bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Deep Learning and Computer Vision Techniques to Improve Facility Corrosion Risk Management Systems
Authors: Ejimuda C. C. , Ejimuda C. M. 
Published: April 2018

Abstract
During fit for service or corrosion risk assessments of oil and gas facility systems, a key parameter required to design and implement an effective risk management strategy is visual inspection. This paper explains how using state of the art computer vision and deep learning techniques could address such challenges. We mainly used the python programming language, Tensorflow Application Programming Interface, Resnet deep learning architecture, GPU machines and cloud computing technologies to achieve this. Beyond the challenges of obtaining sufficient corrosion defects data, our final solution is a systematic method that would assist field personnels, facility engineers, service companies and management more accurately detect corrosion defect types and failure modes unbiasedly. This leads to more cost effective and quicker recommendation of preventive or corrective measures.
Evolution of CO2 Utilization Ratio and CO2 Storage under DifferentCO2 - EOR Operating Strategies: A Case Study on SACROC Unit Permian Basin
Authors: Hosseininoosheri P. , Hosseini S. A. , Nunez-Lopez V. , Lake L. W. 
Published: April 2018

Abstract
There are several parameters affecting the net and gross CO2 utilizations during a CO2-EOR process. Although many of the parameters cannot be changed for a specific hydrocarbon reservoir, the field development strategy is one of the parameters that could be chosen in a way to get the most favorable CO2 utilization ratios, oil production, and CO2 storage. This paper presents a field scale compositional reservoir fluid flow model in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. The model was developed to investigate the impact of various injection scenarios, such as CGI (Continuous Gas Injection) and WAG (Water Alternating Gas) on CO2 utilization ratio, oil production, and CO2 storage during CO2 injection. Additionally, we demonstrated the amount of stored CO2 in different phases: dissolved in brine, miscible in oil, residual CO2, and mobile CO2 and correlated the contribution of different trapping mechanisms to the utilization ratios. A high-resolution geocellular model, which was constructed based on wire-line logs, seismic surveys, core data, and stratigraphic interpretation, is used for numerical simulations. Previous studies skipped the history matching of the field; however, the initial distribution of fluids plays an important role in CO2–EOR efficiency. Therefore, a comprehensive history matching of primary, secondary, and tertiary recovery was conducted for this study. The history matching process included matching the average reservoir pressure, the oil and water production, and most importantly the gas production. The results show that the utilization ratio is not a constant number and evolves during the injection period. The results of this study also shows how the evolution of oil miscibility trapping over the injection time controls the evolution of net CO2 utilization ratios. CGI showed higher utilization ratios than WAG. We also compared both the total stored amount and the amount of stored CO2 in different phases. Finally, we compared the amount of produced oil for the assumed field development strategies. Results show that the amount of produced oil by WAG and CGI are so close. Among the various scenarios explored, WAG seems be a promising operational approach to balance both storage and oil production. The present work provides valuable insights for optimizing oil production and CO2 storage based on the evolution of net CO2 utilization ratios.
Experimental Study on the Effect of Injection Parameters on Proppant Transport in Rough Vertical Hydraulic Fractures
Authors: Huang H. , Babadagli T. , Li H. , Develi K. , Wei G. 
Published: April 2018

Abstract
The understanding of proppant flow through fractures is critical in evaluating the hydraulic fracturing performance. As a continuation of our experimental efforts devoted to understanding how proppant flows in rough vertical fractures, in this paper, we examine the effect of injection parameters on the proppant transport in rough vertical fractures. The effects of polymer concentration, injection rate, proppant concentration, and type of proppant were investigated in detail. Experimental results show that a sufficiently high polymer concentration is needed to enable effective proppant flow in rough fractures. In general, the relative coverage of proppants increased dramatically as the polymer concentration increased, implying that the higher viscosity of fracturing fluid could enhance the slurry's ability to place more proppant vertically into the fracture and help to maintain a better conductivity after fracturing treatment. A sufficiently high injection rate of the slurry is also needed to enable effective proppant flow in rough fractures. At certain low injection rate, the proppants carried by a low polymer solution might not exhibit a tree-like settling pattern, diminishing the effect of roughness effect on the proppant transport. This means that even in rough fractures, the tree-like settling pattern of the proppants did not necessarily occur for sure; the injection rate should be properly selected to enable such phenomenon. With other condition being kept constant, a higher proppant loading led to a higher final relative coverage of the proppants in the rough fractures. But if the injection rate used for delivering the proppants is not sufficiently high, we may encounter injectivity issues; in our lab experiments, this caused the choking of the pump. The heavier proppant (ceramic proppants) in the rough fracture models tended to suppress the tree-like settling pattern that was experienced by the lighter proppant (silica sands). This is attributed to the larger density of the ceramic proppants, leading to a larger settling velocity. In order to maximize the spreading of a given proppant over a rough fracture model, we should determine the proper values of all the essential injection parameters (including polymer solution, injection rate, proppant concentration) by striking a good balance among them. The conclusions obtained in this study shed light on how to optimize slurry injection parameters to achieve an optimal proppant-filling ratio during hydraulic fracturing.
Fracture Quantification Method with 3D X-Ray Image - Entropy-Assisted Indicator Kriging Method
Authors: Wang H. , Rabiei M. , Wang S. , Cui G. 
Published: April 2018

