bluuebunny/crossref_metadata_2025_split huggingface dataset:
Relating Acoustic Anisotropy to Kerogen Content in Unconventional Formations - A Case Study in A Kerogen-Rich Unconventional Carbonate
Authors: Gordin Yair , Bradley Thomas , Rosenberg Yoav O. , Canning Anat , Hatzor Yossef H. , Vinegar Harold J. 
Published: September 2021

Abstract
The mechanical and petrophysical behavior of organic-rich carbonates (ORC) is affected significantly by burial diagenesis and the thermal maturation of their organic matter. Therefore, establishing Rock Physics (RP) relations and appropriate models can be valuable in delineating the spatial distribution of key rock properties such as the total organic carbon (TOC), porosity, water saturation, and thermal maturity in the petroleum system. These key rock properties are of most importance to evaluate during hydrocarbon exploration and production operations when establishing a detailed subsurface model is critical. High-resolution reservoir models are typically based on the inversion of seismic data to calculate the seismic layer properties such as P- and S-wave impedances (or velocities), density, Poisson's ratio, Vp/Vs ratio, etc. If velocity anisotropy data are also available, then another layer of data can be used as input for the subsurface model leading to a better understanding of the geological section. The challenge is to establish reliable geostatistical relations between these seismic layer measurements and petrophysical/geomechanical properties using well logs and laboratory measurements.
In this study, we developed RP models to predict the organic richness (TOC of 1-15 wt%), porosity (7-35 %), water saturation, and thermal maturity (Tmax of 420-435⁰C) of the organic-rich carbonate sections using well logs and laboratory core measurements derived from the Ness 5 well drilled in the Golan Basin (950-1350 m). The RP models are based primarily on the modified lower Hashin-Shtrikman bounds (MLHS) and Gassmann's fluid substitution equations. These organic-rich carbonate sections are unique in their relatively low burial diagenetic stage characterized by a wide range of porosity which decreases with depth, and thermal maturation which increases with depth (from immature up to the oil window). As confirmation of the method, the levels of organic content and maturity were confirmed using Rock-Eval pyrolysis data.
Following the RP analysis, horizontal (HTI) and vertical (VTI) S-wave velocity anisotropy were analyzed using cross-dipole shear well logs (based on Stoneley waves response). It was found that anisotropy, in addition to the RP analysis, can assist in delineating the organic-rich sections, microfractures, and changes in gas saturation due to thermal maturation. Specifically, increasing thermal maturation enhances VTI and azimuthal HTI S-wave velocity anisotropies, in the ductile and brittle sections, respectively. The observed relationships are quite robust based on the high-quality laboratory and log data. However, our conclusions may be limited to the early stages of maturation and burial diagenesis, as at higher maturation and diagenesis the changes in physical properties can vary significantly.
Novel Density-Based Autonomous Inflow Control Device Using Artificial Gravity
Authors: Greci Stephen , Fripp Michael , McChesney Ryan , El Mallawany Ibrahim 
Published: September 2021

Abstract
A new class of Autonomous Inflow Control Devices, AICDs, has been developed which balances production flow and restricts unwanted production fluids, even when there is no viscosity difference in the produced fluids. This novel AICD senses the density difference between oil and water and uses artificial gravity to amplify the buoyancy forces while eliminating the need for downhole orientation in the completion.
AICDs have effectively reduced water production and increased oil recovery since their introduction in the early 2010s. During initial production, AICDs balance the flow across the production zone. In later production, AICDs automatically restrict the rate from zones producing water. Commercially available AICDs primarily operate by sensing the viscosity difference between oil and water. In very-light oil reservoirs, such as in parts of the Middle East, there is no significant viscosity difference. Previous density-based AICDs have been rejected because buoyancy forces are often overwhelmed by fluid forces and because they needed to be oriented with respect to Earth's gravity.
Density-AICDs use floats that are buoyant in water and sink in oil to control fluid production. The key to the new density-AICD is that that the floats are housed in a spinning centrifugal rotor. This spinning density selector creates centripetal forces that multiply the buoyancy force thereby magnifying the difference between oil and water. The magnified buoyancy forces are stronger than fluid friction forces and are sufficient to overcome suction forces on the valve seats. The centripetal acceleration creates an artificial gravity that is much larger than Earth's gravity, eliminating the need to orient the density-AICD downhole. The density selector is spun by the production fluid so that larger centripetal forces are created in response to a larger drawdown. The result is a density-AICD that will operate in real-world conditions, especially in the light oil formations of the Middle East.
The performance of this novel density-AICD has been measured in flow loop testing and demonstrated in computer modeling. The flow loop testing achieved substantial water restriction and continued oil flow using oil and water with identical viscosities.
Modified Method of Characteristics for Generating EOR Oil Recovery Curves
Authors: Agger Christian , Sørensen Henrik 
Published: September 2021

