2019 | Chandler, M. Mecklenburgh, J., Fauchille, A-L., Rizzo, R.E., Ma, L., Dowey, P.J., May, S., Atwood, R.C., Lee, P.D., Rutter, E.H., Bogush, A., Taylor, R.L. | AGU Fall Meeting 2019 | PUBLISHED ABSTRACT

A suite of laboratory-scale fluid injection experiments were conducted on 20mm diameter shale samples at elevated confining pressures between 20 and 50 MPa. Experiments were conducted on Bowland, Haynesville, Kimmeridge, Mancos and Whitby shales, as well as Solnhofen limestone. An Aluminium pressure vessel was specially developed to perform these fluid injection experiments with in-situ X-Ray Tomography on the I12 beamline at Diamond Light Source, UK. Tomographs with a voxel edge-length of 17μm were generated in this way and have been used to correlate fractures to the layering in the materials.

Here, the breakdown pressures of the various rock samples were seen to increase linearly with confining pressure as has been seen in previous studies, with little difference between sample materials. However, here, two distinct linear trends are interpreted, offset by around 10MPa. The tomographs demonstrate that the higher of these two trends corresponds to the development of new fractures, while the lower trend corresponds to reopening in samples featuring populations of existing fractures.

Tomographs were recorded throughout the application of the confining pressure, and subsequently, the injection of fluid into the central boreholes in the samples. These tomographic images have been used to investigate the closure of existing fractures during the application of the confining pressure, as well as the development of new fractures induced by the fluid pressure. In general, the primary fracture opened up parallel to the borehole, independent of the orientation to bedding. However, borehole-perpendicular primary fractures were observed in some of the more laminated shales, and secondary, bedding-parallel, fractures were induced in many samples with the borehole perpendicular to bedding.

​Post-experiment SEM images of the regions around the main fractures demonstrate substantial differences in the characteristics of the damaged region around the main fracture body between materials. In Haynesville shale, the damaged zone appears to mostly contain reactivated microfractures lying parallel to bedding, while in the more homogenous Bowland shale, this small-scale damage has a wider range of orientations.

2017 | Chandler, M. Mecklenburgh, J., Rutter, E.H., Taylor, R.L., Fauchille, A-L., Ma, L., Lee, P.D., Taylor, R.L. | AGU Fall Meeting 2017 | PUBLISHED ABSTRACT

Bibcode: ​2017AGUFMMR44A..06C

​Fracture propagation trajectories in gas-bearing shales depend on the interaction between the anisotropic mechanical properties of the shale and the anisotropic in-situ stress field. However, there is a general paucity of available experimental data on their anisotropic mechanical, physical and fluid-flow properties, especially at elevated confining pressures. A suite of mechanical, flow and elastic measurements have been made on two shale materials, the Whitby mudrock and the Mancos shale (an interbedded silt and mudstone), as well as Pennant sandstone, an isotropic baseline and tight-gas sandstone analogue. Mechanical characterization includes standard triaxial experiments, pressure-dependent permeability, brazilian disk tensile strength, and fracture toughness determined using double-torsion experiments. Elastic characterisation was performed through ultrasonic velocities determined using a cross-correlation method. Additionally, we report the results of laboratory-scale fluid injection experiments for the same materials. Injection experiments involved the pressurisation of a blind-ending central hole in a dry cylindrical sample. Pressurisation is conducted under constant volume-rate control, using silicon oils of varying viscosities. Breakdown pressure is not seen to exhibit a strong dependence on rock type or orientation, and increases linearly with confining pressure. In most experiments, a small drop in the injection pressure record is observed at what is taken to be fracture initiation, and in the Pennant sandstone this is accompanied by a small burst of acoustic energy. The shale materials were acoustically quiet. Breakdown is found to be rapid and uncontrollable after initiation if injection is continued. A simplified 2-dimensional model for explaining this is presented in terms of the stress intensities at the tip of a pressurised crack, and is used alongside the triaxial data to derive a characteristic flaw size from which the fractures have initiated in the borehole wall.

​Keywords: Geomechanics; Hydrology; Equations of state; Mineral physics; Surfaces and interfaces; Fractures and faults; Structural geology

2017 | Chandler, M. Mecklenburgh, J., Rutter, E.H., Fauchille, A-L., Taylor, R.L., Lee, P.D., Taylor, R.L. | EGU General Assembly 2017 | PUBLISHED ABSTRACT

