Eagle Ford Shale Samples Research Articles

Methane and CO2 Adsorption Capacities of Kerogen in the Eagle Ford Shale from Molecular Simulation.

Over the past decade, the United States has become a world leader in natural gas production, thanks in part to a large-fold increase in recovery from unconventional resources, i.e., shale rock and tight oil reservoirs. In an attempt to help mitigate climate change, these depleted formations are being considered for their long-term CO2 storage potential. Because of the variability in mineral and structural composition from one formation to the next (even within the same region), it is imperative to understand the adsorption behavior of CH4 and CO2 in the context of specific conditions and pore surface chemistry, i.e., relative total organic content (TOC), clay, and surface functionality. This study examines two Eagle Ford shale samples, both recovered from shale that was extracted at depths of approximately 3800 m and having low clay content (i.e., less than 5%) and similar mineral compositions but distinct TOCs (i.e., 2% and 5%, respectively). Experimentally validated models of kerogen were used to the estimate CH4 and CO2 adsorption capacities. The pore size distributions modeled were derived from low-pressure adsorption isotherm data using CO2 and N2 as probe gases for micropores and mesopores, respectively. Given the presence of water in these natural systems, the role of surface chemistry on modeled kerogen pore surfaces was investigated. Several functional groups associated with surface-dissociated water were considered. Pressure conditions from 10 to 50 bar were investigated using grand canonical Monte Carlo simulations along with typical outgassing temperatures used in many shale characterization and adsorption studies (i.e., 60 and 250 °C). Both CO2 and N2 were used as probe gases to determine the total pore volume available for gas adsorption spanning pore diameters ranging from 0.3 to 30 nm. The impacts of surface chemistry, outgassing temperature, and the inclusion of nanopores with diameters of less than 1.5 nm were determined for applications of CH4 and CO2 storage from samples of the gas-producing region of the Eagle Ford Shale. At 50 bar and temperatures of 60 and 250 °C, CH4 adsorption increased across all surface chemistries considered by 60% and 2-fold, respectively. In the case of CO2, the surface chemistry played a role at both 10 and 50 bar. For instance, at temperatures of 60 and 250 °C, CO2 adsorption increased across all surface chemistries by 6-fold and just over 2-fold, respectively. It was also found that at both 10 and 50 bar, if too low an outgassing temperature is used, this may lead to a 2-fold underestimation of gas in place. Finally, neglecting to include pores with diameters of less than 1.5 nm has the potential to underestimate pore volume by up to 28%. Taking into consideration these aspects of kerogen and shale characterization in general will lead to improvements in estimating the CH4 and CO2 storage potential of gas shales.

Relative permeability estimates for Wolfcamp and Eagle Ford shale samples from oil, gas and condensate windows using adsorption-desorption measurements

Relative permeability in shales is an important petrophysical parameter for purposes of accurate estimation of production rate and recovery factor, efficient secondary recovery, and effective water management. We present a method to estimate relative permeability of aqueous and hydrocarbon phase in shales by processing the low-pressure nitrogen adsorption-desorption isotherm measurements. The interpretation method is applied to 35 samples from various maturity windows of Eagle Ford and Wolfcamp shale formations. The method assumes that effective medium theory, percolation theory, and critical path analysis can quantify the biphasic fluid transport in shales.The relative permeability curves were estimated for samples collected from 100ft interval in Eagle Ford gas window, 30ft interval in Eagle Ford oil window, and 60ft interval in Wolfcamp condensate window. Although the samples exhibit large variations in organic content, pore connectivity, range of connected pore network, and pore complexity, the relative permeability curves estimated for these samples exhibit relatively similar trends. Samples from gas and oil windows were low temperature plasma ashed to study the effects of removal of organic matter on relative permeability and pore network characteristics. The relative permeability of aqueous phase decreases sharply with decrease in water saturation, whereas the relative permeability of hydrocarbon phase decreases at a relatively slow and constant rate with increase in water saturation. Relative permeability estimates for the shale samples explain the low water-cut during hydrocarbon production, absence of correlation between hydrocarbon production decline and the increase in water production, and the existence of permeability jail in shale reservoirs.