Abstract
With the low porosity and low permeability in Bakken Oilfield, the fracture as principal flow channel is of vital importance. The access to micro X-ray scanning technique makes the quantification of fracture feasible. In this paper, entropy-assisted indicator kriging method is applied to segment the CT images of a shale rock sample core. This method combines the global and local information of the grayscale value. Use triple Gaussian distributions to fit the grayscale value distribution of fracture, matrix and mineral phase respectively, to obtain the global threshold. With the threshold values, the initial segmentation can be finished. Combine the initial segmentation result with entropy function to determine the boundary pixels. Then, operate indicator kriging to classify the boundary pixels. Based on the final segmentation result, the distribution of fractures and mineral phase can be observed and quantified in 3D views: There are two fractures running through the rock sample, and detailed parameters can be seen in Table 2. The volume fraction of fracture and mineral phase is 0.64% and 1.29%, respectively.
Modeling the Combined Effects of Water Salinity and Polymer Rheology on the Performance of Polymer Flooding and In-Depth Gel Treatment
Authors: Khamees T. K. , Flori R. E. 
Published: April 2018

Abstract
Assessment of the potential of polymer flooding and gel treatment to investigate their roles of improving sweep efficiency requires an accurate modeling of polymer rheology (polymer viscosity versus shear rate) coupled with the effects of water salinity. A 3-D simulation model that represent quarter of five-spot pattern with one injector and one producer was utilized to run different scenarios using 1,000 ppm partially hydrolyzed polyacrylamide (HPAM) polymer solution with brine varying in salinities from 2,000 to ppm using UTGEL simulator. The in-situ gelation system consisted of HPAM as a polymer solution, trivalent chromium (Cr3+) as a crosslinker, and malonate ion as a delaying ligand. A unified viscosity model (UVM) developed by Delshad et al. (2008) that covers a full spectrum of Newtonian, shear-thinning, and shear-thickening behaviors was used to model the polymer rheology during polymer flooding and gel treatment and the results were compared with running the same scenarios assuming shear- thinning behavior only. Input parameters that relates the effects of salinity on both polymer viscosity and polymer adsorption were obtained. Finally, the effect of the presence of divalent cations such as Ca2+, Mg2+ in the reservoir brine were also investigated.
In this study, we demonstrated that using polymer solutions that have viscoelastic characteristic such as HPAM can indeed increase recovery more than shear-thinning behavior only, and more importantly was the effect of gel rheology on the gelation process of the gel system. Thus, oil recovery factor was always higher when considering UVM compared to shear-thinning behavior only. In addition, increasing the salinity of the injected water decreases the viscosity and increases the adsorption of polymer solution; therefore, the higher the brine salinity, the lower the recovery factor. A further enhancement of the recovery factor was achieved using low-salinity chase water flooding. This improvement was more noticeable when the initial salinity of the model was very high (i.e., 20,000 ppm). In addition, the effects of lowering chase water salinity were more pronounced with polymer flooding compared to gel treatment. Moreover, the treatments were less efficient when the hardness was high in the reservoir brine. Finally, low-salinity chase water flooding reverse the effect of the presence of divalent cations in the reservoir brine.
An Integrated Framework of Stress Inversion and Coupled Flow and Geomechanical Simulation for 4D Stress Mapping
Authors: Bubshait A. A. , Aminzadeh F. , Jha B. 
Published: April 2018