Abstract
The paper describes a fast and approximate 1D simulation algorithm for calculating the percent recovery that can be obtained from an oil reservoir if gas injection is carried out at a pressure lower than the minimum miscibility pressure. The algorithm is based on the Method of Characteristics. While a conventional 1D reservoir simulation of a gas injection scenario may take minutes or even hours, the proposed algorithm allows a full evaluation of the recovery to be completed within seconds. To make the method numerically robust, a number of approximations were needed. The result is an extremely fast algorithm that not only provides a good estimate of the recovery obtained by gas injection, but also gives a good visualization of how the gas displaces the oil.
The Impact of Kerogen Structure on Shale Permeability: Coupled Molecular Diffusion and Geomechanical Behavior Study
Authors: Afagwu Clement Chekwube , Al-Afnan Saad Fahaid , Mahmoud Mohamed 
Published: September 2021

Abstract
The advancements in production technologies have unlocked tremendous reserves of natural gas in shale formations. The ability to describe shale matrix dynamics during the production span is, however, at infancy stages. The complex mineralogy and the multiscale nature of shales require transport models beyond the classical Darcian framework. Shales primarily consist of clays, quartz, calcite, and some fragments of organic matters known as kerogen. The latter can be envisioned as naturally occurring nanoporous media where diffusion is believed to be the predominant transport mechanism. Moreover, kerogen exhibits different geo-mechanical behavior than typical clastic sedimentary rocks. Hence, kerogen responds to changes in the stress field differently during the production span and ultimately influences the transport. It is our aim in this paper to delineate the transport and geo-mechanical aspects of kerogen through molecular-based assessments. Realistic kerogen structures at some ranges of density were recreated on a computational platform for thorough investigations. The structures were analyzed for porosity, pore size distribution, and mechanical properties such as bulk modulus, shear modulus, Young's modulus, and Poisson ratio. The adsorption alongside self-diffusion calculations were performed on the configurations. Moreover, the assessment of diffusivity was linked to pore compressibility to address the impact of effective stress changes on the transport throughout typical production span. An effective diffusion model for kerogen was proposed, validated with molecular simulation data in the literature, and compared with the MD diffusion data of this study. The results revealed critical dependency of pore size distribution, and porosity on the effective stress, which severely alters the diffusive permeability. This work provides a novel methodology for linking kerogen microscale intricacies to some fundamental transport and mechanical properties to better describe the transport of natural gas from kerogen.
First Complete Digital Drilling Package Deployment for Risks Reduction and Performance Optimization: Africa Offshore Case History
Authors: Ferrara Paolo , Mutidieri Luigi , Magni Gianluca , Farina Daniele , Dal Forno Luca , Ricci Maccarini Giorgio , Battaglia Francesco , Ricci Giovanni 
Published: September 2021

Abstract
In an era of reduced profit margin and high market uncertainty, more than ever it is important to meet operational excellence as a key factor for business sustainability. This is common to most technical applications, but it is particularly true for the drilling operations, where considerable investments and associated risks are involved. During last four years, as part of its digital transformation process, Eni has equipped itself with several digital tools for the diagnosis and the monitoring of drilling and completion operations. Goals and reached benefits can be summarized in risk reduction, operational efficiency and performance optimization.
Based on a wide case history started in 2019, a Digital Drilling Package was developed for operations support, from the design to the construction phase. Three main tools are now available to be applied to the most complex wells, either stand-alone or in parallel, covering drilling operations non-productive time (NPT) prediction, performance advanced analytics and real time simulations. This last simulation tool was deployed for the first time in late 2020 on some wells and is now being included in the engineering and operation workflows.
Attacking operational NPT and invisible lost time with the aim to increase safety and to reach the technical limit is not only a matter of processing tools. It requires a deep integration with headquarter (HQ), geographical units and field locations, with the definition of a strong data management infrastructure. This paper describes Eni's experience both on-site and in office, showing how the portability and integration of big data systems, suitable data lake architectures and human factor synergies can create effectiveness at all levels. An Africa Offshore field case history is reported to show how predictive and data analytics modelling and tools interact. In addition, the way in which these tools have been managed to support optimum decision-making processes is highlighted.
Next development steps will target an even higher level of integration of all available digital tools to have a single diagnostic approach based on univocal dashboards and in-house data server infrastructures.
Fluid Identification Derived from Non-Electric Measurements and Reservoir Characterization of Tight Carbonate in Sichuan Basin, China
Authors: Zhao Zuo AN , Wang Yue , Lai Qiang , Li Kai Xuan , Zhao Xian Ran , Wu Jin Long , Zhao Hai Peng , Yu Dai Guo 
Published: September 2021

