Carl H. Sondergeld

Microstructural investigation of gas shales in two and three dimensions using nanometer-scale resolution imaging

The microstructure of gas shale samples from nine different formations has been investigated using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM). Backscattered electron (BSE) images of FIB cross sectioned shale surfaces show a complex microstructure with variations observed among the formations. Energy dispersive spectroscopy of the shale cross sections indicates that clay, carbonate, quartz, pyrite, and kerogen are the most prevalent components. In the BSE images, areas of kerogen are observed interspersed with the inorganic grains. Pores are observed in both the kerogen and inorganic matrix with the size, shape, and number of pores varying among the shale samples. By using FIB milling and SEM imaging sequentially and repetitively, three-dimensional (3-D) data sets of SEM images have been generated for each of the shale samples. Three-dimensional volumes of the shales are reconstructed from these images. By setting thresholds on the gray scale, the kerogen and pore networks are segmented out and visualized in the reconstructed shale volumes. Estimates of kerogen and pore volume percentages of the reconstructed shale volumes have been made and range from 0 to 90.0% for the kerogen and 0.2 to 2.3% for pores. Estimates of pore-size distributions suggest that although pores with radii of approximately 3 nm dominate in number, they do not necessarily dominate in total volumetric contribution. Scanning electron microscopy images and 3-D reconstructions reinforce the facts that shales are quite different and that their microstructures are highly variable and complex.

New Pore-scale Considerations for Shale Gas in Place Calculations

Using FIB/SEM imaging technology, a series of 2-D and 3-D submicro-scale investigations are performed on the types of porous constituents inherent to gas shale. A finely-dispersed porous organic (kerogen) material is observed imbedded within an inorganic matrix. The latter may contain larger-size pores of varying geometries although it is the organic material that makes up the majority of gas pore volume, with pores and capillaries having characteristic lengths typically less than 100 nanometers. A significant portion of total gas in-place appears to be associated with inter-connected large nano-pores within the organic material. This observation has several implications on reservoir engineering of gas shales. Primarily, thermodynamics (phase behavior) of fluids in these pores are known to be quite different. Most importantly, gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a density profile across the pore with damped-oscillations. This raises the following serious questions related to gas-in-place calculations: under reservoir conditions, what fraction of the pore volume of the organic material can be considered available for the free gas phase and what fraction is taken up by the adsorbed phase? If a significant fraction of the organic pore volume is taken up by the adsorbed phase, how accurately is the shale gas storage capacity estimated using the conventional volumetric methods? And, finally, do average densities exist for the free and the adsorbed phases and how large would a typical density contrast be in an organic pore for an accurate gas reserve calculation? In order to answer these questions we combine the Langmuir equilibrium adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the organic pore space taken up by the sorbed phase. The method yields a total gas-in-place prediction based on a corrected free gas pore volume that is obtained using an average adsorbed gas density. Next, we address the fundamental-level questions related to phase transition in organic matter using equilibrium molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature. We predict methane density profiles across the pores and show that (i) an average total thickness for an adsorbed methane layer is typically 0.7 nm, which is roughly equivalent to 4% of a 100 nm diameter pore volume, and (ii) the adsorbed phase density is 1.8-2.0 times larger than that of the bulk methane, i.e., in the absence of pore wall effects. These findings suggest that a significant level of adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, we perform a series of calculations using the new volumetric method and show a 10-25% decrease in total gas storage capacity compared to that using the conventional approach. This additionally could have a larger impact in shales where the sorbed gas phase is a more significant portion of the total gas-inplace. The new methodology is recommended for estimating shale gas-in-place and the approach could be extended to other unconventional gas-in-place calculations where both sorbed and free gas phases are present.

Gassmann fluid substitutions: A tutorial

Fluid substitution is an important part of seismic attribute work, because it provides the interpreter with a tool for modeling and quantifying the various fluid scenarios which might give rise to an observed amplitude variation with offset (AVO) or 4D response. The most commonly used technique for doing this involves the application of Gassmanns equations.Modeling the changes from one fluid type to another requires that the effects of the starting fluid first be removed prior to modeling the new fluid. In practice, the rock is drained of its initial pore fluid, and the moduli (bulk and shear) and bulk density of the porous frame are calculated. Once the porous frame properties are properly determined, the rock is saturated with the new pore fluid, and the new effective bulk modulus and density are calculated.A direct result of Gassmanns equations is that the shear modulus for an isotropic material is independent of pore fluid, and therefore remains constant during the fluid substitution process. In the...

Elastic anisotropy of shales

Accompanying the resource potential of gas shales is a new interest in understanding the physical and petrophysical properties of shales. Shale by geochemical or stratigraphic measures is arguably the most common lithology encountered in sedimentary basins. Despite this, shales remain little studied while engineers and explorationists focused on conventional reservoirs. Geophysicists did this knowing full well that often a reflection coefficient from a reservoir was controlled by the shale properties of the cap rock. We compensated for this ignorance by arguing that shales are deposited in deepwater environments in which lateral and vertical changes are slow and therefore inconsequential. We further compounded this ignorance by assuming that the shales were isotropic. An example of the consequences of this ignorance was clearly documented by Margesson and Sondergeld (1999). Engineers share culpability for this ignorance too, since most of the drilling problems occur in shales and most of the lithologies d...