Abstract
A change in pore pressure due to production/injection causes changes in both the total stress and the effective stress in the reservoir. These stress changes, when projected onto a fault, may induce fault failure and seismicity depending on the fault rheology and friction parameters. A seismic event can be characterized by the moment tensor and the focal mechanism, which are related to the change in stress tensor causing the event. The objective of this paper is to use the theories of poroelasticity and stress inversion to develop a framework for mapping spatiotemporal changes in reservoir stresses caused by injection and production processes. We use a poro-elastoplastic simulation approach in CMG STARS to examine stress changes resulting from production in a reservoir with a normal fault. Production-induced increase in the von Mises stress and the effective mean compression cause plastic failure within the fault. We model the shear slip as a function of the plastic strain and compute the moment magnitudes of equivalent microseismic events. The focal mechanisms of these events are used in MSATSI, a MATLAB Package for Stress Inversion, to obtain the magnitudes and directions of three principal stresses. The stress inversion algorithm is modified to calibrate the principal stresses with the stress solution from the poro-elastoplastic simulator. We find that as production continues in the reservoir, the magnitudes and directions of stresses evolve in time. The result is a framework that provides a 4D (time-lapse) stress map of a reservoir while honoring both the production/injection and microseismic data.
Reservoir Geostatistical Estimation of Imprecise Information Using Fuzzy Kriging Approach
Authors: Zhao X. , Popa A. S. , Ershaghi I. , Aminzadeh F. , Li Y. , Cassidy S. D. 
Published: April 2018

Abstract
This paper presents a methodology for geostatistical estimation of reservoir properties to handle uncertainties in observation and modeling. Given certain known data in a geological region, the Kriging methodology is used to estimate or predict spatial phenomenon at non-sampled locations from the estimated random function. The approach assumes that the data is accurate and precise and the random function is generated from a thorough descriptive analysis of the known dataset. Regarding the assumptions considered in classic Kriging, it is realistic to assume that spatial data contains a certain amount of imprecision mostly due to measurement errors, and the information is lacking to properly assess a unique random function model. This paper presents a methodology for geostatistical estimation of reservoir properties to handle uncertainties in observation and modeling. Combination of regular or classic Kriging and Fuzzy Logic method is proposed. As such, imprecise variogram parameters are modeled based on Fuzzy Logic theory, while the predictions and variances are computed from Kriging analysis characterized by membership functions. Lastly, an optimization method is included to solve the constrained fuzzy non-linear equation system. The proposed methodology was implemented into a friendly integrated tool, which enables the user to create a preferred grid, conduct statistical analysis and run fuzzy kriging for various problems. The tool was validated using the SPE-10 porosity data. Additionally, a case study has been conducted using measured core permeability data in a heterogeneous reservoir to demonstrate the viability of the technology.
An Experimental Investigation of WAG Injection Performance under Near-Miscible Conditions in Carbonate Rock and Comparison with Sandstone
Authors: Alkhazmi Bashir , Farzaneh S. Amir , Sohrabi Mehran , Sisson Adam 
Published: April 2018

Abstract
In this study, the effect of rock type on two-phase and three-phase flow and displacements have been experimentally investigated as a part of a study on the performance of WAG injection in sandstone and carbonate rocks. A series of core flood experiments have been performed under reservoir conditions to investigate the effect of parameters pertinent to the performance of WAG injection. Clashach sandstone and Indiana limestone cores with almost similar porosity and permeability were selected for this work. To reduce the effects of experimental artifacts, large cores were used with diameter and length of 2 in × 2 ft respectively. To investigate the role of rock type, the WAG design parameters including injection order, injection strategy, and slug size were kept unchanged for the sandstone and carbonate rocks. Both core flood experiments were performed on water-wet cores and at near-miscible gas/oil IFT conditions.
Comparison of our core flood experiments reveal that even though the waterflood efficiency was higher in carbonate core than in sandstone rock, the overall oil recovery performance by the alternation of water and gas injections in the sandstone rock outperformed its trend in the carbonate core. Ultimate oil recovery values of 88.35 % (IOIP %) and 71.0 % (IOIP %) were obtained for the sandstone and the carbonate cores, respectively. The results show that about 39.12 % (IOIP %) and 12.37 % (IOIP %) of additional oil was recovered by the alternation of water and gas injection in the sandstone and carbonate cores, respectively. Comparing the average saturation profiles in the cores revealed that the higher trapped gas saturation in sandstone rock had significantly enhanced its oil recovery performance, during the tertiary water and gas injections, compared with that in the carbonate rock. The results also revealed the impact of rock type on pressure drop and fluid saturation distribution.
Geomechanical Impact on Gas Recovery from Marcellus Shale
Authors: El Sgher Mohamed , Aminian Kashy , Ameri Samuel 
Published: April 2018

