Download or read book THE ROLE OF PORE STRUCTURE IN PERMEABILITY EVOLUTION OBSERVED IN LABORATORY STUDIES OF MARCELLUS AND WOLFCAMP SHALE written by Brandon Schwartz and published by . This book was released on 2018 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: We explored the role of pore geometry and stiffness on the distribution of strain around pores for Marcellus and Wolfcamp shales. Relationships exist to model permeability evolution as well as bulk stiffness evolutionhere we find a relationship relating these two variables to each other. Whereas bulk stiffness is determined by bulk mineralogy and initial pore structure, evolving bulk stiffness is determined by the evolution of the pore structure alone. Permeability evolution is also determined by the evolution of the pore structure. We cast the permeability evolution in terms of evolving material properties including the Poisson ratio, the crack density parameter, and the bulk modulusall of which can be measured via acoustic waves. The end result is a method to measure permeability evolution via acoustic waves alone.We modeled the effects of fracture spacing, aspect ratio, and pore stiffness on the permeability evolution of an ellipsoid crack under uniaxial stress and varying pore pressure. We found that rocks undergoing identical compressional strain and pore pressure can undergo significantly different magnitudes of fracture closure or dilation based on these three variables. This is especially important is gas shales, where nano-porosity is challenging to characterize and heterogeneity between basins has led to disparate permeability responses in the field and in the laboratory. We found that the aspect ratio is the most sensitive parameter influencing pore compressibility. The fracture spacing becomes important when external stress is applied, but it has no significant effect when pore pressure is varied is the absence of external stress. To capture effects of mineral distribution around pores, we simulated mismatches between a pores skeletal stiffness and the surrounding matrix and determined that for a given strain soft pores relative to the bulk material experience greater permeability evolution than pores that are stiff relative to the surrounding matrix. While soft pores experience greater closure than stiff pores for a given applied stress, they also experience a greater amount of dilation when pore pressure increases. This highlights that while some shale basins such as the Marcellus can experience large permeability drops relative to other basins given the same production conditions, pressure maintenance may be the most important tool to preserve permeability. We compare the permeability response of Marcellus shale to Wolfcamp shale under changing strain to explore differences in pore structure between them. This work highlights that while magnitude of strain for a given stress is determined predominantly through a shales mineral composition, the response of transport properties to a given strain are dependent on fracture spacing, fracture geometry, and mineral distribution around pores. We dynamically stress samples of Marcellus and Wolfcamp shales and observed levels of compaction, creep, and permeability evolution. We characterize the differences between the two shales using bulk mineralogy, SEM imaging with elemental analysis, and the cubic law for permeability evolution. We find that the Marcellus shale is comprised predominantly of clays that leads to more deformation when stressed than the Wolfcamp shale which is composed predominantly of quartz and calcite. The level of creep and compaction are directly related to the amount of clay in each shale sample. Modifications to the cubic law for fluid flow reveal that Marcellus shale has a lower fracture density than the Wolfcamp shale, that the pore geometry more closely resembles slit-like pores, and that the mineral distribution around the pore space is soft compared to the Wolfcamp shale. These differences cause the Marcellus shale to experience much greater permeability reduction under the same compressive strain than the Wolfcamp. The result of our study is a unique strain-driven model to capture permeability evolution in shale due to differences in pore structure.We show that nitrogen flooding can double matrix permeability of gas shales. In laboratory experiments, nitrogen gas increased permeability in the bedding-parallel and bedding-perpendicular directions by 206% and 234%, respectively. Experiments are performed at constant stress, pore pressure, and temperature. We build a model to show that the permeability enhancement is controlled by the sorptive strain, pore geometry, and the spacing-to-aperture ratio. This work addresses how an organic-poor shale can experience large permeability changes driven by sorption induced strains. We plot methane and helium permeability curves as a function of pore pressure to isolate the portion of permeability evolution controlled by sorption. We independently build strain curves to solve for the sorptive strain and find good agreement between these two methods. This work demonstrates that matrix permeability in gas shales can be doubled, which suggests that ultimate recovery can be improved as well.We explore relationships among bulk modulus, crack density, and permeability through repetitive loading of Marcellus shale. Cumulative cyclic stressing (22-26 MPa with confinement of 24 MPa) is applied at a frequency of 0.05 Hz over 100,000 cycles. Changes in acoustic velocities are used to follow changes in dynamic bulk modulus, Poisson ratio, and crack density and to correlate these with bedding-parallel measurements of methane permeability. The shale is represented as an orthotropic elastic medium containing a dominant, noninteracting fracture set separated by thin laminae. An effective continuum model links permeability evolution to the evolution of the bulk modulus and crack density. Bulk modulus is linearly related to crack density by a scaling parameter representing rock fabric and fracture geometry. The Poisson ratio and bulk modulus of the intact, uncracked shale are deduced from our data. We propose a method for tracking permeability evolution of finely laminated shale using acoustic waves.

