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.
Tinni, Ali (University of Oklahoma) | Fathi, Ebrahim (Univ of Oklahoma) | Agarwal, Rajiv (University of Oklahoma MPGE) | Sondergeld, Carl H. (University of Oklahoma) | Akkutlu, I. Yucel (University of Oklahoma MPGE) | Rai, Chandra Shekhar (University of Oklahoma)
The economic viability of a shale play is strongly dependent on permeability which is often on the order of nanodarcies. Permeabilities are measured on core plugs or crushed samples using unsteady state techniques. However, the resultant permeabilities are the sources of controversy, because of the inconsistency in the permeability values produced with different techniques and different laboratories. In this research we evaluated the experimental factors which could influence permeability measurements with the GRI technique, and also present some permeability measurements on shale plugs.
To evaluate the GRI permeability measurement technique on crushed rock, we investigated the effect of particle size, sieving of the crushed samples, pore pressure, different gases, and initial state of the measurement apparatus. The measured crushed shale permeabilities display a dependency on all these parameters. However, the particle size and the pore pressure appear to be the more important factors. This makes the reported values strongly dependent on the exact measurement procedure. This study was complemented by the imaging of crushed shale samples with a micro-CT scanner. These images showed the presence of microcracks even in samples as small as the recommended GRI particle size (~0.7mm).
The permeabilities of several Devonian and Ordovician age shale plugs were measured with a pressure build up technique using nitrogen as flowing gas. A permeability decrease by an order of magnitude was generally observed for the Ordovician shale plugs with an increase of confining pressure from 1000 to 5000 psi. For the same Ordovician shale, the permeability anisotropy was found to be close to 2 orders of magnitude.The permeability of the Devonian shale plugs decreased by a maximum of 3 orders of magnitude over the range of confining pressure. For most shales, the confining pressure dependency of permeability is driven by cracks which is confirmed by a fit to Walsh's crack permeability model. However, we also noticed that it is possible to close the cracks contained in some plugs and obtain a value more representative of matrix permeability.
Kumar, Vikas (University Of Oklahoma) | Curtis, Mark Erman (University of Oklahoma) | Gupta, Nabanita (University of Oklahoma) | Sondergeld, Carl H. (University of Oklahoma) | Rai, Chandra Shekhar (University of Oklahoma)
Shales are one of the most heterogeneous and complex natural materials found. Recent spike in the activities in shale gas and oil plays has been possible through horizontal drilling and hydraulic fracturing, which requires better understanding of
mechanical properties. Complexities associated with elastic properties of shale are amplified with presence of wide range of organic fraction present in them. There is a need to understand the mechanical properties of organics and their associated
impact on bulk mechanical properties.
Scanning Electron Microscopy with focused ion beam milling and nano-indentation have been employed to calculate mechanical properties of kerogen at the submicron level in Woodford shale samples of different maturities. A displacement
of 500 nm was applied to investigate mechanical properties of kerogen and force in the range of 400-500 mN was applied to measure average mechanical properties of shale.
Young's modulus of kerogen was found to be linked to localized porosity as well as maturity. Kerogen in different samples with vitrinite reflectance range of 0.5-6.36 % and almost no porosity showed Young's moduli in the range of 6-15 GPa,
whereas, kerogen with significant porosity showed values as low as 1.9-2.2 GPa. Young's modulus measured by nanoindentation on small shale samples (~ 5-10 mm) was found to be in good agreement with dynamic modulus measured on core
plugs (~cm). Young's modulus is most sensitive to the Total Organic Carbon present. Increase in organics is found to qualitatively reduce both Young's modulus and hardness.
Measurement of elastic properties of shale is significant for optimizing hydraulic fracture design, for well stability study and better seismic velocity prediction in shale. This technique requires small sample dimension, on the order of millimeters, for
experiment and thus eliminates the requirement of larger, centimenter, size samples. This is particularly significant for shale as they are mechanically and chemically unstable which makes retrieval of larger core samples challenging.
Surface seismic offers a promising technique to monitor CO2 flood fronts during enhanced oil recovery process. Changes in seismic signature have been observed with CO2 flooding but quantification of the seismic signature with respect to subsurface saturation is still in its infancy. This study is focused on quantification of the variation in seismic parameters (velocity and impedance) with the change in subsurface fluid type and saturation.
The results of a laboratory study are presented where velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) are replaced sequentially. All the experiments were performed at in-situ pressure conditions on plugs (Tuscaloosa sandstones) recovered from a well in a field currently undergoing CO2 flooding. The plugs used are characterized as fluvial (quartz~87%, clay~10%) and distributary channels (quartz~75%, clay~17%).
