|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
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 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.
ABSTRACT: Hydraulic fracturing in shales is challenging because of the complicated stress status. The confining pressure imposed on a shale formation has a tremendous impact on the permeability of the rock. The correlation between confining pressure and rock permeability is complicated and might be nonlinear. Gas flow in low-permeability shales differs significantly from liquid flow because of the Klinkenberg effect, especially when the pore pressure is relatively low. The Klinkenberg effect results from gas molecule slip at the solid walls inside the nanopores, where the collision between gas molecules and solid surfaces is more frequent than the collision between gas molecules. This effect causes the increase of apparent permeability (i.e., the measured permeability). In this study, the simple effective stress law and the effective stress coefficient law were used to study the relationship between permeability and effective stress. In the simple effective stress law, the effective stress is calculated as the difference between confining pressure and pore pressure. The Klinkenberg coefficient and the effective mean pore radius can then be calculated. In the effective stress coefficient law, there is an effective stress coefficient (i.e., the Biot coefficient) which controls the influence of pore pressure on the effective stress. In this study, the effective stress coefficient was obtained by analyzing a large number of laboratory data measured under varying pore pressures and confining pressures. Specifically, the permeabilities of core samples extracted from four U.S. shale formations were measured using a pulse decay permeameter under varying combinations of confining and pore pressures. The samples were cored in the directions parallel to and perpendicular to the shale bedding planes, in order to test the role of bedding plane direction on the measured permeability. Laboratory results demonstrate that the permeabilities of all core samples fell in the range between 10-2 millidarcy (mD) and 10-4 mD. In the same formation, the permeabilities of the core samples in which the bedding planes were in the longitudinal direction were about one order of magnitude higher than the permeabilities of the core samples in which the bedding planes were in the transverse direction. Using the simple effective stress law, the Klinkenberg effect was observed, because the measured apparent permeability decreased with increasing pore pressure. Using the effective stress coefficient law, the effective stress coefficient was found around 0.5, which suggests that the pore pressure had a less influence on the effective stress compared to the confining pressure. Moreover, a multiphysical shale transport (MPST) model is built that accounts for fluid dynamics, geomechanics, and the Klinkenberg effect. The model fitting result is quite matched with PDP experimental results. These comprehensive laboratory experiments and model fitting demonstrate the role of confining pressure, Klinkenberg effect, and bedding plane direction on the gas flow in the nanoscale pore space in shales. These experimental data will be valuable in validating and calibrating pore- to core-scale numerical models of the flow and transport properties in shale formations.
Summary A Sand Wash Basin well was drilled for an unconventional target for which the measured core properties did not match production for the well. The crushed‐rock porosity for the core suggested a bulk‐volume hydrocarbon (BVH) of 1.5 to 2.0 p.u., indicating that the stimulation would have to be draining at approximately 400 ft vertically. To resolve this incongruity for further field development, we investigated the validity of crushed‐rock porosity and nuclear magnetic resonance (NMR) to accurately assess the resource. Initial results using conventional 2‐MHz core NMR yielded results similar to those for crushed‐rock porosity. Because unconventional rocks have very fast relaxations in NMR, it was then theorized that with the use of a high‐resolution 20‐MHz machine, the signal/noise ratio would improve and create a more‐accurate quantification of porosity components. The results of using a high‐resolution 20‐MHz NMR showed a porosity increase from 6.5 p.u. using the Gas Research Institute (GRI) methodology (Luffel et al. 1992) to 14 p.u. on an as‐received sample, creating a large increase for in‐place calculations. As a result, a process termed sequential fluid characterization (SFC) was developed using high‐resolution 20‐MHz NMR to quantify all components of porosity (i.e., movable fluid, capillary‐bound water, clay‐bound water, heavy hydrocarbon, residual hydrocarbon, and free water). This method represents an alternative to crushed‐rock methodologies (such as GRI and tight rock analysis) that will accurately quantify movable porosity as well as the other components without the errors introduced by cleaning and crushing. After investigating the application of SFC with the high‐resolution 20‐MHz NMR, it was identified that other unconventional plays (such as Marcellus and Fayetteville) have an average of 45% uplift on in‐place calculations using SFC‐based movable porosity. Identifying in‐place volumes correctly can vastly improve the characterization of fields and prospects for unconventional‐resource development, and, as is shown in this paper, SFC can be used to do so with a great effect on volume assessment in unconventional reservoirs.