Download or read book Laboratory Studies of Permeability Evolution written by Benjamin James Madara and published by . This book was released on 2018 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Fault and fracture permeability-stability relationships continually evolve over the seismic cycle. Both static and dynamic changes in mechanical stresses can affect the fluid pressures and vice versa. These changes can be potentially beneficial to energy production, as dynamic stressing has been observed to enhance reservoir permeability in natural and manufactured systems. However, both dynamic and static changes in stress have also been shown to destabilize faults, triggering earthquakes. It is clear a fundamental understanding of controlling mechanisms is necessary for safely enhancing reservoir productivity and understanding seismic hazard assessment. In this dissertation, I strive to illuminate the underlying mechanisms that govern permeability evolution, including transient changes in permeability associated with dynamic stressing and fault shear. While the relationships between fault slip, dynamic stressing, and permeability have been studied separately, little data are available on their combined effects. In each chapter, I present results from suites of carefully controlled laboratory experiments to investigate the effect of mode II fault failure and shear on permeability and poromechanical properties.In Chapter 1, I investigate the effects of dynamic stressing on highly porous reservoir rock, Berea sandstone, at various stages of shear displacement. I demonstrate that porous rock is sensitive to dynamic stressing only via fluid pulsing and that both reservoir permeability and sensitivity to dynamic stressing declines with shear. Chapter 2 extends this work into low porosity, low permeability reservoir rock, Westerly granite and Green River shale. Here I show that frequency of imposed fluid oscillations has the greatest control over permeability enhancement. Finally, chapter 3 focuses on friction and permeability responses across multiple reservoir rock types throughout the seismic cycle, simulated via Slide-Hold-Slide and velocity step testing. Here, I use in situ fractured samples alongside traditional, saw cut samples to highlight the effect of fracture roughness on the fluid response across varying rock mineralogy.This dissertation provides insight to the controlling mechanisms and data that can be used to predict reservoir behavior, including the feasibility of shear failure and dynamic stressing as reservoir permeability management techniques. I demonstrate that permeability-stability relationships evolve as a result of dynamic stressing and are dependent upon properties of the reservoir: porosity, fracture roughness, and stiffness as well as the properties of imposed dynamic stressing: frequency and amplitude. The evidence provided shows differing results from exercising the same mechanism when applied to different types of reservoir rock.

Download or read book Core scale Heterogeneity and Dual permeability Pore Structure in the Barnett Shale written by Michael Brett Cronin and published by . This book was released on 2014 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: I present a stratigraphically layered dual-permeability model composed of thin, alternating, high (̃9.2 x 10−20 m2) and low (̃3.0 x 10−22 m2) permeability layers to explain pressure dissipation observed during pulse-decay permeability testing on an intact Barnett Shale core. I combine both layer parallel and layer perpendicular measurements to estimate layer permeability and layer porosity. Micro-computed x-ray tomography and scanning electron microscopy confirm the presence of alternating cm-scale layers of silty-claystone and organic-rich claystone. I interpret that the silty-claystone has a permeability of 9.2 x 10−20 m2 (92 NanoDarcies) and a porosity of 1.4% and that the organic-rich claystone has a permeability of 3.0 x 10−22 m2 (0.3 NanoDarcies) and a porosity of 14%. A layered architecture explains the horizontal (k [subscript H] = 107 x 10−21 m2) to vertical (k [subscript V] = 2.3 x 10−21 m2) permeability anisotropy ratio observed in the Barnett Shale. These core-scale results suggest that spacing between high-permeability carrier beds can influence resource recovery in shales at the reservoir-scale. I also illustrate the characteristic pulse-decay behavior of core samples with multiple mutually-orthogonal fracture planes, ranging from a single planar fracture to the Warren and Root (1963) "sugar cube" model with three mutually-orthogonal fracture sets. By relating sub core-scale matrix heterogeneity to core-scale gas transport, this work is a step towards upscaling experimental permeability results to describe in-situ gas flow through matrix at the reservoir scale.