Abstract
Natural gas production in the Sichuan Basin reached 30 billion m3 in 2020, but the gap between this and the production goal of 50 billion m3 in 2025 requires further exploration. The complex mineralogy and low porosity in tight carbonate reservoirs lower the accuracy of formation water saturation calculation from Archie's equation, which brings uncertainties to the reservoir characterization. It is, therefore, necessary to incorporate other methods as supplements to methods based on resistivities.
This paper outlines a method that incorporates wireline induced gamma spectroscopy, nuclear magnetic resonance (NMR), array dielectric, and borehole images. Spectroscopy is not only utilized to estimate the mineralogy of the reservoir, but it also provides non-electric measurements, such as chlorine concentration and thermal neutron capture cross-section (sigma). The amount of chlorine in the formation is proportional to the water volume in the reservoir, thus formation water saturation. Sigma is also an indicator of the formation water saturation. It enables formation water saturation calculation without resistivities.
Case studies are presented from carbonate reservoirs in the Sichuan Basin, China. A robust and comprehensive petrophysical description of mineralogy, porosity, pore geometry, free fluid volume, rock type, and formation water saturation is presented. Calculation of formation water saturation from chlorine and sigma proves to be successful in both water-based mud and oil-based mud environments. The depth of investigation (DOI) of chlorine from spectroscopy is about 8 to 10 in. for 90% of the signal. The various DOI of different measurements must be considered when performing the fluid identification. Bound fluid saturation could reach more than 50% in tight carbonate reservoirs. Formation water saturation is not the only factor that determines the fluid type. Free fluid saturation from NMR must be incorporated. Finally, a robust methodology integrating formation water saturation derived from dielectric and spectroscopy, and free fluid saturation derived from NMR shows great advantage in fluid identification in tight carbonate reservoirs.
This paper discusses a novel combination of wireline logging tools for the fluid identification of tight carbonate reservoir in Sichuan Basin. It lowers the uncertainty in the estimation of formation water saturation when application of resistivities is limited in oil-based mud environments. The gas zones identified by the new method have promising gas productions. The workflow can also be applied to other tight carbonate plays in China.
Advanced Reservoir Simulation: A Novel Robust Modelling of Nanoparticles for Improved Oil Recovery
Authors: Hendraningrat Luky , Majidaie Saeed , Ketchut Nor Idah , Skoreyko Fraser , MousaviMirkalaei Seyed Mousa 
Published: September 2021

Abstract
The potential of nanoparticles, which are classified as advanced fluid material, have been unlocked for improved oil recovery in recent years such as nanoparticles-assisted waterflood process. However, there is no existing commercial reservoir simulation software that could properly model phase behaviour and transport phenomena of nanoparticles. This paper focuses on the development of a novel robust advanced simulation algorithms for nanoparticles that incorporate all the main mechanisms that have been observed for interpreting and predicting performance.
The general algorithms were developed by incorporating important physico-chemical interactions that exist across nanoparticles along with the porous media and fluid: phase behaviour and flow characteristic of nanoparticles that includes aggregation, splitting and solid phase deposition. A new reaction stoichiometry was introduced to capture the aggregation process. The new algorithm was also incorporated to describe disproportionate permeability alteration and adsorption of nanoparticles, aqueous phase viscosities effect, interfacial tension reduction, and rock wettability alteration. Then, the model was tested and duly validated using several previously published experimental datasets that involved various types of nanoparticles, different chemical additives, hardness of water, wide range of water salinity and rock permeability and oil viscosity from ambient to reservoir temperature.
A novel advanced simulation tool has successfully been developed to model advanced fluid material, particularly nanoparticles for improved/enhanced oil recovery. The main scripting of physics and mechanisms of nanoparticle injection are accomplished in the model and have acceptable match with various type of nanoparticles, concentration, initial wettability, solvent, stabilizer, water hardness and temperature. Reasonable matching for all experimental published data were achieved for pressure and production data. Critical parameters have been observed and should be considered as important input for laboratory experimental design. Sensitivity studies have been conducted on critical parameters and reported in the paper as the most sensitive for obtaining the matches of both pressure and production data.
Observed matching parameters could be used as benchmarks for training and data validation. Prior to using in a 3D field-scale prediction in Malaysian oilfields, upscaling workflows must be established with critical parameters. For instance, some reaction rates at field-scale can be assumed to be instantaneous since the time scale for field-scale models is much larger than these reaction rates in the laboratory.
Quantitative Evaluation of Water Flooding in a Low Resistivity Heavy Oil Reservoir with NMR and Conventional Logs
Authors: Shi Xinlei , Zhang Jiansheng , Lu Yunlong , Han Zhilei , He Yifan 
Published: September 2021