Bibcode: 2017EGUGA..1918095C

​The use of hydraulic fracturing to recover shale-gas has focused attention upon the fundamental fracture properties of gas-bearing shales. Fracture propagation trajectories in these materials depend on the interaction between the anisotropic mechanical properties of the shale and the anisotropic in-situ stress field. However, there is a general paucity of available experimental data on their anisotropic mechanical, physical and fluid-flow properties, especially at elevated confining pressures. Here we report the results of laboratory-scale fluid injection experiments, for Whitby mudstone and Mancos shale (an interbedded silt and mudstone), as well as Pennant sandstone (a tight sandstone with permeability similar to shales), which is used an isotropic baseline and tight-gas sandstone analogue. Our injection experiments involved the pressurisation of a blind-ending central hole in an initially dry cylindrical sample. Pressurisation was conducted under constant volume-rate control, using silicone oils of various viscosities. The dependence of breakdown pressure on confining pressure was seen to be dependent on the rock strength, with the significantly stronger Pennant sandstone exhibiting much lower confining-pressure dependence of breakdown pressure than the weaker shales. In most experiments, a small drop in the injection pressure record was observed at what is taken to be fracture initiation, and in the Pennant sandstone this was accompanied by a small burst of acoustic energy. Breakdown was found to be rapid and uncontrollable after initiation if injection is continued, but can be limited to a slower (but still uncontrolled) rate by ceasing the injection of fluid after the breakdown initiation in experiments where it could be identified. A simplified 2-dimensional model for explaining these observations is presented in terms of the stress intensities at the tip of a pressurised crack. Additionally, we present a suite of supporting mechanical, flow and elastic measurements. Mechanical experiments include standard triaxial tests, pressure-dependent permeability experiments and fracture toughness determined using the double-torsion test. Elastic characterisation was determined through ultrasonic velocities determined using a cross-correlation method.

2015 | Rutter, E.H., Mecklenburgh, J., McKernan, R., Taylor, R.L. | Fourth International Conference on Fault and Top Seals | EXTENDED ABSTRACT

DOI: https://doi.org/10.3997/2214-4609.201414080

​The matrix permeability of shales is of great importance in determining the behaviour of shale seals and also of shale gas reservoirs. Methods of permeability determination must take into account sensitivity to variations in confining and pore pressures. We seek to establish whether common generic patterns of behaviour exist and to establish their parameters experimentally. Pressure sensitivities of two shales are compared, but the same pattern also applies to others. They follow the general law k = A exp(- g(Pc – a Pp)) (1 + D/ Pp) in which k is permeability, Pc is confining pressure, Pp is pore pressure, A, g, a and D are empirical parameters. g and a describe the sensitivity to confining pressure and pore pressure and variations of k by more than 3 orders of magnitude can occur over the whole reservoir pressure range. Slip (Klinkenberg) flow begins to be significant at gas pore pressures below about 50 bars. Partial fluid saturation leads to a reduction in permeability, and in all cases flow is highly anisotropic. If pressure sensitivity of permeability is not taken into account, reservoir evaluations from well tests will lead to substantial overestimation of original gas in place and likely yield with time.

2015 | Mecklenburgh, J., McKernan, R., Rutter, E.H., Taylor, R.L. | Geomechanical and Petrophysical Properties of Mudrocks, London | TALK

The matrix permeability of shales is of great importance in determining the behaviour of shale seals and also of shale gas reservoirs. Shale permeability is not constant, but varies significantly with variations in confining and pore pressures. We seek to establish whether common generic patterns of permeability behaviour exist for different shales and to establish their parameters experimentally. Here, we compare the pressure sensitivities of the permeability to gas of two Jurassic shales, but the same behaviour pattern also applies to others. They follow the general law

        k = A exp(- g(Pc – a Pp)) (1 + D / Pp)

 in which k is permeability, Pc is confining pressure, Pp is pore pressure, A, g, a and D are empirical parameters. g and a describe the sensitivity to confining pressure and pore pressure.  k can vary by more than 3 orders of magnitude over the whole reservoir pressure range, according to the values of the parameters. Slip (Klinkenberg) flow begins to be significant at gas pore pressures below about 5 MPa. Partial saturation of pore space with water or other fluids leads to a reduction in permeability, and in all cases flow is highly anisotropic. Over the range of reservoir pressure conditions pore volume changes with pressure are elastic and recoverable, except during the initial application of pressure.

If pressure sensitivity of permeability is not taken into account, reservoir evaluations from well tests will lead to substantial overestimation of original gas in place and of likely yield with time.

Introduction

The exploitation of shale gas using hydraulic fracture, or the performance of a shale as a seal above a conventional gas reservoir depends on the rate at which gas can flow through the pores of the rock matrix. It is known that the permeability of shale to gas depends on the difference between the pressure of the gas in the intergranular pore spaces and the externally applied overburden pressure, but successful modelling of reservoir or seal behaviour depends upon knowing the form of the permeability/pressure relationship and the values of the parameters. These can only be determined through laboratory measurements.

We seek to determine whether a common generic pattern of a permeability/pressure relationship might exist between different shales, by means of measurements on two mineralogically comparable shales over the whole range of reservoir pressure conditions likely to be encountered, to determine the relevant parameters and to consider the implications of the results for the interpretation of well tests.

Two Jurassic shales are considered:

(a)   Whitby shale, collected from the low-tide level at Runswick bay, North Yorkshire, England, so that the rock was always submersed in sea water. A petrographic description of this rock and the preliminary permeability data is given in McKernan et al. (2014) but is summarized as follows. It is a clay-bearing, well-foliated silt-rich mudstone, Porosity 8%, Total organic carbon (TOC) 1.5%. Samples were dried to constant weight at 60 oC before use.