Download or read book Characterization of Petrophysical Properties of Organic rich Shales by Experiments Lab Measurements and Machine Learning Analysis written by Han Jiang (Ph. D.) and published by . This book was released on 2018 with total page 354 pages. Available in PDF, EPUB and Kindle. Book excerpt: The increasing significance of shale plays leads to the need for deeper understanding of shale behavior. Laboratory characterization of petrophysical properties is an important part of shale resource evaluation. The characterization, however, remains challenging due to the complicated nature of shale. This work aims at better characterization of shale using experiments, lab measurements, and machine leaning analysis. During hydraulic fracturing, besides tensile failure, the adjacent shale matrix is subjected to massive shear deformation. The interaction of shale pore system and shear deformation, and impacts on production remains unknown. This work investigates the response of shale nanoscale pore system to shear deformation using gas sorption and scanning electron microscope (SEM) imaging. Shale samples are deformed by confined compressive strength tests. After failure, fractures in nanoscale are observed to follow coarser grain boundaries and laminae of OM and matrix materials. Most samples display increases in pore structural parameters. Results suggest that the hydrocarbon mobility may be enhanced by the interaction of the OM laminae and the shear fracturing. Past studied show that the evolution of pore structure of shale is associated with thermal maturation. However, the evolution of shale transport propreties related to thermal maturation is unclear due to the difficulty of conducting permeability measurement for shale.This work studies evolution of permeability and pore structure measurements using heat treatment. Samples are heated from 110°C to 650°C. Gas sorption and GRI (Gas Research Institute) permeability measurements are performed. Results show that those petrophysical parameters, especially permeability, are sensitive to drying temperature. Multiscale pore network features of shale are also revealed in this study. Characterizing fluids in shale using nuclear magnetic resonance (NMR) T1-T2 maps is often done manually, which is difficult and subjected to human decisions. This work proposes a new approach based on Gaussian mixture model (GMM) clustering analysis. Six clustering algorithms are performed on T11-T2 maps. To select the optimal cluster number and best algorithm, two cluster validity indices are proposed. Results validate the two indices, and GMM is found to be the best algorithm. A general fluid partition pattern is obtained by GMM, which is less sensitive to rock lithology. In addition, the clustering performance can be enhanced by drying the sample

Download or read book Influence of Nanopores on the Transport of Gas and Gas condensate in Unconventional Resources written by Maytham I. Al Ismail and published by . This book was released on 2016 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Shale gas and liquid-rich shales have become important energy sources in the US and other parts of the world. Unlike conventional oil and gas reservoirs, unconventional shale resources contain a very heterogeneous pore system. The pore size varies between micro-, meso- and macroscales (2 nm, 2-50 nm and 50 nm). The mineral composition of shale rocks varies widely as well from clay-rich to calcite-rich. The nanoscale nature of the pores, coupled with rock mineral heterogeneity, makes the "conventional'' understanding of fluid transport in conventional reservoirs no longer suitable to explain and predict accurately the flow behavior in unconventional resources. The research work aimed to bridge the gap in the understanding of the fluid flow behavior of unconventional resources by applying various experimental and molecular simulation tools. Specifically, this research work studied how the rock (i.e. permeability), the fluid (i.e. composition and phase behavior) and the fluid-rock interactions (i.e. adsorption) all behaved with depletion in nanoporous rock formations. Several laboratory experiments and molecular simulation techniques were applied in this research work. Laboratory experiments included a gas-condensate core-flooding experiment, permeability measurements and adsorption measurements. In the core-flooding experiment, a real gas-condensate mixture obtained from the Marcellus shale play was injected into a Marcellus shale core at in-situ conditions and the composition of gas samples collected along the core was monitored during flow. To investigate