bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach To Clastic Rocks Pore-Scale Topology Reconstruction Based On Automatic Thin-Section Images and Ct Scans Analysis
Authors: Krutko Vladislav , Belozerov Boris , Budennyy Semyon , Sadikhov Emin , Kuzmina Olga , Orlov Denis , Muravleva Ekaterina , Koroteev Dmitri 
Published: September 2019

Abstract
A framework for porous media topology reconstruction from petrographic thin sections for clastic rocks is proposed. The framework is based on two sequential stages: segmentation of thin sections imagesinto grains, porous media, cement (with further mineralogical classification of segmented elements) and reconstructing a three-dimensional voxel model of rock at pore scale.
The framework exploits machine learning algorithms in order to segment2D thin section images, perform structural and mineralogical classification of grains, cement, pore space, and reconstruct 3D models of porous media. Segmentation of petrographic thin section images and mineral classification of the segmented objects are performed by the means of combination of image processing methods and Convolutional Neural Networks (CNNs). The 3D porous media reconstruction is done by means of the Generative Adversarial Networks (GANs) are applied to the segmented and classified 2D images of thin sections.
As the criteria of the reconstruction quality, the following metrics were numerically calculated and compared for original and reconstructed synthetic 3D models of porous rocks: Minkowski functionals (porosity, surface area, mean breadth, Euler characteristic) and absolute permeability. Absolute permeability was calculated using pore network model. The 3D reconstruction framework was tested on a set of thin sections and CT tomograms of the clastic samples from the Achimovskiy formation (Western Siberia). The results showed the validity of the goodness-of-fit metrics based on Minkowski functionals for reconstruction the topology of porous media. The combined usage of CNN and GAN allowed to create a robust 3D topology reconstruction framework. The calculated poroperm characteristics are correlated with laboratory measurements of porosity and permeability.
The developed algorithms of automatic feature extraction from petrographic thin sections and 3D reconstruction based on these features allow to achieve the following goals. First is the reduction of the amount of the routine work done by an expert during petrographic analysis. Second leads to the reduction of the number of expensive and time-consuming CT scannings required for each physical sample in order to perform further absolute and relative permeability calculations. The proposed method can bring the petrographic thin section and CT data analysis to a new level and significantly change traditional core experiments workflow in terms of speed, data integration and rock sample preparation.
Third Generation Production Logging Technologies Enhance Inflow Profiling in Deepwater Gulf of Mexico Reservoirs
Authors: Donovan Glenn , Kamath Sagar , Tanis Elizabeth , Abbassi Linda , Gysen Alain 
Published: September 2019

Abstract
This paper discusses the effectiveness of the third-generation (Gen3) Production Logging Tool (PLT) technology which incorporates the use of co-located digital sensors for simultaneous acquisition of flow data. Case studies are provided which demonstrate that this technology is a step-change in the application of digitalization to a down-hole sensor platform which provides the most accurate characterization of the flow condition at each depth surveyed. The resulting data allows for much improved processing which is also described. The probabilistic interpretive model used in the processing has been updated to incorporate this and future developments in PLT architecture.
Planning, execution, and analysis of data for the wells is described in detail. Due to the significantly shorter configuration of Gen3 tools, safety at the wellsite is enhanced by allowing for a much-simplified surface rig-up. One well was logged in surface readout (SRO) mode while data in the other two were recorded in the downhole tool's memory for retrieval at the surface at the end of operations. This flexibility in logging modes optimizes operations by addressing the needs of the operation teams.
Three Deepwater Gulf of Mexico producers logged with the Gen3 PLT are described. In each case, a clear path forward is provided for optimal management of the reservoirs through effective production management.
The first generation (Gen1) of PLT provided a single discrete measurement for each sensor along the tool assembly's length, resulting in long tool assemblies and measurements taken at different points along the flow path. This approach had several drawbacks: long toolstrings, point sensors only provided a measurement at a single point in the cross-section of the flow, and measurements were not acquired simultaneously at each depth logged. The second generation (Gen2) of PLT was an improvement as sensors were arranged as an array enabling multiple measurements to be made at a single depth but were still long and not all were optimally arranged to capture data in the path of flow. The Gen3 PLT is one-tenth the length of the Gen1 versions and roughly one-third of the shortest Gen2 tools. Digitization allows for direct measurement of flow conditions and rapid interpretation of results. In multi-phase flow and deviated wells, the co-location of sensors in a spatial geometry provides the optimal information with which to create a fully accurate picture of the downhole flow.
Engineers’ Dilemma: When to Use Soft String and Stiff String Torque and Drag Models
Authors: Zhang Yuan , Samuel Robello 
Published: September 2019

