Article pubs.acs.org/EF
Shale Gas Potential of the Major Marine Shale Formations in the Upper Yangtze Platform, South China, Part III: Mineralogical, Lithofacial, Petrophysical, and Rock Mechanical Properties Jingqiang Tan,*,† Brian Horsfield,† Reinhard Fink,‡ Bernhard Krooss,‡ Hans-Martin Schulz,† Erik Rybacki,† Jinchuan Zhang,§ Christopher J. Boreham,∥ Ger van Graas,⊥ and Bruce A. Tocher⊥ †
GFZ-German Research Centre for Geosciences, 14473 Potsdam, Germany Energy and Mineral Resources Group (EMR), RWTH Aachen University, 52064 Aachen, Germany § China University of Geosciences (Beijing), 100083 Beijing, China ∥ Geoscience Australia, Australian Capital Territory 2601 Canberra, Australia ⊥ Statoil, Martin Linges vei 33, Oslo, Norway ‡
ABSTRACT: The marine black shale formations on the Upper Yangtze Platform, South China, are currently exploration targets for shale gas. Here, we report on the mineralogy, lithofacies, petrophysics, and rock mechanics of samples collected from the Ediacaran (Upper Sinian), Lower Cambrian, and Lower Silurian black shale intervals. All three formations are composed of high proportion of quartz, low content of clay, and rare or nonexistent content of carbonates. The Ediacaran and Lower Cambrian shales deposited in restricted deep water marine platform to marine basin environments are characterized by a higher quartz content and lower clay content than the Lower Silurian shales that were deposited in a more restricted marine basin environment. The carbonate content varies from 0 to over 50%, with the higher values measured in the Lower Silurian samples. These stratigraphic units were formed during bottom water anoxic conditions; therefore, they were rarely influenced by bioturbation. Lithologically, laminated and nonlaminated siliceous mudstones predominate, with minor contributions of other lithotypes. Pores generally have diameters in the nanometer (nm) to micrometer (μm) range, and numerous pores occur in organic matter. Most of the measured samples have porosities less than 4%, although a few samples show porosity in excess of 10%. Pores with radii less than 50 nm contribute significantly to total pore volume and total porosity. Permeability is extremely low, and helium permeability coefficients (Klinkenberg corrected permeability coefficient) are less than 20.2 nD (nano-Darcy, ∼2 × 10−20 m2). The rock mechanical properties of the samples are characterized by high brittle behavior, which coincides with their high compressive and tensile strengths and elastic properties. The Lower Cambrian shale is generally more brittle than the Lower Silurian shales, which possess a relatively higher content of clay minerals. The rock mechanical properties of the measured samples, however, depend on the overall mineral compositions and physical properties.
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stimulation.4−7 Nevertheless, these rock properties must be considered in a larger geological context of stress fields. Having all the optimum properties with poorly defined stress fields could result in poor wells even in good shale gas regimes. Shale gas exploration in China is in its infancy. Marine black shales, which comprise the Ediacaran (Upper Sinian), Lower Cambrian, and Lower Silurian shale intervals, are found throughout the Upper Yangtze Platform (UYP) in South China. These sediments have long been known to be the principal source rocks for conventional petroleum fields in the Sichuan Basin8 and have been more recently recognized to host promising unconventional shale gas potential.9−11 The GIP of the Lower Cambrian and Lower Silurian shale has been estimated at 349 and 343 trillion cubic feet, respectively.12 Despite their tremendous potential, the petrophysical and rock mechanical properties are poorly documented. The mineralogical composition of the Lower Silurian and Lower Cambrian shale has recently been used
INTRODUCTION Unconventional shale gas plays are unique in that they contain three of the classical elements of petroleum systems: source-, reservoir-, and seal-rock.1−3 To understand and therefore predict the viability of an unconventional shale reservoir, it is important to estimate the gas-in-place (GIP), both vertically and laterally, and establish the optimum method of producing the gas by simulation techniques. In addition, the heterogeneity of the target formation must be taken into account and a number of important parameters that relate to successful shale plays should be characterized, e.g., sedimentological architecture, organic richness, thermal maturity, mineralogical composition, lithofacies, as well as petrophysical and rock mechanical properties. As a result of generally low permeability and sorption mechanisms playing important roles in a shale gas play, key technologies for successful shale gas production are necessary; that is, horizontal drilling and hydraulic fracturing. It is thus mandatory that detailed investigations of the mineral constituents, texture, fabric, and physical and mechanical properties of shales should be conducted to successfully exploit the shale reservoir. A wellconsidered completion strategy entails evaluating the role of these properties for the susceptibility of a shale play to successful © 2014 American Chemical Society
Received: November 19, 2013 Revised: February 17, 2014 Published: March 5, 2014 2322
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Figure 1. Overview maps of the Yangtze Platform, South China (A), and the Georgina Basin, North Australia (B). Numbers show the investigated profiles and wells, and names are listed in Table 1.