the effect of rock mineralogy and pore structure on the transport mechanisms in nanoporous shale reservoirs, the permeability of Utica, Permian and Eagle Ford shale samples were measured using argon as a nonadsorbing gas and CO2 as an adsorbing gas. In addition, CO2 adsorption experiments were conducted on different shale samples in order to investigate the role of shale mineral constituents in adsorption. Moreover, molecular simulation techniques were applied to model the selective adsorption of binary hydrocarbon mixtures in carbon-based slit-pores and to estimate the shift in the critical properties of hydrocarbons due to confinement in nanometer-size pores. The molecular simulation techniques included the grand canonical Monte Carlo (GCMC) and the Gibbs ensemble Monte Carlo (GEMC). This research work revealed that clay content in shale reservoirs played a significant role in the stress-dependent permeability. For clay-rich samples, higher pore throat compressibility was observed which in turn led to higher permeability reduction with increasing effective stress compared to calcite-rich samples. Numerical simulation results showed that failing to account for stress-dependent permeability in clay-rich shale reservoirs may lead to overestimating the cumulative gas recovery by a factor of two after ten years of production. Permeability measurements with CO2 indicated that CO2 permeability decreased in comparison with the nonadsorbing gases by as high as an order of magnitude due to a combination of CO2 adsorption, sorption-induced swelling and molecular sieving effects. CO2 adsorption measurements indicated that adsorption was controlled mainly by the clay content. Clay-rich shale samples showed higher adsorption capacity compared to clay-poor shale samples. The predominant clay mineral in those shale samples was illite. The platy shape of illite provided the surface area for enhanced adsorption capacity. This study concluded that in gas-condensate systems of liquid-rich shales, the produced gas becomes leaner during production and significant volumes of condensates, which contain predominantly heavy components, are left behind in the reservoir. The gas-condensate core-flooding experiment showed that composition of the flowing mixture below the dew-point pressure contained less heavy components along the direction of flow. Molecular simulations revealed that the change in gas composition was not only due to condensate dropout and relative permeability effects, but also due to the preferential adsorption of heavy hydrocarbons over methane. This means that initial production from shale reservoirs contain both methane and other heavy components from the free phase. However, as reservoir pressure decreases, methane from the adsorbed phase starts to desorb preferentially and the adsorption sites where methane molecules used to reside start to accept heavier components. In addition, molecular simulations conducted at subcritical conditions to estimate the vapor and liquid densities of pure hydrocarbons inside 5 and 10-nm pores revealed that rock-fluid interactions in the form of adsorption caused the critical pressure and temperature of the confined molecules to decrease. This was observed clearly for methane and ethane. The decrease in the critical properties was affected by the size of the pores. For example, the estimated critical pressure and temperature of methane in 5-nm pore were lower than the critical pressure and temperature in 10-nm pore.

Download or read book Pore Structure and Permeability of Cementitious Materials written by L. R. Roberts and published by . This book was released on 1989 with total page 498 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Microscale Pore fracture System Characterization of Shales by Digital Images Gas Sorption and Machine Learning written by Xiao Tian (Ph. D.) and published by . This book was released on 2019 with total page 191 pages. Available in PDF, EPUB and Kindle. Book excerpt: The challenges in sustainable and efficient development of organic shales demand a better understanding of the micro-scale pore structure of organic shales. However, the characterization of shale pore structure is challenging because the pores can be very small in size (less than several nanometers). Besides, the pore network in shales can be very different from that of conventional reservoirs. A unique feature of the pore system in organic shales is that the formation of the pore network usually depends heavily on the maturation of organic matter. In this dissertation, the properties of the pore network in the shale matrix are investigated using