Experimental Investigation on Brazilian Tensile Strength of Organic-Rich Gas Shale

SummaryTensile strength is a critical parameter for hydraulic fracturing, predicting fracture initiation and propagation in reservoirs, especially in shale reservoirs with complex natural fractures and fissures. The tensile strength of conventional rocks, such as sandstone and limestone, has been well-studied and -documented. There are many studies of the tensile strength of laminated shale, which focus on scale effects, loading direction, and temperature effects; however, the studies on effects of mineralogy and the water content on tensile strength of organic-rich shales are very limited.The objectives of this paper are to (1) critically review the key parameters that affect the tensile strength of shale and 2) experimentally examine the effects of water content, mineralogy, and lamination on tensile strength. To do so, a rigorous workflow is followed: 1) Each 1-in.-long shale sample is cut into two subsamples, A and B, of similar length; (2) X-ray computed-tomography (CT) scan is performed to diagnose pre-existing cracks and defects inside the core plugs; (3) nuclear magnetic resonance (NMR) is then used to measure the air dry samples’ water content; (4) Sample A is placed on a load frame to measure the tensile strength; (5) Sample B is vacuumed and then saturated; (6) NMR is used to measure the water content after saturation; (7) tensile strength of the saturated Sample B is measured; and (8) after the sample fails, the pieces are used for X-ray diffraction (XRD), scanning electron microscopy (SEM), and pyrolysis to estimate the mineralogy and total organic content (TOC).A total of 70 Mancos and 48 Eagle Ford shale samples have been tested. The experimental results show that (1) bedding plane/lamination has a significant effect on Eagle Ford tensile strength, but no pronounced impact is observed for the Mancos shale; (2) the imbibed water significantly reduces the tensile strength by 4.4 to 51.7% as water content increases from 4.45 to 11.7%; (3) pre-existing detectable microfractures can significantly reduce the tensile strength by up to 66%; (4) Eagle Ford exhibits typical brittle hard-rock failure configuration, with primary fractures and secondary fractures being observed, whereas for the Mancos shale, only primary fractures are observed; (5) acoustic velocity-test results confirm that Eagle Ford is mechanically transversely isotropic, and Mancos is likely mechanically isotropic.

Water/Rock Interaction for Eagle Ford, Marcellus, Green River, and Barnett Shale Samples and Implications for Hydraulic-Fracturing-Fluid Engineering

Summary Knowledge of water/rock interactions on the surface of fractures is important to develop an understanding of the geological structures and changes within the formation, and to determine hydraulic-fracturing (HF) performance. To obtain this knowledge, this study investigates water/shale interactions in carbonate-rich (Eagle Ford), organic-rich (Green River), clay-rich (Barnett), and other-minerals-rich (Marcellus) shale samples. Crushed shale samples were exposed to water for 3 weeks at reservoir conditions. The water and rock samples before and after each static experiment were subjected to several analyses. The change in the rock mineralogy was defined by X-ray diffraction (XRD), the elemental composition of rock was determined by X-ray photoelectron spectroscopy (XPS) and scanning electron microscopy energy dispersive spectroscopy (SEM-EDS), and the organic content of rock samples was estimated by thermogravimetric analysis (TGA). The water was analyzed for its anions and cations, total dissolved solids (TDS), conductivity, pH, total organic carbon (TOC), and average particle sizes of colloids. The stability of the colloids was characterized by zeta-potential. We show that Barnett rock is high in illite content, and the greatest calcite concentration is determined for Eagle Ford. The sulfate content of water correlates with the atomic percent of the sulfur and oxygen elements determined through XPS analyses. The magnesium content of water correlates mainly with the illite amount in the rock, and calcium concentration associates with the calcite and gypsum content of the rock samples. The greatest dissolution rate belongs to the minerals that yield sulfate in the water; then, gypsum and calcite that yield calcium cation in the water come second; and the lowest dissolution rates are obtained from the magnesium-containing minerals (mainly, dolomite). TDS of the water samples shows that Green River has the least tendency to interact with water, and Barnett has the greatest tendency. Zeta-potential values indicate that particles in the water that interacted with Eagle Ford have the highest tendency for precipitation. The results of this study are used to make suggestions on the engineering of hydraulic-fracturing fluids (HFFs) in the context of water/rock interactions by considering the type and the concentration of ions along with colloidal stability determined through zeta-potential measurements.

