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Summary A novel multiphysics multiscale multiporosity shale gas transport (MST) model was developed to investigate shale gas transport in both transient and steady states. The microscale model component contains a kerogen domain and an inorganic matrix domain, and each domain has its own geomechanical and gas transport properties. Permeabilities of various shale cores were measured in the laboratory using a pulse decay permeameter (PDP) with different pore pressure and confining stress combinations. The PDP-measured apparent permeability as a function of pore pressure under two effective stresses was fitted using the microscale MST model component based on nonlinear least squares fitting (NLSF), and the fitted model parameters were able to provide accurate model predictions for another effective stress. The parameters and petrophysical properties determined in the steady state were then used in the transient-state,continuum-scale MST model component, which performed history matching of the evolutions of the upstream and downstream gas pressures. In addition, a double-exponential empirical model was developed as a powerful alternative to the MST model to fit laboratory-measured apparent permeability under various effective stresses and pore pressures. The developed MST model and the research findings in this study provided critical insights into the role of the multiphysics mechanisms, including geomechanics, fluid dynamics and transport, and the Klinkenberg effect on shale gas transport across different spatial scales in both steady and transient states.
Tabatabaei, Maryam (Pennsylvania State University) | Dahi Taleghani, Arash (Pennsylvania State University) | Cai, Yuzhe (Pennsylvania State University) | Santos, Livio (Pennsylvania State University) | Alem, Nasim (Pennsylvania State University)
Summary Proppant bed can play a critical role in enhancing oil and gas production in stimulated wells. In the last 2 decades, there have been consistent efforts to improve shape characteristics and mechanical strength properties to guarantee high permeability in the resultant propped fracture. However, engineering the surface properties of proppants, such as tuning their wettability, has not received considerable attention. Considering that water-wet proppants can not only limit production because of reduced hydrocarbon relative permeability but also facilitate fines migration through the proppant bed, a methodology is presented here to alter the wettability of proppants using graphite nanoplatelets (GNPs). The idea benefits from the intrinsic hydrophobicity of graphitic surfaces, their relatively low cost, and their planar geometry for coating proppants. Conductivity tests are conducted according to ISO 13503-5:2006 (2006) and API RP 19D (2008) to examine how the coating process changes the relative permeability to water and oil. According to the simulation results, the newly developed graphite-coated proppants speed up the water cleanup and increase long-term oil production in an oilwet reservoir. Introduction Hydraulic fracturing has unlocked considerable reserves of oil and gas from impermeable shale rocks by benefiting from highly permeable propped fractures. Hydraulic-fracturing treatments induce extensive fracture networks by cracking the formation rock and possibly connecting pre-existing fractures (Dahi-Taleghani and Olson 2011). In fracturing treatments, the fracturing fluid, which is mainly composed of water and other chemical additives, is pumped into the formation at high pressure to form fractures.
Summary We present a comprehensive investigation of gas injection for enhanced oil recovery (EOR) in organic-rich shale using 11 coreflooding experiments in sidewall core plugs from the Wolfcamp Shale, and three additional coreflooding experiments using Berea Sandstone. Our work studies the effect of pressure, minimum miscibility pressure (MMP), soak time, injection-gas composition, and rock-transport properties on oil-recovery factor. The injection gases were carbon dioxide (CO2) and nitrogen. The core plugs were resaturated with crude oil in the laboratory, and the experiments were performed at reservoir pressure and temperature using a design that closely replicates gas injection through a hydraulic fracture, minimizes convective flow, and exaggerates the fracture to the reservoir-rock ratio. We accomplished this by surrounding the Wolfcamp reservoir-rock matrix with glass beads. Computed-tomography (CT) scanning enabled the visualization of the compositional changes with time and space during the gas-injection experiments and gas chromatography provided the overall change in composition between the crude oil injected and the oil recovered. As gas surrounds the oil-saturated sample, a peripheral, slow-kinetics vaporization/condensation process is the main production mechanism. Gas flows preferentially through the proppant because of its high permeability, avoiding the formation and displacement of a miscible front along the rock matrix to mobilize the oil. Instead, the gas surrounding the reservoir-core sample vaporizes the light and intermediate components from the crude oil, making recovery a function of the fraction of oil that can be vaporized into the volume of gas in the fracture at the prevailing thermodynamic conditions. The mass transfer between the injected gas and the crude oil is sufficiently fast to result in significant oil production during the first 24 hours, but slow enough to cause the formation of a compositional gradient within the matrix that exists even 6 days after injection has started. The peripheral and the slow-kinetics aspects of the recovery mechanism are a consequence of the low fluid-transport capacity associated with the organic-rich shale that is saturated with liquid hydrocarbons. Our results show CO2 overperforms nitrogen as an EOR injection gas in organic-rich shale, and higher injection pressure leads to higher oil recovery, even beyond the MMP. The gas-injection scheme should allow enough time for the mass transfer to occur between the injected gas and the crude oil; we achieved this in the laboratory with a huff ’n’ puff scheme. Our results advance the understanding of gas injection for EOR in organic-rich shale in a laboratory scale, but additional work is required to rigorously scale up these observations to better design field applications.