pore-scale network modeling constrained by low pressure nitrogen sorption isotherms. In addition to the larger, induced fracture network generated during hydraulic fracturing, the flow pathways formed by microfractures and nanopores are important for economic hydrocarbon production formations. However, due to the difficulty in detecting and characterizing microfractures and the complexity of hydrocarbon transport in shales, the role of microfractures in hydrocarbon flow during production is still poorly understood. In this dissertation, the most up-to-date machine learning and deep learning tools are utilized to characterize microfractures propagation in organic rich shales. The microfracture lengths and fracture-mineral preferential association are studied. Later a microfracture is embedded in pore-scale network models to understand the role of microfracture in permeability enhancement of shale matrix. Shale samples from three different shale formations are studied in this dissertation. These formations are Barnett shale, Eagle Ford shale (Karnes County, TX), and a siliceous shale in the northern Rocky Mountains, USA (the specific location has been withheld at the donor’s request). By analyzing the nitrogen sorption isotherms for isolated organic matter clusters and the bulk shale samples, the pore size information in the organic matter and inorganic matter is explored for the Barnett shale samples. The network connectivity and pore spatial arrangement in the shale matrix is determined by comparing the modeled nitrogen sorption isotherms with laboratory experiment results. Later, the pore network model is used to predict the permeability of the shale matrix. Both Darcy permeability and apparent permeability (including Darcy flow and gas slip effect) are computed using the network model. The apparent permeability is much larger than the Darcy permeability from laboratory measurements and pore network modeling. Pore network models are constructed for four samples: two sample from Barnett shale, one from Eagle Ford and one from the siliceous samples. The pore network properties are characterized using nitrogen sorption isotherms. I concluded that on average, each pore is connected with two neighboring pores in shale matrix. The pore spatial arrangement is not totally random in the network. By analyzing the microfracture propagation in high resolution scanning electron microscopy (SEM) images for the Eagle Ford samples and siliceous samples, the fracture lengths and density in intact and deformed (in confined compressive strength testing) shale samples are explored. The preferential fracture-mineral association is scrutinized by analyzing the composed back-scatter electron (BSE) images and the energy dispersive x-ray spectroscopy (EDS) images for the Eagle Ford and Siliceous samples. The fractures and minerals are easily detectable after combining BSE and EDS images. The conclusion is that, the generation and closure of microfracture is closely related to total organic carbon (TOC), OM maturation, and minerology. A higher TOC indicate that more microfractures are generated during organic matter maturation. Clay dehydration is another reason for microfracture generation. However, the microfractures generated due to clay dehydration or organic matter maturation are also more sensitive the pressure dependent effect. Microfractures also develop at the grain boundaries of more brittle minerals such as quartz, calcite, and feldspar. The permeability of the pore network model containing one microfracture is computed for the Eagle Ford sample and the siliceous sample. The results suggest that the permeability of shale matrix increases greatly after one microfracture is added to the matrix. The relationship between permeability and fracture height-aperture ratio follows a logarithmic function for both samples. The relationship between permeability and lengths follows an exponential function for both samples. Fracture lengths have more impact on fracture permeability compared to height-aperture ratio

Download or read book Unconventional Reservoir Geomechanics written by Mark D. Zoback and published by Cambridge University Press. This book was released on 2019-05-16 with total page 495 pages. Available in PDF, EPUB and Kindle. Book excerpt: A comprehensive overview of the key geologic, geomechanical and engineering principles that govern the development of unconventional oil and gas reservoirs. Covering hydrocarbon-bearing formations, horizontal drilling, reservoir seismology and environmental impacts, this is an invaluable resource for geologists, geophysicists and reservoir engineers.