Abstract
The classification of water flooding severity is crucial for planning reservoir production and improving the recovery ratio. In this paper, we study a siliciclastic heavy oil reservoir in Bohai Bay, with resistivity reading close to, or even lower than the wet zone (3~5Ω.m). In this environment, computing original reservoir Sw using Traditional hydrocarbon saturation equation is challenging. As a result, the displacement efficiency of a water drive cannot be accurately determined.
In order to properly evaluate displacement efficiency, we must estimate initial reservoir Sw (Swirr) and the modern day Sw. Sw can typically be estimated from NMR data with a proper T2 time cutoff. However, in heavy oil reservoirs, the relaxation times of oil and capillary bound water overlap, leading to an over-estimation of Sw. We propose to compensate for the heavy oil effect by adjusting the cutoff until NMR Sw matches the Sw from core Mercury Injection for Capillary Pressure (MICP). As oilfield development proceeds, water displaces some oil in the pore space. Since the injected water has higher salinity than reservoir water, formation resistivity (Rw) becomes lower. Based on the material balance theory, the variable multiple water injection material balance equation is established, and the equation set is established by combining the material balance equation with the Simandoux equation and the calculation formula of mixed water resistivity (Rwz). According to the rock electricity experiment under different salinity, the dynamic rock electricity parameters are used in the Simandoux equation, and the mixed water resistivity and modern day Sw after water flooding are solved iteratively under the original SW constraint. The displacement efficiency is calculated as the difference between Sw and modern day Sw.
The proposed method was applied to 10 wells and improved the Sw accuracy by 5%-15%. The continuous solution Rw from our method matches Rw measured in the lab. The calculated displacement efficiency is compared with actual production history and the accuracy improved from 68% to 80%.
How to Block the Water Channels by High-Density Polyethylene Particles Supersaturated Filling Out-of-Screen and Inflow Control Device in Heterogeneous Sandstone Reservoir
Authors: Shi Hongfu , Xu Zhongbo , Cai Hui , Zhang Wenjun , Li Yunting 
Published: September 2021

Abstract
At present, the Bohai Oilfield has entered the late stage of high water cut, with a high degree of flooding and an average water cut of more than 80%. Horizontal wells were widely used in tapping the potentials of high water-cut oilfields with avoiding local water flooding, accurately develop enrichment of remaining oil, and improving initial productivity. Until 2020, there are more than 1,200 horizontal wells in the Bohai Oilfield, with daily production accounting for more than 40% of the entire oilfield. However, mainly continental deposits, strong heterogeneity, heavy oil, relatively large mobility ratio, long-term water flooding, and large liquid production have resulted in the obvious dominant channels in the formation, intensified ineffective water circulation, and low oil recovery. The application of horizontal wells faces huge challenges due to the serious water flooding and the prevalence of thief zones.
Inflow Control Device (ICD) is becoming more and more prevalent in bottom water reservoirs as it can delay the water breakthrough and significantly improve the economic benefit of a project by producing more oil and less water. The strong microscopic heterogeneity along the horizontal water channeling outside the screen or water channeling along the annulus between the screen and ICD tubular is responsible for the short term even ineffective effect of conventional ICD. Based on the review of the conventional ICD application in the Q oilfield, a workflow is present to design and optimize hybrid ICD to increase the success probability of the validity period of water control.
Risk Reduction on the Western Siberia Prospect Using Stochastic Seismic Inversion and Geological Constraints
Authors: Khitrenko Anton , Fedotkin Sergey , Nazaryan Ayk , Zhigulskiy Svetlana , Emelyanov Pavel 
Published: September 2021

Abstract
Seismic data is a main source of information for lateral forecast of lithofacies. No one can deny that seismic data is a useful method to determinate structure of prospects. However, we have to accept to urgent need to implement steps that will make possible to predict distribution of lithofacies. In exploration, the prediction of lithology and fluid properties is a main goal. Popularity and comparative simplicity of inversion, made seismic inversion popular for reservoir characterization. Despite the benefits of method, inability to estimate uncertainty of models, stochastic seismic inversion was inveted. A stochastic seismic inversion combine relationship with varying lithofacies parameters and elastic properties using uncertainty of each data. Additional modification of stochastic seismic inversion is geological constraints allows to exclude not appropriate realization and obtain correct probability model of lithofacies.
Comparison of approaches and results on a real set provided from the Tyumen formation in Western Siberia allows to estimate advantages and disadvantages of modification stochastic Seismic inversion.