Matrix acidizing is commonly used as a preflush to the hydraulic-fracturing stimulation of shale formations. The process dissolves sediments and mud solids that inhibit the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons. In this paper, the mineralogical and physical responses to matrix acidizing of several important North American shale formations are evaluated. A few studies have quantified the effect of hydrochloric acid (HCl) matrix acidizing on mineralogical and physical properties of shale formations. However, less is known about the development of conductivity and the acid concentrations necessary to optimize conductivity and, by extension, the impact on production and rock stability.
A second look at the size of US shale formations is revealing they hold far more natural gas, and pushed a new name up near the top of the list: the Mancos Shale. A recent reassessment of the formation in western Colorado concluded it holds 66 Tcf of shale gas that could be produced using current technology, making it second only to the prolific Marcellus Formation for unconventional gas in the US. This elevates the profile of the formation, which the US Geological Survey (USGS) had previously estimated at 1.6 Tcf in 2003. The agency also recently upped its estimate for the Barnett Shale, doubling it to 53 Tcf. "We reassessed the Mancos Shale in the Piceance Basin as part of a broader effort to reassess priority onshore US continuous oil and gas accumulations," said Sarah Hawkins, a USGS geologist who was the lead author of the study.
Temizel, Cenk (Saudi Aramco) | Canbaz, Celal Hakan (Ege University) | Gok, Ihsan Murat (NESR) | Roshankhah, Shahrzad (Caltech) | Palabiyik, Yildiray (ITU) | Deniz-Paker, Melek (Independent Consultant) | Hosgor, Fatma Bahar (Petroleum Software LLC) | Ozyurtkan, Hakan (ITU) | Aksahan, Firat (Ege University) | Gormez, Ender (METU) | Kaya, Suleyman (METU) | Kaya, Onur Alp (METU)
Abstract As major oil and gas companies have been investing in shale oil and gas resources, even though has been part of the oil and gas industry for long time, shale oil and gas has gained its popularity back with increasing oil prices. Oil and gas industry has adapted to the low-cost operations and has started investing in and utilizing the shale oil sources significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of shale oil and gas reservoirs as a significant source of energy in the current supply and demand dynamics of oil and gas resources. A comprehensive literature review focusing on the recent developments and findings in the shale oil and gas resources along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using SCOPUS database to other renowned resources including journals and other publications. All gathered information and data are summarized. Not only the facts and information are outlined for the individual type of energy resource but also the relationship between shale oil/gas and other unconventional resources are discussed from a perspective of their roles either as a competing or a complementary source in the industry. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the shale oil/gas as it stands with respect to other energy resources. Among the few existing studies that shed light on the current status of the oil and gas industry facing the rise of the shale oil are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between heavy and light oil as a complementary and a competitor but harder-to-recover form of hydrocarbon energy within the era of rise of renewables and other unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Abstract Acid fracturing is a promising technique to stimulate the induced unpropped (IU) fractures which are created in shales during hydraulic fracturing. These fractures have enormous surface area, but close during production due to their inability to accommodate proppants. The use of acid has been proposed as a way to keep these IU fractures open after pumping has ceased. A successful acid fracturing treatment requires the acid to effectively etch the shale fracture surfaces to create a connected flow pathway that will remain open when stress is applied. This requires the acid etching to be non-uniform. Changes in fracture surface topography and mechanical properties are critical in determining how the fracture conductivity will change with stress. In this study, 55 preserved shale samples from Barnett, Eagle Ford, Haynesville and Utica shale covering a wide range of mineralogy (with clay 3.4 - 75.6 wt% and carbonate 1.9 - 83.7 wt%) were used to systematically investigate the effect of acid treatment on their fracture surface topography, mechanical properties and fracture conductivities. The mechanical properties of the fracture surface were measured using indentation tests. Fracture conductivities were computed with a numerical model that simulates unpropped fracture closure. The results showed that the roughness of all the fracture samples increased after acid etching, but to different extents. The roughness was initially 1.58 ± 0.29 µm and developed into two groups: the low roughness group for roughness within 6 µm, and the high roughness group with roughness over 10 µm and up to 43.71 µm. Although carbonate-rich samples were more likely to produce high roughness, high carbonate content did not necessarily always lead to rougher surfaces. The amount and the distribution pattern of carbonate minerals affected the etched surface topography. On surfaces of low etched roughness, isolated pits with diameter of 10-30 um were formed, while profile valleys at millimeter scale were developed on surfaces of high roughness, and some of these valleys were connected to form channels. Acid caused additional shale softening than brine exposure, mainly by removal of carbonate minerals. Acid fracturing was found to improve fracture conductivities under reservoir pressure mostly in cases of high etched roughness; while fractures with low etched roughness, conductivities were lower than or close to factures treated by brine. Experimental results on surface topography, mechanical properties and the modeled fracture conductivities of acid-fractured shales of a wide range of mineralogy are presented. The results are important in selecting candidate shale plays for acid fracturing, and also provide useful parameters for modeling and field design.