During brine flooding on dry samples, a decrease in P-wave velocity (~2%) was observed till 95% saturation and thereafter the velocity increases by 15% during the remaining 5% saturation. After attaining 100% brine saturation, oil was pumped to displace brine till irreducible water saturation was achieved. A linear drop of 4% in velocity was observed during this step. Liquid CO2 was injected to displace oil-brine system and a drop of 8% in P-velocity was observed. Associated changes in P-wave impedance due to change in pore fluid saturation are 25%, -5% and -8% respectively for the three flooding experiment. Biot-Gassmann modeling shows good agreement with experimental results for gas-brine and oil-brine system but not for liquid CO2 flooding.
4D seismic data set acquired over the same region is quantitatively interpreted based on these laboratory measurements.
Since the discovery of pores in the organic matter of gas shales, the conventional thought has been that the pores formed as a result of hydrocarbon generation during the thermal maturation of the organic matter. However, thermal maturity alone may not be the only factor in determining the formation and preservation of pores in the organic matter. In this paper we report on a study of organic porosity in Woodford Shale samples with vitrinite reflectances ranging from 0.51% Ro to 6.36% Ro. Using focused ion beam (FIB) milling and scanning electron microscopy (SEM), it is observed that while the first appearance of porosity for the samples occurs by 1.23% Ro, there are anomalies. One anomaly is the complete lack of organic porosity in the 2.00% Ro sample. In addition, some samples with a vitrinite reflectance = 1.23% Ro exhibit regions of porous organic matter adjacent to non-porous organic matter regions that are separated by a few microns Observations show that while some regions of porous organic matter appear protected by grains others appear stress-supporting. These observations have important consequences for using indicators such as thermal maturity in predicting the occurrence of pores in the organic matter of shales.
We report on a nano-indentation study of shales from the Barnett, Woodford, Ordovician, Eagle Ford and Haynesville plays. Careful selection of load and displacement during nano-indentation testing yields micro to macro-mechanical properties, Young's modulus and hardness, of shale. Scanning Electron Microscope coupled and nano-indentation were used to study the mechanical behavior of kerogen. The measured Young's modulus of kerogen varied from 5 to 9 GPa. Mineralogy is found to play an important role in controlling mechanical properties of shales; an increase in carbonate and quartz content is correlated with an increase in Young's modulus whereas, an increase in TOC, clay content and porosity decreases Young's modulus. Close agreement is found between indentation moduli measured on small samples (mm scale) and dynamic moduli calculated from velocity and density measurements made on larger samples (centimeter scale). Tests conducted on cuttings provided results comparable to measurements made on larger core samples. Nano-indentation can provide a viable means of assessing quantitative measure of shale "fraccability.??
Hydraulic fractures are traditionally modeled as planar features developed by the tensile failure of the rock. Laboratory nanoseismic and field mine-back studies show that most of the fractures are non-planar complex features. Fracture properties are strongly affected by the magnitudes and directions of the stresses in the formation. Low stresses are associated with a complex fracture development while high stresses create simpler, straighter and more planar fractures. We report the results of controlled laboratory triaxial hydraulic fracturing experiments instrumented with piezoelectric sensors. We performed tests on Lyons sandstone which was determined to have an initially isotropic velocity structure. The fracturing experiments have been performed under triaxial stress state to replicate the insitu stress reservoir conditions. The uncertainty in hypocenter locations, frequency analysis, source mechanisms and the effects of stress on fracture propagation will be discussed. Microscopic observations of the fractures are correlated with the mapped microseismic events. Fractures are observed to be non-planar visually and at the SEM scale. Shear failure recorded by focal mechanisms appears to dominate the failure mode. The deviation from planarity will surely affect proppant transport and dispersement.
A model-assisted analysis is presented of pressure-pulse-transmission data obtained under different pressure conditions with core plugs of shale-gas formations. Applications and validations for steady-state and transient-state laboratory tests are provided. Best-estimate values of the intrinsic permeability and tortuosity at a reference condition and the Langmuir volume and pressure are determined by matching the solution of a modified Darcy model to several pressure-pulse-transmission flow tests with core samples simultaneously. The data-interpretation model considers the prevailing characteristics of the apparent permeability under the various flow regimes involving gas flow through extremely low-permeability core samples. Further, the present fully pressure-dependent shale- and gas-property formulation allows for model-assisted extrapolation from the reference conditions to field conditions once the unknown model parameters have been estimated under laboratory conditions. The improved method provides a better match to the measurements of the pressure tests than previous models, which assume only Darcy flow.