Complementary neutron scattering, mercury intrusion and SEM imaging approaches to micro- and nano-pore structure characterization of tight rocks: A case study of the Bakken shale (original) (raw)
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Proceedings of the 2nd Unconventional Resources Technology Conference, 2014
Porosity and pore size distribution are crucial parameters which are required to calculate reservoir volume as well as to evaluate producibility. In mudrocks, these measurements are challenging due to the presence of fine grains, small pores, high clay content, swelling clay minerals, pores hosted in organic content, and possibly, mixed wettability. We used samples from the Monterey, Haynesville, Niobrara and Eastern European Silurian Formations. We measured porosity and pore/throat size distribution (PSD) of the samples using the subcritical nitrogen gas adsorption (N2) analysis at 77.3 K, the mercury intrusion (MI), and the low-field (2 MHz) nuclear magnetic resonance (NMR). Porosity was also measured with the water immersion (WI) and the helium porosimetry (GRI) techniques. The effect of texture and rock matrix components on porosity and pore-size distribution have been studied considering clay content and type, and total organic carbon (TOC).
2015
Various techniques have been developed over the years for characterizing pore structure beyond a simple visual description. These tests provide qualitative data for both reservoir evaluations in the short run and reservoir simulation in the long run. In this study, mercury porosimetry (MP), low field (2MHz) nuclear magnetic resonance (NMR) relaxometry, centrifuge drainage tests and flow tests were run on 11 plugs of a mix of sandstones, limestones, dolomites and chalk. Initially, a representative elemental volume (REV) which uses pore size distribution (PSD) data and porosity to simulate the pore network is discussed. The model is later used to predict permeability and predictions were compared with gas flow measurements. NMR and centrifuge data are coupled to derive capillary pressure curves and the results are compared with MP derived capillary curves. The results indicate that there is significant difference between the two capillary curves based on the degree of heterogeneity of...
Pore Characterization of Reservoir Rocks by Integrating Scal and Petrography
Pores of reservoir rock control its petrophysical and flow properties and are of importance for hydrocarbon exploration and development. We present an integrated study on pore characterization on several typical reservoir rocks, namely glauconitic sandstone, shaly sandstone, salt-cemented sandstone and chalk using SCAL data from lab nuclear magnetic resonance (NMR), high pressure mercury injection (MICP) and by SEM and thin section. NMR T2 relaxation distributions reveal patterns similar to porethroat size distributions obtained from the (MICP) tests carried out on the same samples. Chalk samples show narrow uni-modal pores, while the glauconitic sandstones and some shaly sandstones with pore filling kaolinite show bi-modal pore size distribution. Thin section and SEM observations show that intra-granular and inter-granular pores of glauconite, kaolinite etc. correspond to micro-pores seen in NMR T2 relaxation and MICP data. The abundance of clay indicated by petrography correlates to the amplitudes of the micropore peaks of NMR T2 relaxation and pore throat size distributions in sandstone samples. Uniform intergranular pores result from fine-grained broken coccolith grains explain the narrow mono-modal T2 relaxation and pore throat distributions in chalk. The apparent T2 relaxivities for glauconite and calcite are derived.
Effects of maturation on multiscale (nanometer to millimeter) porosity in the Eagle Ford Shale
Interpretation, 2015
Porosity and permeability are key variables that link the thermal-hydrologic, geomechanical, and geochemical behavior in rock systems and are thus important input parameters for transport models. Neutron scattering studies indicate that the scales of pore sizes in rocks extend over many orders of magnitude from nanometer-sized pores with huge amounts of total surface area to large open fracture systems (multiscale porosity). However, despite considerable efforts combining conventional petrophysics, neutron scattering, and electron microscopy, the quantitative nature of this porosity in tight gas shales, especially at smaller scales and over larger rock volumes, remains largely unknown. Nor is it well understood how pore networks are affected by regional variation in rock composition and properties, thermal changes across the oil window (maturity), and, most critically, hydraulic fracturing. To improve this understanding, we have used a combination of small-and ultrasmall-angle neutron scattering (U)SANS with scanning electron microscope (SEM)/backscattered electron imaging to analyze the pore structure of clay-and carbonate-rich samples of the Eagle Ford Shale. This formation is hydrocarbon rich, straddles the oil window, and is one of the most actively drilled oil and gas targets in the United States. Several important trends in the Eagle Ford rock pore structure have been identified using our approach. The (U)SANS results reflected the connected (effective) and unconnected porosity, as well as the volume occupied by organic material. The latter could be separated using total organic carbon data and, at all maturities, constituted a significant fraction of the apparent porosity. At lower maturities, the pore structure was strongly anisotropic. However, this decreased with increasing maturity, eventually disappearing entirely for carbonate-rich samples. In clay-and carbonate-rich samples, a significant reduction in total porosity occurred at (U)SANS scales, much of it during initial increases in maturity. This apparently contradicted SEM observations that showed increases in intraorganic porosity with increasing maturity. Organic-rich shales are, however, a very complex material from the point of view of scattering studies, and a more detailed analysis is needed to better understand these observations.
