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.
Due to the complexity of tight shale reservoirs, core analysis has become an increasingly important source of data for evaluating these systems. However, as there are no generally agreed upon testing protocols, there are competing methods for obtaining such primary data as fluid saturations and porosity. The two most commonly employed commercial methods are Dean Stark toluene combined thermal and solvent extraction and thermal extraction by retort. However, the impact of these protocols on the rock and its fluid phases is different, primarily due to the abundance of clays. While the Dean Stark extraction produces a total porosity and total water saturation, data suggest significantly elevated values of these parameters relative to what is measured through the retort process, resulting from significantly higher amounts of water recovered. This distinction is fundamentally important for using core analyses in shale for calibrating logs and/or determining reserves, as both methods claim to report the same parameters.
To understand this effect, we have assembled a data set of compatible core analyses from various laboratories from several wells for a tight-gas shale reservoir in the United States. In addition, we conducted thermogravimetric analysis and Karl Fischer Titration with methanol extraction on splits of the same samples. The retort, thermogravimetric, and Karl Fischer data generally agree in the amount of water eluted from the samples (per gram of rock), while the Dean Stark data show significantly more water. We suggest this excess water could be a portion of the structural water in the clays, which should not contribute to porosity and saturation. Additionally, there is a relationship between this excess water and the total clay content from XRD. This correlation to XRD analyses suggests that a correction can be determined, leading to more accurate porosity and saturation values necessary for proper reserves estimations.
Kuila, Utpalendu (Colorado School of Mines) | Prasad, Manika (Colorado School of Mines) | Derkowski, Arkadiusz (Institute of Geological Sciences, Polish Academy of Sciences) | McCarty, Douglas K. (Energy Technology Company, Chevron)
Speculation exists about the presence of micropore and mesopore networks either exclusively within the organic matter or as pore systems in the inorganic components. This study presents a comparison of pore-size distributions (PSD) in a set of fine grained rocks from the Niobrara Formation using a combination of meticulous, precise, and repeatable laboratory preparation and measurement techniques. The analyses were performed on aliquot samples of ground powders (<0.4 mm) following rigorous procedures of homogenization and division (splitting) to obtain mineralogically and chemically equivalent portions for each analysis. The mesopore and micropore distribution was measured by conventional subcritical N2 gas-adsorption analysis at 77.3 K. These results, combined with quantitative mineral analysis by XRD and organic content and maturity measurements, indicate that the abundance of illite-smectite group clay controls the small scale pore features in the Niobrara Formation. The samples show a characteristic 3 nm pore-size distribution peak that correlates strongly with clay abundance, but not with organic content. The low thermal maturity of the organic matter (OM) further implies the lack of associated small pores. Instead, this non-porous OM hinders access to the fine mesopore structure of the clay aggregates.
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.??
Drilling of shale has long been a challenge due to its strong potential for wellbore instability. Designing of drilling fluids which minimize the interaction with shale is critical in the success of these drilling practices.
Shale instability is mainly related to its abundance of clay content, distribution of reactive clays such as smectite, bedding and thin laminae (fissility). In many situations, small faults and fractures may intersect laminated shale, which causes the
rock to crack in various directions. Though shale has many common properties, each shale formation has specific features in clay minerals, rock structures, and deformation properties; consequently their response to drilling fluids varies. As a result,
our goal is to understand the petrologic and deformation features of each specific shale formation and their potential interactions with various drilling fluids.
The traditional laboratory methods such as dispersion test, bulk hardness test, and swelling test cannot fully reflect the impacts of rock structure on fracture development and rock failing. This can be compensated by immersion test which is
designed to directly observe the rock-fluid interactions and fracture development. Our laboratory test results indicate that the composition and concentration of chemical additives in drilling fluids have significant impact on controlling and reducing the
interaction between shale and fluids. Based on laboratory studies, we have designed custom drilling fluids for many shale formations around the world. The custom drilling fluids reduce the inherent wellbore instability found in drilling shales.