoretical Analysis of Pore Size Distribution Effects on Shale Apparent Permeability

Tian

Ren

et al. 2017

Geofluids

View full text Add to dashboard Cite

show abstract

“…A high rate of permeability loss (high ) can be attributed to the narrowing or removal of the more compressible pores from the fluid conducting network. Although has not been found to differ greatly between the Whitby Mudstone samples, it can be expected to vary with mineralogy of different rock types (particularly clay content (Chalmers et al 2012;Ghanizadeh et al 2014a;Ghanizadeh et al 2014b;Ghanizadeh et al 2015) and microstructure.…”

Section: Sensitivity Of Permeability To Confining Pressurementioning

confidence: 95%

Microstructural controls on the pressure-dependent permeability of Whitby Mudstone

Mecklenburgh¹,

Taylor²,

Rutter³

et al. 2018

Preprint

View full text Add to dashboard Cite

A combination of permeability and ultrasonic velocity measurements allied with image analysis is used to distinguish the primary microstructural controls on effective-pressure dependent permeability. Permeabilities of cylindrical samples of Whitby Mudstone were measured using the oscillating pore pressure method at confining pressures ranging between 30-95 MPa and pore pressures ranging between 1-80 MPa. The permeability-effective pressure relationship is empirically described using a modified effective pressure law in terms of confining pressure, pore pressure and a Klinkenberg effect. Measured permeability ranges between 3×10 -21 m 2 and 2 ×10 -19 m 2 (3 and 200 nd), and decreases by ~1 order of magnitude across the applied effective pressure range. Permeability is shown to be less sensitive to changes in pore pressure than changes in confining pressure, yielding permeability effective pressure coefficients ( ) between 0.42 and 0.97. Based on a pore-conductivity model which considers the measured changes in acoustic wave velocity and pore volume with pressure, the observed loss of permeability with increasing effective pressure is attributed dominantly to the progressive closure of bedding-parallel, crack-like pores associated with grain boundaries.Despite only constituting a fraction of the total porosity, these pores form an interconnected network that significantly enhances permeability at low effective pressures.The pre-publication reference is: Mckernan, R., Mecklenburgh, J., Rutter, E. H. and Taylor Progress in understanding fluid transport properties of mudstones is currently hindered by a scarcity of published experimental data. However, the ongoing expansion of the hydrocarbon industry into low-permeability unconventional resources is driving the demand for research and development in this field. Even when hydraulic fracture treatment is used to enhance production, flow of hydrocarbons into the fractures will be controlled ultimately by the microporous, low permeability matrix. Furthermore, during reservoir production pore-fluid pressure is progressively reduced, which acts to increase the in-situ Terzaghi effective pressure (defined as overburden pressure minus pore pressure), thereby decreasing permeability. The evolution of permeability of the matrix therefore determines the prediction of long-term production, which must take into account the effects of flow regime, multiphase flow, sorption effects, permeability anisotropy and, most importantly, the pressuredependence of permeability.Laboratory measurements of permeability of intact mudstone samples performed under reservoir conditions has yielded values between 10 -22 m 2 and 10 -12 m 2 (0.1 nD and 1 D) for flow both parallel and normal to layering (Morrow et al.

show abstract

“…The pulse-decay permeability measurement method has been widely recognized as a way to identify the ultra-low permeability rocks [28,30,[48][49][50][51][52][53]. Because the conventional permeability measurement is based on recording the flow rate during the experiment, the flow rate through the ultra-low permeability rock is too small to be measured exactly under the precision of present equipment.…”

Section: Permeability Stress Sensitivitymentioning

confidence: 99%

Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

Shen¹,

Meng²,

Liu³

et al. 2017

Geofluids

View full text Add to dashboard Cite

The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT) appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR) and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flowback scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

show abstract

A comparison of shale permeability coefficients derived using multiple non-steady-state measurement techniques: Examples from the Duvernay Formation, Alberta (Canada)

Cited by 89 publications

References 52 publications

A Theoretical Analysis of Pore Size Distribution Effects on Shale Apparent Permeability

A Theoretical Analysis of Pore Size Distribution Effects on Shale Apparent Permeability

Microstructural controls on the pressure-dependent permeability of Whitby Mudstone

Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

Contact Info

Product

Resources

About