Abstract Shale reservoirs exhibit evolution of resistivity with a noted reversal typically occurring at the wet- to dry-gas transition. This study documents this phenomenon and investigates mechanisms that cause and influence the reversal. In many shales, resistivity evolves from low resistivity at low thermal maturity, increases with increasing maturity, commonly peaking in the wet-gas window, and then decreases at the wet- to dry-gas transition. In highly organic shales at very high maturities (﹪Ro>3) resistivities can be up to three orders of magnitude less than observed in the same formation at peak resistivities. Resistivity changes can be related to changes in water saturation and distribution, resistivity of the water, mineral matrix (e.g., clays, pyrite, organic matter), or pore network. These, in turn, are related to evolution of mineral and fluid properties, fluid-rock properties, porosity, and pore-size distribution. Two key variables are wettability and capillary pressure (Pc) which influence water saturation (Sw) and distribution. Thermal maturation of kerogen from oil generation onset through wet gas involves both expulsion of polar hydrocarbons from the kerogen that can partially wet adjacent mineral surfaces and the development of partial to fully oil-wet porosity within the organic matter (OM). Increase in oil wetness decreases Pc and the continuity of the water-wet surface which increases resistivity. Further thermal evolution causes cracking of polar, surfacewetting, heavy hydrocarbons to lighter, non-polar, non-surface-wetting hydrocarbons. This decreases oil wetness and associated electrical resistivity. Concurrently, free hydrocarbons undergo cracking from low API/low gas-oil ratio (GOR) to high API/high GOR. The associated decrease in contact angle acts to increase Pc. At constant hydrocarbon pressure, an increase in Pc might increase Sw and bulk volume water (BVW), or cause expulsion of hydrocarbons from small pores, which decreases resistivity. Other mechanisms that can act to decrease resistivity to varying degrees include: increasing aromaticity and graphene within kerogen, increasing pyrite content, and increasing brine salinity associated with water vaporization in overpressured expelled gas. Conversely, mechanisms that can act to increase resistivity include: porosity occlusion, pore-throat size decrease, and decrease in clay cation exchange capacity. Resistivity reversal is a significant phenomenon and is exhibited on well-log cross sections for the Niobrara Formation in the Piceance, Sand Wash, and Denver basins (Al Duhailan and Cumella, 2014) and is observed in other shale formations (e.g., Woodford, Barnett, Fayetteville, Eagle Ford, Marcellus, Utica, Mowry, Mancos, Vaca Muerta). Understanding and quantifying this phenomenon is important for accurate log-saturation determination and may be used to map the wet-to-dry-gas transition for shale reservoirs.
Abstract Hydraulic Fracturing has been used successfully in the oil and gas industry to enhance oil and gas production. Recent years have seen the great development of tight gas, coalbed methane, and shale gas. Different fluids were used as fracturing fluids in shale and sandstone formations, including the use of CO2, N2 and CO2 foam, slick water, crosslinked solutions, and oil-based fracturing fluids. The objective of this study is to develop an experimental setup to measure the breakdown pressure to initiate the fractures in shale and tight sandstone cores. This study investigated the effect of injection flow rate, temperature, fluid viscosity, and fluid type on the breakdown pressure of different rock cores. 5 wt% KCl brine, slick water with a friction reducer, linear gel systems were used as a fracturing fluid. Kentucky, Scioto, Bandera, and Berea sandstone cores were used. Also, Mancos, Marcellus, and Barnett shale cores were used in this study. Finally, the behavior of the breakdown pressure was examined as a function of the back pressure (0, 100, 300 psi). The preliminary results show that the breakdown pressure increased as the injection flow rate increased. Where the breakdown pressure increased from 438 to 1,000 psi as the flow rate increased from 5 to 10 cm/min in case of 5 wt% KCl with Kentucky sandstone cores. The breakdown pressure increased in Marcellus shale to 1,800 psi in case of 5 wt% KCl at 5 cm/min. As the fluid viscosity increased the breakdown pressure increased, it increased to 1,115 psi in case of 2 gptg friction reducer (5 cp) comparing to 5 wt% KCl (1.1 cp) case at 5 cm/min. A straight line relationship was found between the breakdown pressure and the logarithmic scale of the fluid viscosity. This study will give recommendations for the fluid viscosity, type, and the injection flow rate that will improve the efficiency of the hydraulic fracturing operation.
In this study, experiments were done on samples from the Marcellus, Woodford, and Eagle Ford shales. The experiments showed that samples from these formations were grossly water-wet, mixed-wet and oil-wet, respectively. The correlation of average wettability index with total organic carbon (TOC) showed that 5 wt% is the critical TOC content required to achieve connectivity and generate oil-wet pathways. Similarly, correlation of average wettability index with clay content showed that <10 wt% clay, samples are oil-wet and >65 wt%, they are predominantly water-wet, and between 10 and 65 wt% clay content, samples exhibited mixed wettability. The threshold values of 5 wt% TOC and 10 wt% clays represent the same volumetric fraction (~10%) of the rock. The figure of 10% can be thought of as percolation threshold for connectivity in shale rocks.
Scanning electron microscope (SEM) imaging done on representative samples (one per formation) was used to quantitatively assess the fraction of different pore types. The fractions of different pore types were in agreement with the observations from the macroscopic imbibition experiments. For instance, oil-wet Eagle Ford samples had a higher fraction of organic pores (22.5%) while water-wet Marcellus samples had a higher fraction of inorganic pores (40%). The samples from all the three shales had a high fraction of mixed-wet pores (Marcellus 57%, Eagle Ford 69%, and Woodford 68%). This knowledge of fractions of different pore types can be instrumental in modeling connectivity pathways.