as a proxy for brittleness based on a “ternary comparison” of carbonate, quartz and clay content.9,13−17 Nevertheless, comprehensive and systematic investigations are rare, resulting in indistinct correlations of these major rock physical properties. In this paper, we present new insights into the lithofacies, petrophysics, and rock mechanical properties of these Pre- to Early Paleozoic marine shale intervals.
Samples collected from 15 profiles/wells in the core area of the UYP were examined from the centimeter-scale (cm, hand specimen and light microscopy) down to the nanometer-scale (Transmission Electron Microscope, TEM). The results were correlated with the data of mineralogical composition, porosity and permeability and the elastic properties and mechanical strengths gained by a series of rock mechanical experiments. 2323
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Additionally, published data, including the X-ray diffraction (ale) results of nearly 700 samples from more than 20 profiles/wells scattered on the UYP, were compiled with the purpose of characterizing mineralogical properties. Furthermore, samples from the Georgina Basin, North Australia, were also investigated because Cambrian shale in the Georgina Basin is considered an
immature equivalent of the over mature Cambrian shale on the UYP in terms of its organic geochemical composition.18
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EXPERIMENTAL DETAILS
Analyzed Samples. The analyzed sample set is composed of rocks from the UYP, South China (UYP samples) and Georgina Basin, North
Table 1. Investigated Samples and Applied Measurementsa
a UYP: the Upper Yangtze Platform. AU: Australia (the Georgina Basin). XRD: X-ray powder diffraction. LM: Light microscope. SEM: Scanning electron microscopy. TEM: Transmission electron microscopy. MIP: Mercury injection porosimetry. HP: Helium pycnometry. GP: Gas (helium) permeability. UC: Uniaxial compression test. TC: Triaxial compression test. BD: Brazilian disk tensile test. UV: Ultrasonic velocity.
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minerals. The diffraction data were recorded from 4° to 75° 2 θ with a step width of 0.02° and a counting time of 4 s per step. The generator settings were 40 kV and 30 mA. Measured data were then analyzed qualitatively using the EVA (Bruker) software and quantitatively using the AutoQuant software. Mercury Intrusion Porosimetry (MIP). Mercury injection porosimetry was performed on most of the core samples and several outcrop samples to determine the bulk density, equivalent pore radius distribution, and interconnected pores in the micrometer and nanometer range. Sample fragments with approximately 20 × 20 mm and 10−20 g were prepared and dried in an oven for 24 h at 50 °C. Subsequently, sample fragments were placed in a container (dilatometer) and mounted on the apparatus. The measurements were performed using a Fisons Instruments Mercury Porosimeter, and the results were calculated using the Washburn equation.29 The mercury pressure increased from 0.0013 to 200 MPa, which corresponds to an equivalent pore radius from 58 μm to 3.7 nm. Helium Pycnometry. Helium pycnometry was performed on most of the core samples and certain outcrop samples using the pycnometers at RWTH Aachen University and GFZPotsdam to determine the skeletal density of the sample. Measured materials were cuttings with a diameter between 0.5 and 1.0 mm, and they were dried in vacuum conditions at 105 °C. Helium Permeability. Helium permeability measurements were conducted on four UYP samples at RWTH Aachen University. Plugs were in as-received conditions and measured using a triaxial flow cell, which was designed for confining pressures up to 50 MPa and axial loads up to 100 KN. We applied a nonsteady state technique that is described in detail by Ghanizadeh et al.30,31 to measure apparent gas permeability (kgas) coefficients at different mean pressures (Pmean). kgas was calculated from the pressure decline/incline curves at the upstream/downstream reservoirs we calculated according to Ghanizadeh et al.,31 and the corrected permeability k∞ was calculated using the formulation of Klinkenberg.32 In this research, the applied confining pressure was 30 MPa at temperatures of 46 and 52 °C. The pressure difference between the upstream and downstream reservoir (ΔP) at the beginning of each experiment was approximately 20 bar, excluding certain measurements of sample 43 (
