Second EAGE Workshop on Shales

North American data demonstrate that shale-gas productivity is a function of a suite of economically significant mudstone properties that vary laterally and vertically at a variety of length scales. Properties of interest include porosity type and amount, permeability, mechanical properties, organic matter type and concentration, stratification style, parasequence and bed thickness, natural fracturing, etc. Many of these variables are controlled, at least in part, by the processes and environments of mudstone deposition. The mudstones of North American shale-gas plays were deposited in tectonic settings that include passive margins (e.g., Haynesville, Barnett), foreland basins (e.g., Lewis, Marcellus) and intracratonic basins (e.g., Antrim). Knowledge of depositional processes and sequence stratigraphic concepts in these systems is used to help define which basins are more attractive as exploration targets, which portions of a basin are likely to produce more gas, which stratigraphic intervals are likely to be targets for horizontal drilling, and even how core sampling should be undertaken and interpreted. Fine-grained sedimentary deposits show heterogeneity at every level, and integration of microscopic- to sequence-scale observations (e.g., SEM imagery, thin sections, core/outcrop, wireline logs, seismic) and interpretations is essential.

This paper describes a case study from the Fort Worth Basin (USA), where the occurrence of residual gas in the Barnett shale was analyzed using standard basin modeling. The aim of this work was to determine to what extent conventional petroleum system simulation approaches can be applied to an unconventional system like gas shale. A sensitivity analysis was thus performed, to quantify the dependency of the residual mass of gas in the source rock at present day, on parameters involved in the generalized Darcy flow model, i.e., permeability, relative permeability, capillary pressure and adsorption threshold parameters. We found that gas retention in the source rock was mostly controlled by the gas relative permeability, and especially the gas expulsion saturation (i.e., ‘Satex’ value). High capillary pressure in the shale favours gas expulsion, however this process remains limited compared to relative permeability and permeability effects. Surprisingly, adsorption threshold values had nearly no effect on the residual mass of gas: adsorption was indeed largely compensated by the Satex effect. These results demonstrate that conventional basin modelling can reproduce the occurrence of a gas shale play, by adjusting at least gas relative permeability parameters in the source rock, especially the Satex value.

Two different quartz cement morphologies have been identified in originally smectite-rich Late Cretaceous mudstones. 1) Extremely fine-grained micro-pore-filling quartz (sub-micron to 1-3 µm) found as spherical discrete grains or as part of short chains/clusters of several inter-connected micro-quartz crystals. This type is also typically inter-grown with clay crystals and found embedded in the fine-grained illitized clay matrix below 2500 m burial (80-85 ºC). 2) Quartz platelets oriented normal to the overburden as laterally extensive sheets with typical irregular or patchy development. The quartz platelets originate as extremely thin flakes that evolve into well-developed patchy continuous quartz cement as identified at 4300 m/150 ºC. The identified quartz cement were most likely sourced by silica released from the dissolution of smectite and precipitation of illite-smectite and illite due to evaluated silica super-saturation in the system. The observed inter-connected micro-quartz crystals are associated with a sudden Vp-velocity increase reflecting an increase in the mudrock stiffening interpreted to be related to pervasive micro-quartz networks and aggregate formation. The quartz platelets will reinforce and further cement together the micro-quartz networks and aggregates during burial.

The microstructural characteristics of a shear zone developed in Plio-Pleistocene mudstones of the Southern Apennines have been analysed by means of XRD, SEM, optical microscope observation and a consolidation test. XRD analyses indicate that the wall rock contains mixed layer illite/smectite while the fault gauge contains illite only. The distribution patterns of smectitic and illitic mudstones is analysed thanks to a simple peeling technique that allows observation with optical microscope and SEM. The consolidation test provides indications on the depth at which deformation occurred.

We used undrained multi-stage triaxial tests to evaluate how the ultrasonic wave velocities and their anisotropy changed with increasing isotropic and differential stress conditions. In addition, the impact of stress orientation with respect to fabric orientation was evaluated. An array of ultrasonic transducers allowed to measure five independent wave velocities which were used to calculate the elastic properties of the shale. Results indicate that in this shale P- and S-wave velocities vary with stress in a different manner dependent on the maximum stress orientation with respect to the fabric orientation. Where the maximum stress is normal to bedding, Vpv and Vs1 increase monotonically with increasing effective stress. However Vph and Vsh decrease during individual loading stages but increase from stage to stage as confining pressure increases. The reverse occurs when the microfabric is parallel to the maximum principal stress. Where the maximum stress is bedding normal, velocity anisotropy decreases as differential stress increases; when maximum stress is fabric parallel, anisotropy increases. Intrinsic anisotropy is related to the initial composition and fabric of the sediment, while changes in elastic anisotropy result from the applied stresses, their orientation to the rock fabric and the degree of stress anisotropy

The purpose of the study is to characterize the main features of the anisotropic mechanical behaviour of a shale (Opalinus Clay), and to identify an anisotropic constitutive framework adapted to the response of the material under mechanical perturbations. Such a constitutive model is required for the simulation of triaxial tests which were done on OC samples. Firstly, the large quantity of available laboratory tests which characterize the mechanical response of OC has been analyzed. The test series provide clear evidence for anisotropic mechanical behaviour of Opalinus Clay. It appears that the stress history and the micro-structure of the material induce a typical response of the material which is more overconsolidated (higher rigidity, less ductile behaviour…) for loading direction parallel to the bedding plane than perpendicular to it. Concerning numerical investigations, the capabilities of the model of Hujeux have been assessed in reproducing the anisotropic features of behaviour of OC. The constitutive model uses the theory of multi-mechanisms plasticity. Two fundamental observations account for the adequacy of the chosen constitutive framework: the elastic moduli depend on the direction of shearing, and induced anisotropy will affect the way the material hardens or softens depending on the angle of shearing.

The emerging imaging and computing technology is especially effective for gas-shale where the knowledge and understanding of the internal pore architecture (down to 3 nanometer scale) is crucial for determining connected vs. unconnected porosity, TOC distribution and maturity, pore size distribution, mineralogy, sample-scale heterogeneities, computing 2 phase flow, and Interrelate all properties on same sample.

A case history of detecting "sweet spots" associated with zones of high permeability in a tight gas reservoir using multicomponent seismology.

Shale gas reservoirs have become important hydrocarbon targets for oil and gas companies. Fractures and stress fields play important roles in the development of shale gas reservoirs. New seismic analysis methods enable geoscientists to map fracture patterns and associated permeability changes, allowing E&P operators to better target highly productive zones within these tight, heterogeneous reservoirs. Horizontal transverse isotropy (HTI) is an important issue for shale gas reservoirs and can be an effect of such things as vertical aligned fractures or unequal horizontal stresses. Azimuthal velocity analysis allows the measurement of HTI effects in wide azimuth seismic data and the determination of important azimuthal velocity anisotropy attributes. Calibration of the anisotropy attributes with well data can provide information regarding fracture density and orientation as well as horizontal stresses, thereby allowing geoscientists to predict sweet spots in shale gas reservoirs.

To improve the understanding of behavior related to the borehole geometry in shales, and to generate better input data to borehole stability simulators to be used when estimating the stable mud weight window, we have developed an experimental methodology whereby we perform rock mechanical laboratory tests on various shales in a hollow cylinder geometry. We present our methodology, including both laboratory measurements, how such data and other data are fed into our borehole stability simulator, as well as results for specific cases. These tests allow for a better understanding of failure mechanisms causing borehole instabilities and providing calibration data to borehole stability models. When integrated into proper borehole stability simulators it thus represents an applicable tool for attaining improved drilling performance while drilling through shales.