(b)   Haynesville shale (Texas), core samples provided by BG International, depth and precise location unspecified. The section of core used was chosen for its homogeneity and freedom from fractures. It is a silty-argillaceous to silty-calcareous, clay-bearing mudstone, well-foliated, porosity 9%, TOC 4%. As-supplied water saturation is 40%+10%.

Experimental Methods

Permeabilities (k) were expected to be low (on the order of 10-17 m2 or less, hence were measured over a range of total confining pressure (Pc) up to 95 MPa and argon gas pore pressures (Pp) over the same range using both the oscillating pore pressure method (Bernabé et al., 2006; Fischer and Paterson, 1992; Kranz et al., 1990; Faulkner and Rutter, 1998; McKernan et al., 2014) and/or the pulse transient decay method (Brace, 1968). For the pulse transient decay method, the upstream pressure was maintained constant by servo-control, so that the upstream volume was effectively infinite. This simplifies data processing.

It was anticipated that the relationship between permeability, total hydrostatic pressure, and pore fluid pressure would be non-linear and take the form

       ln k = ln A – g Pc + b Pf                                                                                                 (1)

in which  A,  g and b are empirical parameters. This can be re-cast as

       ln k = ln A – g(Pc  – a Pf ),   in which a = b/g  .                            (2)

If parameter a = 1, the pore pressure can be considered fully effective, so that a change in pore pressure produces the same effect on k as an identical change in confining pressure. If a < 1, the pore pressure can be considered less than fully effective, and if a > 1 it has a greater effect on k than a similar change in Pc. a can be > 1 if the pore spaces are effectively lined with an elastically more compliant phase than the framework of load-supporting grains. To determine parameters a and g  it is necessary to carry out experiments varying Pc at constant Pp and also varying Pp at constant Pc.

The compressibility of the samples was also determined by measuring the volume of pore fluid expelled from the pores at constant pore pressure with successive Pc increments. It is important to confirm that the rock responds elastically to changes in load when making permeability measurements.

2015 | Taylor, R.L., Mecklenburgh, J., McKernan, R., Rutter, E.H., Chandler, M.R. | 11th Euro-CONFERENCE on Rock Physics and Geomechanics, Ambleside | POSTER

Exploitation of shale gas using hydraulic fracture, or the performance of a shale as a seal above a conventional gas reservoir depends on the rate at which gas can flow through the pores of the rock matrix. Permeability of shale to gas depends on the difference between gas pressure in the intergranular pore spaces and the externally applied overburden pressure, but modelling of reservoir/seal behaviour depends upon knowing the form of the permeability/pressure relationship and the values of the parameters. These can only be determined through laboratory measurements.

Shale permeability is not constant, but varies significantly with confining and pore pressures and those tested exhibit common generic patterns. We seek to establish whether these patterns of permeability behaviour exist for different shales by determining their parameters experimentally. Pressure sensitivities of the gas permeability of two mineralogically comparable Jurassic shales were compared over the whole range of reservoir pressure conditions.

(1) Whitby shale - collected from the low-tide level at Runswick bay, North Yorkshire, England, so that the rock was always submersed in sea water. Clay-bearing, well-foliated silt-rich mudstone, porosity 8%, total organic carbon (TOC) 1.5%. Samples were measured dried to constant weight at 60 oC.

 (2) ‘Texas’ shale - core samples provided by BG International, depth and precise location unspecified. The section of core used was chosen for its homogeneity but still exhibits some fractures. Silty-argillaceous to silty-calcareous, clay-bearing mudstone, well-foliated, porosity 9%, TOC 4%. Samples were measured dried to constant weight at 60 oC and as-supplied. As-supplied water saturation is 40%+10%. 

The relationship between permeability, total hydrostatic pressure, and pore fluid pressure follows the general law

 k = A exp(- g(Pc – a Pp)) (1 + D / Pp)

 in which A, g, a and D are empirical parameters. g and a describe the sensitivity to confining and pore pressures. To determine parameters a and g it is necessary to carry out experiments varying confining pressure at constant Pp and varying pore pressure at constant Pc.

Permeability can vary by more than 3 orders of magnitude over the whole reservoir pressure range. Slip (Klinkenberg) flow is only significant at gas Pp < 5 MPa. Partial saturation of pore space with water or other fluids leads to a reduction in k, and in all cases flow is highly anisotropic. It is important to confirm that the rock responds elastically to changes in load when making permeability measurements. Over the range of reservoir pressure conditions pore volume changes with pressure are elastic and recoverable, except during the initial application of pressure.

If pressure sensitivity of permeability is not taken into account, reservoir evaluations from well tests will lead to substantial overestimation of original gas in place and of likely yield with time.

2015 | Rutter, E.H., Mecklenburgh, J., Taylor, R.L., McKernan, R.  | LPS One Day Seminar: What’s So Special About Core Analyses, London | TALK

2015 | Rutter, E.H., Mecklenburgh, J., McKernan, R., Taylor, R.L., Chandler, M.R., Taylor, K. | Shale World UK, Birmingham  | TALK