Pores in Marcellus Shale: A Neutron Scattering and FIB-SEM Study
Energy & Fuels, 2015
The production of natural gas has become increasingly important in the United States because of the development of hydraulic fracturing techniques, which significantly increase the permeability and fracture network of black shales. The pore structure of shale is a controlling factor for hydrocarbon storage and gas migration. In this work, we investigated the porosity of the Union Springs (Shamokin) Member of the Marcellus Formation from a core drilled in Centre County, PA, USA, using ultrasmall-angle neutron scattering (USANS), small-angle neutron scattering (SANS), focused ion beam scanning electron microscopy (FIB-SEM), and nitrogen gas adsorption. The scattering of neutrons by Marcellus shale depends on the sample orientation: for thin sections cut in the plane of bedding, the scattering pattern is isotropic, while for thin sections cut perpendicular to the bedding, the scattering pattern is anisotropic. The FIB-SEM observations allow attribution of the anisotropic scattering patterns to elongated pores predominantly associated with clay. The apparent porosities calculated from scattering data from the bedding plane sections are lower than those calculated from sections cut perpendicular to the bedding. A preliminary method for estimating the total porosity from the measurements made on the two orientations is presented. This method is in good agreement with nitrogen adsorption for both porosity and specific surface area measurements. Neutron scattering combined with FIB-SEM reveals that the dominant nanosized pores in organic-poor, clay-rich shale samples are water-accessible sheetlike pores within clay aggregates. In contrast, bubblelike organophilic pores in kerogen dominate organic-rich samples. Developing a better understanding of the distribution of the water-accessible pores will promote more accurate models of water− mineral interactions during hydrofracturing.
A comparative study of porosity measurement in mudrocks
SEG Technical Program Expanded Abstracts 2014, 2014
Porosity and pore size distribution are crucial parameters required to calculate reservoir volume and to evaluate its producibility. In mudrocks, however, these measurements are challenging due to the presence of fine grains, small pores, high clay content, swelling clay minerals, pores hosted in organic content, and, possibly, mixed wettability. We present porosity and pore/throat size distribution (PSD) measurements on samples from Monterey, Haynesville, Niobrara and Eastern European Silurian formations estimated from subcritical nitrogen gas adsorption (N2) analysis at 77.3 K, mercury intrusion (MI), and low-field (2 MHz) nuclear magnetic resonance (NMR). Porosity was also measured with water immersion (WI) and helium porosimetry (GRI). Clay content, type and total organic carbon (TOC) are also measured to study the effect of texture and rock matrix components on porosity and poresize distribution. Our data show that clay content, thermal maturity and pore size range are the main factors that need to be considered while choosing the appropriate method for porosity and pore size distribution measurements. GRI method is not recommended for high TOC samples. MI porosity highly underestimates the clay related porosity. N2 measures both TOC and clay porosity as long as the pores are smaller than 200 nm. Reliability of porosity data depends on the accessibility of the pores by the displacement fluid, which can be confirmed by PSD measurements. At the same time reliability of PSD can be confirmed by comparing porosity values to see if the method measures the total porosity or not. Our results are useful to better understand the inconsistencies in porosity measurements from different techniques. As a result a reliable porosity value can be estimated for velocity-porosity transforms and rock physics modeling applications.
