Fluid‐Driven Tensile Fracture and Fracture Toughness in Nash Point Shale at Elevated Pressure

Gehne, Stephan; Inskip, Nathaniel Forbes; Benson, Philip; Meredith, P. G.; Koor, Nick

doi:10.1029/2019jb018971

Cited by 29 publications

(23 citation statements)

References 24 publications

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“…For example, within the Porthkerry formation at Nash Point the Nash Point limestone is interbedded with the Nash Point shale. While the results reported here show that Nash Point limestone is essentially isotropic, previously published data (Forbes Inskip et al 2018;Gehne et al 2020) show that Nash Point shale is highly anisotropic, with both tensile strength and fracture toughness much lower in the Short-transverse orientation than in either of the Arrester or Divider orientations. For a fracture propagating vertically through a horizontally layered sequence, it is the fracture toughnesses in the Arrester orientation that needs to be overcome.…”

Section: Implications For Fracture Propagation Through Layered Rock Sequencescontrasting

confidence: 71%

Fracture Properties of Nash Point Limestone and Implications for Fracturing of Layered Carbonate Sequences

Inskip

Meredith

2021

Rock Mech Rock Eng

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Carbonate reservoirs accommodate a significant proportion of global hydrocarbon reserves. However they are often tight and permeability is therefore usually dependent on either flow through existing fractures or through those produced by hydraulic stimulation. Hence, understanding how fracture networks develop in carbonate reservoir rocks is key to efficient and effective production. However, despite their prevalence as reservoir rocks, there is a paucity of data on key fracture properties of carbonate rocks, particularly in more than one orientation. Here, therefore we report measurements of both the tensile strength and fracture toughness of Nash Point limestone in the three principal fracture orientations to determine what effect any mechanical anisotropy might have on fracture propagation. We find Nash Point limestone to be essentially isotropic in terms of both its microstructure and its fracture properties. When comparing the fracture toughness of Nash Point limestone with that of others limestones, we find that fracture toughness decreases with increasing porosity, although this dependency is not as strong as found in other porous rocks. Finally, as many so-called carbonate reservoirs actually comprise layered sequences, we extend our analysis to consider the layered sequence of limestones and shales at Nash Point. We find that the fracture toughness of Nash Point limestone is higher than Nash Point shale but that the fracture energy is lower. We therefore discuss how the implications of fracturing through multi-layered sequences could be explored in future work.

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Section: Implications For Fracture Propagation Through Layered Rock Sequencescontrasting

confidence: 71%

Fracture Properties of Nash Point Limestone and Implications for Fracturing of Layered Carbonate Sequences

Inskip

Meredith

2021

Rock Mech Rock Eng

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“…Using ρ r =2700 kg·m −3 , ρ f =1000 kg·m −3 , µ=8.9 GPa, ν=0.25 and K c in the range 0.36-4.05 to 7-25 MPa·m 1/2 , we obtain V num c = 6·10 −2 and 500 m 3 respectively. These K c values are for laboratorysized shale samples from 100 to 1000 m confining pressure and effective K c values estimated for veins in the field, respectively (Gehne et al, 2020;Olson, 2003). Current operations use volumes around double our highest predicted limit.…”

