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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 In this paper, we report multi-stage creep experiments in shales at three different temperatures. We used two samples from the Wolfcamp formation in the Permian Basin with different mineralogy and bedding orientations. In these experiments, we increased the confining pressure to 40 MPa followed by an increase in differential stress to 40 MPa at room temperature. The differential stress was then kept constant several hours. We repeated these loading steps at 50 °C and 80 °C to study the effect of temperature on viscoplastic properties. The results from this study showed that the viscoplastic deformation of the horizontally drilled sample with bedding planes is more affected by the elevation of temperature than the vertically drilled sample with no distinguished bedding planes, although the latter sample has a higher percentage of clay and organic matter. 1. INTRODUCTION Propagation of hydraulic fractures requires the pressure inside the fractures to exceed the magnitude of the least principal stress. In this context, vertical propagation of hydraulic fractures in unconventional shale formations is controlled by variations of the magnitude of the least principal stress with depth. In previous papers from our group, we showed that the magnitude of stress variation is a function of the relative degree of viscoplastic stress relaxation. This time-dependent viscoplastic behavior is shown to be affected by the mechanical and mineralogical properties of the rocks, especially clay plus kerogen content [1–4] as well as the reservoir stress and thermal conditions [5–7]. So far, we have used the following simple power-law model, a simple model that fits the collected creep data over different time periods reasonably well [2,8]: (equation) In this model ε is creep strain, σ is the applied differential stress, t is time, J is the creep compliance factor and B and n are creep constants. In these publications [6, 10], we argued that the B and n values represent recoverable and inelastic deformation of shale rocks, respectively. We conducted all these creep tests at room temperature. Here, we try to initiate expanding the power-law model for creep date at intermediate reservoir temperatures.
Abstract The combination of extended-length horizontal drilling and high volume hydraulic fracturing has led to previously unimaginable production increases, yet the recovery potential of unconventional oil and gas resources remains largely unrealized. Recovery factors for unconventional oil and gas wells are typically reported at < 20% in gas shale reservoirs and < 10% in the oil plays. Neutrally buoyant ultra-lightweight proppants have been demonstrated to effectively provide production from fracture area that is otherwise unpropped and thus, non-contributive with conventional sand/slickwater hydraulic fracturing processes. Production simulations illustrate that treatment designs incorporating neutrally buoyant ULW proppant treatment designs tailored for contemporary unconventional well stimulations deliver cumulative production increases of 30% to over 50% compared to the typical large volume sand/slickwater treatments. Unfortunately, production simulation results may not sufficiently lessen risk uncertainties for operators planning high-cost multi-stage horizontal stimulations. Therefore, several field trial projects using the neutrally buoyant ULW proppant in extended-length horizontal unconventional wells are currently in progress to validate the production simulations. Since the initial 4-stage fracturing stimulation incorporating neutrally buoyant ultra-lightweight proppant in 2007, deployment has occurred in fracture stimulating hundreds of oil and gas wells spanning multiple basins and reservoirs. Most of the wells are vertical or relatively short lateral wells common to asset development practices predating the unconventional shale completions mania, but many were targeted at the same unconventional reservoirs as the current multi-stage horizontal completions. Several published case histories have documented the production enhancement benefits afforded by the legacy ULW proppant wells, but questions remained as to how those lessons might be correlated to provide engineers confidence in the current production simulations. Well completion and production information was mined from the various accessible databases for the neutrally buoyant ULW proppant wells. The scope of the legacy data compiled for analysis was limited to the reservoirs common to the current field trials and production simulations, ie. unconventional oil and gas shale reservoirs. Production performance contributions of neutrally buoyant ULW proppant in past applications were compared with the production uplift observed in applications and/or simulated application of neutrally buoyant ultra-lightweight proppant fracturing treatments in current multi-stage horizontal reservoirs. The lessons learned from this investigation provide the practicing engineer the means to confidently assess production simulation data for multi-stage horizontal unconventional completions incorporating neutrally buoyant ulw proppant in the treatment designs.
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.
ABSTRACT: Many of unconventional shale reservoirs are marginally economic due to a combination of high drilling and completions costs and/or low productivity. Technological advances in horizontal drilling and hydraulic fracturing have alleviated these burdens but additional cost reductions and productivity enhancements can be achieved by understanding how the various mineralogy shale rocks mechanical properties and embedment changes during hydraulic fracturing.
In this paper, numerous reservoir shale samples from the Marcellus, Mancos, Eagleford, and Wolfcamp formations were exposed to commonly-used fracture fluids to determine the corresponding changes in the rock mechanical properties. These samples were also subjected to proppant embedment testing to assess the potential reduction in fracture width. The mineralogy of each sample was measured to understand its impact on the changes in rock mechanical properties and corresponding proppant embedment.
The results of this study indicate a reduction in the compressive strength and elastic moduli after exposure to the various fracture fluids. Additionally, there is a significant increase of proppant embedment at given stress levels for different proppant types. This reduction in modulus, combined with increased proppant embedment, can lead to a decrease in fracture conductivity and a subsequent loss of productivity.
Increasing demand of fossil fuels have made unconventional shales, which are the source, the seal, and reservoir all in one, gain significant advancement in last few decades, encouraged by emerging technologies in hydraulic fracturing and horizontal drilling. Hydraulic fracturing in the formation is achieved by pumping large volume of fluids into the pay zone followed by slurry of mostly proppant to keep the fractures open and create a conductive path for reservoir fluids once the pressure is reduced.
A successful fracture treatment job requires understanding of shale mechanical properties to create a conductive pathway. An effective achievement of conductive pathway requires the use of two principal materials: fracturing fluid (and additives) and proppant. Shale mechanical properties such as Young's modulus can get affected due to exposure with the fracturing fluids, resulting in weakening of rock frame with time. Any reduction in Young's moduli leads to conductivity loss by reduced fracture width due to proppant embedment as closure stress increases. This reduction in conductivity varies from one formation to other depending upon the mechanical properties, mineralogy, proppant type, fracturing fluid and closure stress. Fracture conductivity reduction in ultra-tight shale reservoirs can have significant economic value and it is desired to optimize the fracture design to improve production and lower completion cost.
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 plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells. Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part. Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry. The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.