Download or read book Pore Pressure written by P. E. Gretener and published by . This book was released on 1978 with total page 102 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Laboratory Investigation of Multiphase Permeability Evolution Due to Fracturing Fluid Filtrate in Tight Gas Sandstones written by Kelvin Abaa and published by . This book was released on 2016 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Injection of large volumes of fluids during fracture treatment may result in leak-off, capillary imbibition and trapping of the fracturing fluid filtrate in the pores of the reservoir. The trapped fluid affects the mobility of hydrocarbons during clean-up and production. Additionally, the fracturing fluid filtrate near wellbore and fracture region is one of variable composition and can induce alterations in rock-fluid and fluid-fluid interactions. The concomitant changes in multiphase permeability during fluid invasion and clean-up is one that is not fully understood. The aim of this study is to investigate the role fracturing fluid filtrate composition has on the evolution of multiphase permeability during imbibition and drainage of the aqueous phase. In this work, multiphase flow of fracturing fluid filtrate in low permeability sandstones was investigated by means of laboratory experiments for three commonly employed fracturing fluids. The multiphase flow experiments were conducted using brine, helium and filtrate from various fracturing fluids in sandstones cores of different permeabilities. The alteration of rock-fluid properties and changes in interfacial tension in the presence of gas was determined by evaluation of the obtained relative permeability curves to both gas and liquid/filtrate phase. Experimental results indicate that there was a reduction in end-point and liquid phase relative permeability following imbibition of slickwater into the core sample. The liquid phase relative permeability decreases with increasing concentration of friction reducer (Polyacrylamide solution) present in the fluid system. Adsorption flow experiments with slickwater confirm the adsorption of polyacrylamide molecules to the pore walls of the rock sample and results in increased wettability of the rock sample. This process was found to increase liquid trapping potential of the rock surface. For linear and crosslinked gels, filtrate composition does not have a significant effect on liquid relative permeability during fluid invasion due to limited polymer invasion into the core. This study also investigated the effect of alcohol and surfactant used as remediation additives on multiphase permeability evolution with different fracturing fluid systems. Multiphase permeability flow tests were conducted to determine, understand and quantify the mechanisms that govern multiphase permeability evolution using alcohols and surfactants to remediate aqueous phase trapping. Methanol and two surfactant chemicals, Novec FC-4430 and Triton X-100 were used as remediation additives in this study. Results from multiphase permeability flow tests conducted with methanol indicated that the volume of liquid removed by displacement increases with methanol concentrations for all fracturing fluids. This is attributed to increased liquid mobility from addition of methanol during the displacement process. Interfacial tension does not contribute to multiphase permeability during the displacement phase. Additionally, friction reducer alters the flow properties of the trapped liquid as indicated by increased surface tension, lower volumes of liquid removed and lower gas endpoint permeability at the same methanol concentration for cores saturated with slickwater. Majority of the improvement in gas permeability from methanol addition is by evaporation of the trapped liquid phase and is caused by increased volatility of the fracturing fluid. Results from multiphase permeability flow tests conducted with surfactant indicated that multiphase permeability evolution is driven by wettability alteration of the rock surface. Pretreatment of core sample with Novec FC-4430 before flooding with fracturing fluid results in best gas permeability improvement and liquid recovery. Triton X-100 did not improve gas permeability or liquid recovery during cleanup. Findings from this study can be used to optimize fracturing fluid and additive selection for field applications. Multiphase permeability data obtained is also useful for model assisted analysis of post fractured production performance in low permeability reservoirs.

Download or read book Permeability of Shale at Elevated Temperature and Pressure written by L. R. Myer and published by . This book was released on 1987 with total page 38 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Nano petrophysics of the Marcellus Formation in Pennsylvania USA written by Christina Marie Muñoz and published by . This book was released on 2019 with total page 100 pages. Available in PDF, EPUB and Kindle. Book excerpt: Characterizing unconventional shale reservoirs consisting of nano-size pores and pore networks are complicated due to their complex geometric structure and restrictive fluid transport abilities. Technological advancements with the use of multiple laboratory techniques for unconventional shale characterization has played key roles in determining their petrophysical properties with greater understanding and accuracy. Successful assessment of reservoir properties can be achieved by the measurement of porosity, permeability, pore size distribution, total organic carbon content, mineralogy, thermal maturity, wettability, tortuosity, with an understanding of the dispositional environments. The Marcellus covers as much as six states and occurs as deep as 9000 feet below the surface indicating a large potential and storage capacity for natural gas. Despite the Marcellus being the top shale gas producer in the United States it's also characterized by low porosity and permeability resulting in low-yields with declining production rates in some wells. In efforts to increase production or higher-yielding well completions in the shale, a greater understanding of the reservoir's petrophysical properties are essential for evaluation. This study will focus on the evaluation of nano-petrophysical properties of the Marcellus and underlying Utica that will provide additional information to the behavior of unconventional shale formations of the Appalachian basin, Pennsylvania. A series of experimental methodologies will be performed on samples gathered from five wells and two outcrops of the Marcellus and Utica formations in Pennsylvania. Analyses to be performed on samples include vacuum saturation, wettability/contact angle, x-ray diffraction (XRD), geochemistry, liquid pycnometry, mercury injection capillary pressure (MICP), imbibition and vapor absorption, and well-log analyses. Observations are then used to determine pore geometry and connectivity, migration, and storage characteristics within the Marcellus and Utica formations in the Appalachian basin, Pennsylvania. This will contribute to a better understanding of reservoir properties leading to the enhancement of well stimulation and completion methodologies for increased fluid migration and potentially increased production.