Section: Water Injection Into Stiff Rockmentioning

confidence: 94%

Critical fluid injection volumes for uncontrolled fracture ascent

Davis¹,

Rivalta²,

Dahm³

2020

Preprint

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Hydro-fracturing is a routine industrial technique whose safety depends on fractures remaining confined within the target rock volume. Both observations and theoretical models show that pockets of fluid can propagate large distances in the Earth's crust, in a self-sustained, uncontrolled manner, providing that the fluid volume is large enough. Existing models that describe when self-sustaining ascent starts are difficult to use for predictions, as they are mostly twodimensional (2D) and depend on parameters (typically the fracture length) that are hard to assess, even a posteriori.Here we constrain, both analytically and numerically in three-dimensions (3D), scale-independent critical volumes as a function of only rock and fluid properties. We apply our model to laboratory, industrial and natural settings, showing that our critical volumes are consistent with observations and can be used as a conservative estimate in geological applications. We find typical injection volumes exceed the limit we define for the start of self-sustaining fracture ascent. We describe a number of other processes that may work to arrest fractures with volumes exceeding this limit.This appears to have resulted in a false sense of operational safety when working with large injection volumes. In Non-peer reviewed EarthArXiv preprint the context of our findings we outline the quantitative work that would be required to better elucidate the processes causing fracture arrest, which could help to assess more comprehensively the safety of such operations.

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“…Once a stable condition has been reached, both confining and axial stress were kept constant via the servo-controlled pumps and fluid was injected into the borehole through the open-end packer to stimulate nucleation and propagation of a hydraulic fracture system, marking the end of the experiment. During the hydraulic injection phase axial stress was still servo-controlled to remain higher than both confining and injection pressure (Gehne et al 2020).…”

Section: Methodsmentioning

confidence: 99%

“…Fluid leak-off in BS8 causes pressure decrease at the tip of the fracture, likely to be responsible of the observed episodic fracture propagation pattern, visible in the oscillations of injection pressure and by the multiple drops in radial and volumetric strain (S. Gehne et al , 2020. On the other hand, in COS1, once the fracture reaches the edge of the sample, we observed a non-monotonic behavior of the radial strain, showing relative contraction on NS radial strain, where the nucleation of the fracture was recorded.…”

Section: Fracture Propagationmentioning

confidence: 99%

The Role of Rock Matrix Permeability in Controlling Hydraulic Fracturing in Sandstones

et al. 2021

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A concomitant effect of a hydraulic fracturing experimenting is frequently fluid permeation into the rock matrix, with the injected fluid permeating through the porous rock matrix (leak-off) rather than contributing to the buildup of borehole pressure, thereby slowing down or impeding the hydro-fracturing process. Different parameters, such as low fluid viscosity, low injection rate and high rock permeability, contribute to fluid permeation. This effect is particularly prominent in highly permeable materials, therefore, making sleeve fracturing tests (where an internal jacket separates the injected fluid in the borehole from the porous rock matrix) necessary to generate hydraulic fractures. The side effect, however, is an increase in pressure breakdown, which results in higher volume of injected fluid and in higher seismic activity. To better understand this phenomenon, we report data from a new comparative study from a suite of micro-hydraulic fracturing experiments on highly permeable and on low-permeability rock samples. Experiments were conducted in both sleeve fracture and direct fluid fracture modes using two different injection rates. Consistent with previous studies, our results show that hydraulic fracturing occurred only with low permeation, either due to the intrinsic low permeability or due to the presence of an inner silicon rubber sleeve. In particular, due to the presence of quasi-impermeable inner sleeve or borehole skin in the sleeve fracturing experiment, fracturing occurs, with the breakdown pressure supporting the linear elastic approach considering poroelastic effects, therefore, with low stress drop and consequently low microseismicity. Rock matrix permeability also controls the presence of precursory Acoustic Emission activity, as this is linked to the infiltration of fluids and consequent expansion of the pore space. Finally, permeability is shown to mainly control fracturing speed, because the permeation of fluid into the newly created fracture via the highly permeable rock matrix slows down its full development. The application of these results to the field may help to reduce induced seismicity and to conduct well stimulation in a more efficient way.

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Fluid‐Driven Tensile Fracture and Fracture Toughness in Nash Point Shale at Elevated Pressure

Cited by 29 publications

References 24 publications

Fracture Properties of Nash Point Limestone and Implications for Fracturing of Layered Carbonate Sequences

Fracture Properties of Nash Point Limestone and Implications for Fracturing of Layered Carbonate Sequences

Critical fluid injection volumes for uncontrolled fracture ascent

The Role of Rock Matrix Permeability in Controlling Hydraulic Fracturing in Sandstones

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