Abstract With advancements in technology such as horizontal drilling and hydraulic fracking, operators are able to pursue reserves in unconventional mudrock reservoirs. Brittleness, one of the many pre-screening considerations, is an important parameter because it determines whether a mudrock can be effectively stimulated via hydraulic fracking. The industry currently uses several geochemical signals (e.g. Si/Al and Si/Zr) to identify authigenic silica phases present in an unconventional reservoir. Cemented horizons are prime candidates for placing hydraulic fracks due to the strengthening effects of mineral cements on the rock frame. A similar geochemical method for readily indicating the occurrence of authigenic carbonate has not been identified. This study documents trace element geochemical differences between biogenic (detrital) carbonate phases and associated cements so that chemical proxies may be used to differentiate authigenic carbonate phases using bulk geochemical data. Both carbonate-rich formations (e.g. Eagle Ford and Niobrara) and argillaceous formations (e.g. Haynesville and Marcellus) are examined to gain insight into reservoir brittleness, using bulk and trace elements such as Ba, Mg, Mn, Fe, Sr, and Ca. The goal is to develop a technique that can be implemented real-time by the mudlogging unit at the wellsite and during the initial core analysis phase. This method will allow a more targeted placement of hydraulic fracking zones to increase permeability and hydrocarbon production in mudrock reservoirs. Electron probe micro analysis (EPMA) on several types of carbonate was conducted on low (0.45 %Ro) and high (2.5 %Ro) thermal maturity Eagle Ford and Haynesville Formation samples, respectively. The EPMA reveals that Sr is the primary elemental signature of the authigenic carbonate phase within the low maturity Eagle Ford. The Haynesville EPMA reveals higher variability of Fe, Mn, Sr, Mg, and Ba trace element concentrations, however the dominant elemental signature associated with the authigenic phases is elevated concentrations of Fe and Mn. Utilizing XRF, Sr/Ca and Ca-Fe-Mg cross-plots can be used as proxies to identify authigenic carbonate in the Eagle Ford and Haynesville Formations respectively, and can be used to indicate brittle zones for target adjustments at the wellsite.
Abstract The investigation of the effect of hydration swelling on induced fracture generation and the resulted permeability in shale has considerably expanded in recent years. However, only a few experiments under anisotropic compressive stress conditions have been done in this area. The experiment methodology that was presented in this paper can be used to study the effect of hydration swelling on fracture initiation and propagation, and the change of shale permeability under anisotropic compressive stress conditions. An artificial fracture through a core was created before the test to simulate the hydraulic fracture generated during the fracturing process. Distilled water was used to simulate the hydraulic fracturing fluid. A CT scanner was used to collect the CT images of fracture development. A digital pressure transducer was used to monitor the upstream pressure change, and the downstream pressure was kept at atmosphere pressure. We, for the first time, combined water adsorption, stress anisotropy conditions, and shale permeability change into one test. Five tests were conducted: three tests underwent stress anisotropy, and the other two tests employed stress isotropy. These tests were continuously exposed to working fluids at a constant flow rate. From the results, the increase in the apparent weight of cores showed that water could be adsorbed into shale samples during the tests. In shale samples with stress anisotropy conditions, fractures through the core were generated. More fractures were created under larger differential stress conditions. The upstream pressure decreased when fractures through the core were generated or particle detachment happened. The decrease in pressure indicates that hydration may be beneficial to shale permeability recovery. To differentiate the effect of hydration and stress anisotropy on fracture generation, one sequential imbibition test was conducted (oil, then water). Fractures can be generated if the imbibition fluid changed from oil to water. The results supported the previous result that hydration may induce fractures (Liu and Sheng, 2019). The experimental results show that this methodology is a practical way to study the effect of hydration on shale properties in the process of hydraulic fracturing.
Abstract The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.