Download or read book Nanopetrophysical Characterization of the Wolfcamp A Shale Formation in the Permian Basin of Southeastern New Mexico U S A written by Ryan Jones and published by . This book was released on 2020 with total page 81 pages. Available in PDF, EPUB and Kindle. Book excerpt: The Permian Basin has been producing oil and gas for over a century, but the production has increased rapidly in recent years due to new completion methods such as hydraulic fracturing and horizontal drilling. The Wolfcamp Shale is a large producer of oil and gas that is found within both the Delaware and Midland sub-basins of the Permian. This study focuses on the Wolfcamp A section in the Delaware Basin which lies within southeastern New Mexico and west Texas. The most recent study performed to estimate continuous (unconventional) oil within the Delaware Basin was conducted in November 2018 by the USGS. They found that the Wolfcamp and overlying Bone Spring formations have an amount of continuous oil that more than doubles the amount found in the Wolfcamp of the Midland Basin in 2016. However, to ensure a high rate of recovery of this oil and gas it is important to understand the nano-petrophysical properties of the Wolfcamp Shale. This study aims to obtain the nano-petrophysical properties of the Wolfcamp A shale formation in Eddy County, NM. To determine petrophysical properties such as density, porosity,permeability, pore connectivity, pore-size distribution, and wettability, various testing procedures were used on a total of 10 samples from 3 different wells in the Wolfcamp A formation. These procedures include vacuum-assisted liquid saturation, mercury intrusion porosimetry (MIP), liquid pycnometry, contact angle/wettability, and imbibition, along with XRD, TOC, and pyrolysis evaluations. Results show that samples from two wells are carbonate dominated and contain 0.08-0.25% TOC, while the third well shows higher amounts of quartz/clay with 1.56-4.76% TOC. All samples show a high concentration of intergranular pores, and two dominant pore-throat sizes of 2.8-50 nm and >100 nm are discovered. Permeability and tortuosity values in the 2.8-50 nm pore network range from 2.75-21.6 nD and 375-2083, as compared to 8.85103-5.44×105 nD and 5.49-295 in the >100 nm pore network. Average porosity values range from 0.891-9.98% from several approaches, and overall wettable pore connectivity is considered intermediate towards deionized water (hydrophilic fluid) and high towards DT2 (n-decane:toluene=1:1, a hydrophobic fluid).

Download or read book Nano petrophysical Properties of the Bone Spring and the Wolfcamp Formation in the Delaware Basin New Mexico USA written by Ashley Chang and published by . This book was released on 2019 with total page 78 pages. Available in PDF, EPUB and Kindle. Book excerpt: The Permian Basin is one of the largest oil producing basins in the United States. The Permian Basin is 260 miles by 300 miles in area and encompasses 52 counties in southeast New Mexico and West Texas. In the past decade, the Permian Basin has exceeded its previous peak from the early 1970s (EIA, 2018). Now, the basin has generated more than 33.4 billion barrels of oil and roughly 118 trillion cubic feet of natural gas (EIA, 2018). The Permian Basin is a very complex sedimentary system, with three main sub-divisions that are geologically and stratigraphically different from one another. These three sub-divisions are the Midland Basin, Central Basin Platform and the Delaware Basin. The Delaware Basin, specifically the Bone Spring and Wolfcamp Formations, will be the focus of this study.Although the production in the Permian Basin has been accelerating, the steep decline rate in the production of the basin is a realistic concern. To better understand the factors contributing to the production decline rate, this study will investigate the pore structure and fluid migration within the Bone Spring and Wolfcamp Formations. Seven samples from the Wolfcamp are studied, along with two samples from the First Bone Spring unit and one sample from the Second Bone Spring unit. The methods used in this investigation include: total organic carbon (TOC) analysis and pyrolysis for the geochemistry, x-ray diffraction (XRD) to determine the mineralogy, vacuum saturation and liquid displacement, mercury intrusion capillary pressure (MICP) measurements of the sample's petrophysical properties (such as porosity, pore size distribution, tortuosity and permeability), and spontaneous imbibition to determine the pore connectivity in DI water and DT2 (n-decane: toluene= 2:1 in volume) fluids.The results from the methods stated above show that samples from the Wolfcamp and Bone Spring Formations are quartz or carbonate rich and have TOC values that range from 0.08-1.96%. The porosity of all samples range between 0.36-7.65%. Most samples have pores that are in the micro-fracture and intergranular pore range (>100 nm), with only three samples falling within the intragranular, organic matter, and inter-clay platelet pore range (2.5-50 nm). The samples with a predominant pore-throat network interval of 2.8-50 nm have a permeability that ranges from 0.55 nD to 294 nD, and a geometrical tortuosity that ranges from 2.7-85.2. Samples that have a predominant pore-throat network of >100 nm have a range of 2.55×104 nD to 6.02×109 nD in permeability, and a geometrical tortuosity range of 0.2-5.3. Three out of the 10 samples display a good pore connectivity towards DT2 fluid, and all samples show poor pore connectivity with DI water.