Characterization of Elastic Anisotropy in Eagle Ford Shale: Impact of Heterogeneity and Measurement Scale

SummaryHeterogeneity and anisotropy were characterized in some Eagle Ford shale samples at various scales by use of scanning-electron-microscopy (SEM) imaging, computed-tomography (CT) scanning, and compressional-velocity scanning. Triaxial testing on 1-in.-diameter and 3-in.-diameter core samples and well-log analysis were used to calculate elastic properties by using vertical transverse isotropic modeling. Correlations between the stiffness coefficients and the correlations between static and dynamic properties from laboratory tests were applied to well-log analysis to improve the calculation of minimum horizontal stress. This paper provides the elastic properties of the Eagle Ford shale at various measurement scales. The paper also elaborates the role of heterogeneity in laboratory testing of shale reservoirs.

Characterization and Measurement of Multiscale Gas Transport in Shale-Core Samples

Summary This work introduces an experimental technique to probe simultaneously flow and diffusion of gas through shale. A core-scale pressure-pulse-decay experiment is used to study the upstream- and downstream-pressure responses of Eagle Ford and Haynesville shale samples. With the aid of numerical models, the pressure histories obtained from the experiments are matched and gas and rock properties are obtained. The experiments are conducted at varying pore pressure and net effective stress to understand the sensitivity of the rock porosity and permeability as well as the gas diffusivity. A dual-porosity model is constructed to examine gas transport through a system of micropores and microcracks. In this sense, the role of the two different-sized pore systems is deconvolved. In some cases, the micropore system carries roughly one-third of the gas flow. The porosity, permeability, and diffusivity obtained assign physical properties to the macroscales and microscales simultaneously. Results bridge the gap between these scales and improve our understanding of how to assign transport physics to the correct pore scale.

Permeability measurements in mudrocks using gas-expansion methods on plug and crushed-rock samples

Permeability is an important parameter relative to the production of hydrocarbons in shale oil/gas plays; however, the measurement of permeability in these nano-to microdarcy rocks remains a challenge. Results from different methods or from different laboratories are not consistent, and reasons are not fully understood. In the present study, permeability is measured for both plug and crushed-rock samples with different plug diameter or crushed-sample particle size to systematically investigate the permeability measurement to better understand and apply the measured results. A modified gas-expansion (MGE) method, which can measure permeability for plug samples under confining pressures, was established and applied to several Eagle Ford and Barnett Shale (mudrock) samples. Permeability results from this method are in fair agreement with those from the pulse-decay method. The traditional Gas Research Institute (GRI) method was applied to crushed-rock Eagle Ford Shale samples. The results were comparable to reported permeability for an Eagle Ford Shale sample. Particle or plug size has significant influence on permeability measurement. In general, permeability increases with increasing particle or plug size. For crushed sample with GRI method, the reason of increasing permeability is related to the limitation of the GRI technique and the data analysis method. Estimate of the permeability based on Kozeny–Carman Equation was conducted, and the results were used to evaluate the GRI permeability measurement. Particle size of 2–4 mm (5–10 meshes) is considered as an appropriate size for GRI permeability measurement. For plug sample, larger permeability with larger plug diameter is most likely caused by the artificial fractures. Higher confining pressure can reduce the influence of the fractures, but cannot fully remove it. A range of permeability, defined by the GRI permeability with 2–4 mm particles as the lower boundary and permeability of 1-in plug under high confining pressure (>5000 psi) as the upper boundary, can be a more reliable measures to represent the shale matrix permeability. The range of the permeability also highlights the uncertainty in matrix permeability measurement for shale.

Langmuir slip-Langmuir sorption permeability model of shale

Darcy law has been widely used in high permeability formations; however, it fails to realistically describe different flow processes other than the viscous flow. Several permeability models have been developed to describe gas flow in shale nanopores due to various processes, and relevant processes other than viscous flow include Knudsen diffusion, slip flow and desorption. To include these processes, all the current models need some empirical coefficients which are not easily available for shale formations. We propose a permeability model that – (1) does away with the shortcomings of Maxwell slip condition, (2) uses readily available Langmuir sorption data to determine slip coefficient for gas flow, and (3) includes the higher-order slip effects on gas flow. This model also includes the effect of pore enlargement due to pressure-depletion sorption. Our model, represented by a single analytical equation depends only on pore size, pressure, and Langmuir sorption isotherm data of shale sample. We validated our model using a set of in-house detailed experimental data on Eagle Ford shale samples and also using data from the literature on shale gas permeability versus pore pressure measurements for helium and methane. We also used our model to calculate gas production from a well-reservoir system and compared the results with previously developed models. Our model also predicts the onset and the contribution of sorption to gas production from a shale well.