Rock properties in low-porosity/low-permeability sandstones

Tight gas sand reservoirs are formally defined by the Federal Energy Regulatory Commission (FERC) as reservoirs with less than 0.1 md permeability. Although this is a permeability-based definition, these reservoirs frequently also have very low porosities ( 15 000 ft (Oil and Gas Investor, 2005).

Acoustic well logging method and system

A method and system for acoustic well logging for obtaining an indirect measure of shear wave velocities for earth formations surrounding a well borehole. The method and system relate to an indirect technique for inverting Stoneley wave velocity data to obtain an estimate of shear wave velocities of formations surrounding the borehole substantially concurrent with the logging operation. A subassembly adapted to be connected to an acoustic well logging sonde and form a part thereof provides measures of fluid density and velocity, and borehole radius as well as formation density and impedance. By combining the output of the well logging sonde and subassembly with the aid of a processor, one is able to obtain a measure of formation shear wave velocities, by constraining the inversion of measured Stoneley wave velocity data, substantially in real-time. This method is especially useful in slow formations where direct shear wave velocities cannot be obtained or where shear wave velocities are difficult to obtain.

An NMR Study of Shale Wettability and Effective Surface Relaxivity

Traditional methods of determining wettability such as the Amott and the U.S. Bureau of Mines (USBM) test for an oil/brine/rock system are difficult to apply to shales due to their extremely low permeability, usually in the nanodarcy range. Earlier Nuclear Magnetic Resonance (NMR) studies on Berea sandstone showed consistency with standard wettablity measurements and served as a calibration standard. A total of 10 core plugs from an Ordovician organic rich shale were analyzed. The T2 NMR signature of the imbibed dodecane and brine occurred mostly at relaxation times faster than their measured bulk relaxation of 1 and 3 second, respectively, indicating that surface relaxation is dominant. The Ordovician organic rich shale display mixed wettability. Three of the samples had a high affinity for dodecane, as a result of the organic pores present in the samples. This result was consistent with the NMR spectra in both sequences as well as the gravimetric analysis. The main advantage NMR has over the traditional methods is that we are able to see where the fluids are being imbibed. Mercury injection capillary pressure (MICP) characterizes the distribution of pore throats while NMR responds to the pore bodies. Assuming the throats and bodeies are equivalent, a scaling factor was used to match the NMR spectra and the MICP curves to estimate the effective surface relaxivity for the shale samples. The range of the effective surface relaxivities ranged between 0.5μm/sec to 3.1μm/sec with an average of 1.7 ± 1.0 μm/sec. Mineralogy variations were observed across the 10 shale samples but showed a correlation which suggests that the effective surface relaxivity is dependent on mineralogy.

Laboratory observations of shear-wave propagation in anisotropic media

Shear‐wave exploration has been revitalized in recent years with the recognition and proper treatment of shear‐wave velocity anisotropy. The subsurface anisotropy we are concerned with is referred to as azimuthal anisotropy and, for simplicity, has been assumed to exhibit hexagonal symmetry or transverse isotropy with a horizonal unique axis. However, before one can address the interpretation of shear‐wave field data, one must provide (as input to the discussion) proper shear‐wave data. To do this, one must accept the validity of R.M. Alford’s 1986 rotational transformations. We have devised a series of laboratory experiments which clearly show the equivalence implied in Alford’s algorithm between physical and mathematical rotation. Furthermore, these studies give new insight into the complexities of field data acquired under conditions of vertically misaligned azimuthal anisotropy.

Effective noise discriminator for use in acoustic emission studies

Both coherent and random short duration electromagnetic noise source pose serious problems to meaningful acoustic emission studies. A simple but effective discriminator is described which makes acoustic emission studies possible in severe noise environments. Additional circuitry is presented which permits one to eliminate coherent noise sources from the acoustic emission data.

Research Note: Experimental measurements of Q-contrast reflections

While seismic reflection amplitudes are generally determined by real acoustical impedance contrasts, there has been recent interest in reflections due to contrasts in seismic-Q. Herein we compare theoretical and modelled seismic reflection amplitudes for two different cases of material contrasts. In case A, we examine reflections from material interfaces that have a large contrast in real-valued impedance (ρv) with virtually no contrast in seismic-Q. In case B, we examine reflections from material interfaces that have virtually no contrast in ρv but that have very large seismic-Q contrasts. The complex-valued reflection coefficient formula predicts non-zero seismic reflection amplitudes for both cases.We choose physical materials that typify the physics of both case A and case B. Physical modelling experiments show significantly large reflections for both cases – with the reflections in the two cases being phase shifted with respect to each other, as predicted theoretically. While these modelling experiments show the existence of reflections that are predicted by theory, there are still intriguing questions regarding the size of the Q-contrast reflections, the existence of large Q-contrast reflections in reservoir rocks and the possible application of Q-reflection analysis to viscosity estimation in heavy oilfields.