Download or read book Permeability and Pore Structure of Rocks Under Pressure written by Yves Bernabe and published by . This book was released on 1985 with total page 336 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Pores in Marcellus Shale written by and published by . This book was released on 2015 with total page 14 pages. Available in PDF, EPUB and Kindle. Book excerpt: Because of the development of hydraulic fracturing techniques, the production of natural gas has become increasingly important in the United States, which significantly increase the permeability and fracture network of black shales. Moreover, 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. Conversely, 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 watermineral interactions during hydrofracturing.

Download or read book Investigation of the Pore Size and Structure in Organic Rich Shales written by Sandra Nkechinyere Ezidiegwu and published by . This book was released on 2015 with total page 130 pages. Available in PDF, EPUB and Kindle. Book excerpt: Permeability in source rocks allows the flow of reservoir fluids during production and is dependent on the pore size distribution. In organic shales, the level of porosity of organic material (OM) is based on its range of pore sizes. Scanning electron microscope (SEM) images are commonly used to examine OM-hosted pores, but this technique is limited by resolution, which is in the order of ~5 nm. This study seeks to increase this range of pore size distribution (PSD) to ~ 0.38 nm, in organic-rich shales by using low-pressure carbon dioxide (CO2) adsorption coupled with density functional theory (DFT). In addition, we coupled low-pressure nitrogen (N2) adsorption with the Barrett-Joyner-Halenda (BJH) and DFT models to quantify pore sizes between ~2 to 170 nm. To characterize the entire range of pore sizes, we used high-pressure mercury intrusion because it is commonly used to quantify larger pores. The samples used in this study include a bulk sample and isolated kerogen of Green River shale (Eocene, Utah), Woodford shale (Upper Devonian, Oklahoma), and Cameo Coal (Cretaceous, Colorado). These samples represent type I, II and III, kerogen, respectively, at similar maturity levels and thus provide a good experimental basis for evaluating the PSD. The methodology consisted of four steps: i) Kerogens were isolated from the bulk samples by demineralization, ii) Samples were divided into sizes of ~ 0.5 grams into test tubes and degassed, iii) Samples were analyzed in the Porosimeter using low-pressure N2 and CO2 adsorption techniques, iv) Isotherm data from the adsorption measurement were extracted to create the PSD. Our results showed the presence of pore sizes as small as ~ 0.38 nm, based on combining techniques of N2 adsorption at 77 K and CO2 adsorption at 273 K in all three samples. Hence, we have expanded our understanding of the range of pore sizes contained in organic-rich material. In addition, the majority of pores in Green River shale and cameo coal fell below the SEM resolution limit of ~5 nm. Lastly, the kerogen and bulk samples of the Green River and Woodford shales showed a variation in the PSD, with the larger pores in the kerogen, which indicates that kerogen constitutes the majority of the pores in the samples. In conclusion, we developed a novel approach to investigate OM-hosted pore sizes. This approach increased the range of pore sizes from ~ 5 nm to ~ 0.38 nm, thus improving the estimation of flow rates during production in shale and in applicable reservoirs.