Pore characterization of shales: A review of small angle scattering technique
Journal of Natural Gas Science and Engineering, 2020
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Marine and Petroleum Geology, 2018
To examine the effects of burial diagenesis on heirarchical pore structures in sandstone and compare those with the effects of overgrowth formation, we obtained samples of St. Peter Sandstone from drill cores recovered from the Illinois and Michigan Basins. The multiscale pore structure of rocks in sedimentary reservoirs and the mineralogy associated with those pores are critical factors for estimating reservoir properties, including fluid mass in place, permeability, and capillary pressures, as well as geochemical interactions between the rock and the fluid. The combination of small-and ultra-small-angle neutron scattering with backscattered electron imaging, provided a means by which pore structures were quantified at scales ranging from approximately 1 nm to 1 cm-seven orders of magnitude. Larger scale (> 10 μm) porosity showed the expected logarithmic decrease in porosity with depth, although there was significant variation in each sample group. However, small-and ultrasmall-angle neutron scattering data showed that the proportion of small-scale porosity increased with depth. Porosity distributions were not continuous, but consisted of a series of log normal-like distributions at several distinct scales within these rocks. Fractal dimensions at larger scales decreased (surfaces smoothed) with increasing depth, and those at smaller scales increased (surfaces roughened) and pores become more isolated (higher lacunarity). Data suggest that changes in pore-size distributions are controlled by both physical (compaction) and chemical effects (precipitation, cementation, dissolution).
The distribution of nanometer-size pores in ten selected Eagle Ford Group, Haynesville, Marcellus, and Barnett shale samples was similar when comparing relative numerical abun-dances of maximum pore diameters but not when comparing relative abundances of pore areas (pore sizes). Differences also existed between units in the association of pores with or-ganic material. Pores were measured on argon-ion-milled (AIM) samples and examined with a field emission environmental scanning electron microscope (SEM). One Haynesville sample was also evaluated using a focused ion beam (FIB) SEM to compare to the AIM results. With the AIM samples, pore types were subdivided into three categories—organic pores, mixed matrix/organic pores, and matrix pores—based on the amount and type of material (organic or inorganic) surrounding the pores. Organic pores are pores generally associated with kero-gen macerals, whereas mixed matrix/organic pores are pores that are probably associated with bitumen or py...
Submicron-Pore Characterization of Shale Gas Plays
2011
Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40−50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet). 2 SPE 144050 Key to successful characterization of fluid flow behavior in shale gas plays is an understanding of the petrophysics of shale rocks and their submicron pore structures. A few studies have attempted to construct submicron pore structures. Liviu et al. (2007) conducted an intensive study of submicron pore imaging using SEM-FIB for chalk rocks. Sondergeld et al. (2010) used the same method to characterize the submicron structures of a few shale gas plays. However, no attempt has yet been made to systematically characterize the petrophysical properties of shale gas plays with any means other than submicron pore imaging. This work used high pressure mercury porosimetry analysis, or MICP (up to 60,000 psi) to determine pore throat distribution and pore volume. It used a dual-beam system (SEM/FIB) to reconstruct three-dimensional structural pore models of shale gas samples. Energy-dispersive spectroscopy (EDS) confirmed the existence of organic matter (kerogen) and defined the elemental composition of the examined shale gas samples. A modest clay mineralogy study was conducted by using X-ray diffractometer. Contact angle measurements evaluated surface wetting properties. Mercury Porosimetry (MICP) Mercury (Hg) is a toxic material that has been used in rock laboratories as an indirect measure of rock capillarity and porosimetry. These experiments are considered destructive, expensive, and time consuming. Nevertheless, mercury porosimetry has been widely accepted as a mean to characterize porous solids with respect to their pore volume (porosity) and pore size distribution over a wide range of pore sizes. Mercury is nonwetting phase and it can only access interconnected pores. The volume of mercury that can enter pore spaces is limited by the maximum pressure attained during analysis. MICP has produced representative and reproducible results for conventional reservoir rocks. However, for shale gas rocks, the scenario is almost impossible to reproduce due to the shale tightness. Only two of 12 attempts have been successful, although high injection pressures up to 60,000 psi were applied. This pressure level is still greater by a factor of 5 than that determined by curve of water drainage displaced by air.