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.
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.??