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Kazak, Andrey (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Simonov, Kirill (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Kulikov, Victor (PicsArt Inc. and Skolkovo Institute of Science and Technology)
Summary The modern focused ion beam-scanning electron microscopy (FIB-SEM) allows imaging of nanoporous tight reservoir-rock samples in 3D at a resolution up to 3 nm/voxel. Correct porosity determination from FIB-SEM images requires fast and robust segmentation. However, the quality and efficient segmentation of FIB-SEM images is still a complicated and challenging task. Typically, a trained operator spends days or weeks in subjective and semimanual labeling of a single FIB-SEM data set. The presence of FIB-SEM artifacts, such as porebacks, requires developing a new methodology for efficient image segmentation. We have developed a method for simplification of multimodal segmentation of FIB-SEM data sets using machine-learning (ML)-based techniques. We study a collection of rock samples formed according to the petrophysical interpretation of well logs from a complex tight gas reservoir rock of the Berezov Formation (West Siberia, Russia). The core samples were passed through a multiscale imaging workflow for pore-space-structure upscaling from nanometer to log scale. FIB-SEM imaging resolved the finest scale using a dual-beam analytical system. Image segmentation used an architecture derived from a convolutional neural network (CNN) in the DeepUNet (Ronneberger et al. 2015) configuration. We implemented the solution in the Pytorch® (Facebook, Inc., Menlo Park, California, USA) framework in a Linux environment. Computation exploited a high-performance computing system. The acquired data included three 3D FIB-SEM data sets with a physical size of approximately 20 × 15 × 25 µm with a voxel size of 5 nm. A professional geologist manually segmented (labeled) a fraction of slices. We split the labeled slices into training, validation, and test data. We then augmented the training data to increase its size. The developed CNN delivered promising results. The model performed automatic segmentation with the following average quality indicators according to test data: accuracy of 86.66%, precision of 54.93%, recall of 83.76%, and F1 score of 55.10%. We achieved a significant boost in segmentation speed of 14.5 megapixel (MP)/min. Compared with 0.18 to 1.45 MP/min for manual labeling, this yielded an efficiency increase of at least 10 times. The presented research work improves the quality of quantitative petrophysical characterization of complex reservoir rocks using digital rock imaging. The development allows the multiphase segmentation of 3D FIB-SEM data complicated with artifacts. It delivers correct and precise pore-space segmentation, resulting in little turn-around-time saving and increased porosity-data quality. Although image segmentation using CNNs is mainstream in the modern ML world, it is an emerging novel approach for reservoir-characterizationtasks.
BP has started production from a prolific new natural gas well in the Mancos Shale of New Mexico, a discovery that points to the area's potential as a large new gas supply source for the United States. Early production rates at the NEBU 602 Com 1H well in San Juan County are the highest achieved in the past 14 years within the San Juan Basin, a large oil- and gas-producing area spanning southwest Colorado and northwest New Mexico that includes the Mancos Shale. The well achieved an average 30-day initial production rate of 12.9 MMcf/D. The successful well test took place on assets that BP acquired from Devon Energy in late 2015, which expanded the company's position in the basin and provided improved access to the Mancos. The NEBU 602 Com 1H well was drilled with a 10,000-ft lateral in an area known as the Northeast Blanco Unit (NEBU), a section of federal lands in New Mexico's San Juan and Rio Arriba counties and an area where BP has been present since the 1920s.
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.
Guedez, Andreina (MetaRock Laboratories) | Govindarajan, Sudarshan (MetaRock Laboratories) | Lambert, Denton (Petricore) | Keyes, Steve (Petricore) | Patterson, Robert (MetaRock Laboratories) | Mickelson, William (MetaRock Laboratories) | Mitra, Abhijit (MetaRock Laboratories) | Aldin, Samuel (MetaRock Laboratories) | Gokaraju, Deepak (MetaRock Laboratories) | Thombare, Akshay (MetaRock Laboratories) | Aldin, Munir (MetaRock Laboratories)
Core analysis practices recommend removal of residual fluids before laboratory measurements of porosity, permeability, and fluid saturations. The most common methods used for core cleaning are Dean-Stark and Soxhlet extraction. While these techniques are adequate for conventional rocks, they are -a) time consuming and b) may induce micro-fractures in unconventionals with ultra-low permeability, thus affecting permeability and porosity measurement. In order to reduce the cost and time of fluid extraction and measuring permeability for such rocks, the GRI crushed-rock technique was proposed. However, the crushing process may destroy connected micro-pores which would not be accounted for in subsequent measurements.
A cleaning method for ultra-low permeability rocks involving multiple cycles of pressurized CO2 driven extraction has been previously proposed. The method employs automated gradual pressure release to avoid parting or fracturing the weak planes or the rock matrix during the CO2 phase change. However, it is critical to ascertain that the permeability increase is resulting from removal of fluids alone and not due to induced fractures.
The paper seeks to investigate the effect of the supercritical CO2 based cleaning process on the samples. The method undertaken is a multidisciplinary look utilizing a strength index, mineralogical composition, and studying the pore attributes and oil content before and after cleaning. Brazilian tensile strength is utilized as an index and is measured on multiple plugs at the same depth to assess whether samples develop fractures during cleaning. X-Ray Diffraction (XRD) is performed to characterize minerological composition while LECO TOC method and rock-eval pyrolysis are utilized to determine oil content. Pore attribute characterization is done by Scanning Electron Microscopy (SEM) and thin section study.
Source rock analysis confirmed the extraction of pore fluids. Preliminary results showed that tensile strength did not decrease significantly following fluid extraction. Comparison of the strength index before and after cleaning showed that a lower decrease in tensile strength is associated solely with the cleaning process while a bigger difference indicates presence of fractures. Additional pore attribute and mineralogical studies supported the results observed in the strength index characterization.
The suggested additions to the previously proposed cleaning method address uncertainties in core cleaning and help to enable representative measurement of petrophysical properties of ultra-tight rocks. The integrated study combining strength index characterization, petrographical and source rock analysis provides a comprehensive validation method for the effectiveness of the Huff & Puff cleaning technique.
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 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.
Fu, Pengcheng (Lawrence Livermore National Laboratory) | Huang, Jixiang (Lawrence Livermore National Laboratory) | Settgast, Randolph R. (Lawrence Livermore National Laboratory) | Morris, Joseph P. (Lawrence Livermore National Laboratory) | Ryerson, Frederick J. (Lawrence Livermore National Laboratory)
Summary The height growth of a hydraulic fracture is known to be affected by many factors that are related to the layered structure of sedimentary rocks. Although these factors are often used to qualitatively explain why hydraulic fractures usually have well-bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fractureheight growth. In this work, we study the role of the "roughness" of in-situ-stress profiles, in particular alternating low and high stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally vs. vertically. We found that a hydraulic fracture propagates horizontally in low-stress layers ahead of neighboring high-stress layers. Under such a configuration, a fracturemechanics principle dictates that the net pressure required for horizontal growth of high-stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the stressroughness profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic-fracture models to represent the effects of rough in-situ stress on fracture growth without directly representing the fine-resolution rough-stress profiles. Introduction The prediction and control of hydraulic-fracture-height growth are extremely important matters in both conventional-and unconventional-reservoir stimulation for both efficiency and environmental considerations (Maxwell 2011; Fisher and Warpinski 2012).
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.