Abstract
The production rate from unconventional reservoirs declines more rapidly than conventional reservoirs. The production from the reservoir result in an increases in the net stress due to reduction in the pore pressure while the overburden pressure remains constant. This leads to formation permeability reduction, both for the matrix and the fissures, as well as and conductivity impairment in hydraulic fracures due to proppant embedment. Information relative to the impact of stress (geomechanical) on matrix permeability and porosity, hydraulic fracture conductivity, fissure permeability were obtained from published studies. The effects of stress on the matrix, and fissure permeability, and propped fracture conductivity were then incorporated into the numerical reservoir simulator to predict production performance.
The objective of this study is to investigate the impact of the net stress changes on gas production from the horizontal wells with multiple hydraulic fractures completed in Marcellus Shale. A commercial reservoir simulator was used to develop the base model for Marcellus shale horizontal wells. The model incorporated various storage and production mechanisms inherent in shales, i.e., matrix, natural fracture, and gas adsorption as well as the hydraulic fracture properties. The core, log, completion, stimulation, and production data from wells located at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were utilized to generate the formation and completion properties for the model. MSEEL is a Marcellus Shale dedicated field laboratory and a research collaboration between West Virginia University, Ohio State University, The National Energy Technology Laboratory, and Northeast Natural Energy. Shale petrophysical properties at this site were determined by Precision laboratory equipment. These laboratory measurments provided the impact of net stress on core plug permeability and porosity. Furthermore, these experimental results were utilized to determine the the fissure closure stress. The relation between the propped fracture conductivity with the net stress were obtained from published studies on cores plugs collected from Marcellus shale. The production data from two horizontal wells at MSEEL site, were utilized for history matching with the model first by inluding geomechanical effects and then by exdcluding them. This approach allowed the impacts of stress-dependent matrix permeability, fissure permeability, and hydraulic fracture conductivity on the gas production to be evaluated. The base model was finally used to perform a number of parametric studies. The inclusion of geomechanical effects in the model improved the model predictions particularly at the early stages of the production. The results indicated that fissure permeability reduction due to stress, compared to reduction in matrix permeability and propped fracture conductivity, has more impact on gas production when the pressure in the vicinity of the well has declined.
Asphaltenes Contribution in Emulsion Formation During Solvent-Steam Processes
Authors: Ng A. , Ovalles C. , Benson I. P. , Hascakir B. 
Published: April 2018

Abstract
The objective of this paper is to enhance the produced oil quality during solvent-steam flooding processes by using asphaltenes precipitants and environmentally friendly solvents as injection fluid. This way, it is aimed to increase the asphaltene deposition tendency and decrease the emulsion formation severity.
Eight one-dimensional core flood experiments were conducted; one steam flooding, three solvent flooding, and four solvent-steam flooding. Five different solvents were tested; propane, n-hexane, toluene, Benzoyl peroxide (BP), and a plant-based environmentally friendly solvent (MS). Solvent and water injection, oil and water production, and temperature along the core flood were continuously measured during each experiment. Both produced oil and residual oil samples were further analyzed to investigate the quality of produced oil samples and the amount of asphaltenes deposited on spent rock. An ASTM method which uses n-pentane was implemented to separate asphaltenes from both produced and residual oil samples. The water content of produced and residual oil samples was determined through thermogravimetric analysis (TGA) and the water-in-oil emulsion content of produced oil samples was visualized with an optical microscope. To understand the impact of each SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions on produced oil quality during solvent-steam processes, every fraction was exposed to liquid or vapor water and examined under a microscope.
It has been observed that stability of asphaltenes and emulsions varies in the presence of vapor or liquid water. Aromatics and Resins fractions are the main contributors of water-in-oil emulsion formation, and emulsion formation is enhanced with the addition of asphaltenes. Vapor-water (steam) promotes the formation of more severe emulsions than liquid-water. Hence, the emulsion formation mechanism was predicted to start with a foam-formation step in where the vapor steam diffuses into the liquid crude before condensing to form liquid water droplets, and then, forming an emulsion at lower temperatures. Since asphaltenes insoluble solvents were used, diffusion of steam occurs mostly in deasphalted oil and mainly in aromatics and resins.
Impact of Thermal Maturation on Wave Velocity in the Bakken Shale
Authors: Kong L. , Ostadhassan M. O. , Sarout J. , Ling K. , Li C. , Wang H. 
Published: April 2018

Abstract
Thermal maturation not only affect the geochemical properties of Bakken shale but also impact the geomechanical properties of organic rich shale formations to some extent. In this study, kerogen was modeled as a function of thermal maturation based on differential effective medium theory. Four shale samples were collected and tested by X-ray diffraction(XRD) and Rock Eval to analyze the mineralogy and geochemical properties. Hudson’s model was used to simulate the acoustic properties of Bakken shale affected by the thermal maturity. The result shows an apparent trend between vitrinite reflectance (Ro) with compressional and shear wave velocity. As the Ro increases, the wave velocity decreases due to the kerogen maturation. Especially during certain interval, the decreasing is significant. This study proves caution should be taken when inverting the seismic or logging data to elastic properties of Bakken shale. As this is a theoretical model, more factors should be integrated to have a more accurate result in the future.