Abstract
The soft string and stiff string models are different string methods that have been used by the oil industry to calculate torque and drag for years. Opinions have often varied as to which model is better. This paper discusses the intrinsic difference between these two models and proposes a criterion for determining which method would deliver the most accurate results.
Although both the soft string and stiff string models are used for torque and drag calculation, the soft string model is calculated like a soft rope, without considering the influence of the hole size and radial clearance. On the other hand, the stiff string model considers the effect of stiffness, thereby accounting for the extra side contact force. In theory, the stiff string model is more accurate because more variables are considered. However, the field data is more inclined to match the soft string model as opposed to the stiff string model. In fact, many factors, including the stiffness of the string, the shape of the wellbore, and clearance, can influence the status of the string and the value of the contact side force on the string. The present stiff string model does not consider these factors, making it difficult to predict accurate results. This paper analyzes the physics statuses of the string under different scenarios in order to determine which model to apply.
Results demonstrate that borehole tortuosity and the shape of the wellbore can significantly change the status of the string. All factors are relative. A string with a large-size section can be very soft in a straight wellbore, which is fit for a soft string model. Likewise, a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is a better fit for a stiff string model. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered. Extensive simulations have been performed and are reviewed in this paper. Results confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. On the contrary, the stiff string model is more useful when the string is stronger, the wellbore is in a high curvature shape, and the clearance is lower. When to use the models depends on the bending shape of the string in the wellbore. Since neither model is equipped to handle all scenarios, combining the two methods provides better results.
A New Strategy for Developing Horizontal Well Inner Potential Based on Fiber Optic Distributed Acoustic Sensing Monitoring
Authors: Li Li , Luo Qiyuan , Xiong Qi 
Published: September 2019

Abstract
An optical fiber has been utilized to continuously acquire liquid production profiles in horizontal well in X oilfield. The results obtained from the dynamical monitoring system confirm the time-varying law of the physical property under the condition of high-water flooding, which can serve as the guidelines to explore the potential of remaining oil in high water-cut/high recovery factor oilfield.
Usually, the sound wave shows different propagation speeds in different medium, which is the basic principle of this test. Firstly, optical cable is used for sound wave detection and signal demodulation.Meanwhile, a series of other processes are applied to calculate the sound velocity of mixed medium; Then the volume velocity and holdup of mixed medium for each phase are determined.The measure of liquid-producing profile along the whole horizontal well has been realized in real time. Finally, numerical simulation model considering the time-varying physical properties is established based on the core flooding laboratory experiment. This result will provide guidelines for the exploration of remaining oil in the well.
The results obtained from optical fiber monitoring system during last two years show that 80% of the fluid produced from the 502-meter horizontal well is mainly contributed to the first 90-meter horizontal section. Experimental results of core flooding under excessive water flooding (2000 pore volume) indicate that the permeability is 1.4 times of the original. The results of numerical simulations considering the time-varying physical properties illustrate that there is still internal remaining oil along the horizontal well section. So, the strategy of exploiting potential oil is proposed using an accurate directional water plugging, which will decrease 10% water cut and obtain more recoverable reserves.
Based on the dynamical monitoring results of optical fiber, this paper innovatively provides the strategy of exploiting potential remaining oil in the horizontal wells, which can provide a valuable suggestion for offshore oilfield with high productivity at high water-cut stage.
Dual-Polymer Fracturing Fluids Provide Major Advantages Over Traditional Fluids
Authors: Almubarak Tariq 
Published: September 2019

Abstract
As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, have low permeability, and higher temperature. Unconventional shale formations utilize slickwater fracturing fluids due to the shale’s unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity.
Guar and its derivatives have a history of success in crosslinked hydraulic fracturing fluids. However, they require higher polymer loading to withstand higher temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, due to the high polymer loading, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.
The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lb/1,000 gal and at a volume ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. HP/HT rheometer was used to measure viscosity, storage modulus, and fluid breaking performance. HP/HT aging cell and HP/HT see-through cell were utilized for proppant settling. FTIR, Cryo-SEM and HP/HT rheometer were also utilized to understand the interaction.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300°F and 100 s-1. Results show that the dual polymer fracturing fluid can generate higher viscosity compared to the individual polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance at 20 lb/1,000 gal. The two polymers form an improved crosslinking network that enhances proppant carrying properties. It also demonstrates a clean and controlled break performance with an oxidizer.
Extensive experiments were pursued to evaluate the new dual polymer system for the first time. This system exhibits a positive interaction between polysaccharide and polyacrylamide families and generates excellent rheological properties. The major benefit of using a mixed polymer system is to reduce polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation and potentially lowers damage to the fracture face, proppant pack, and formation.
The Effectiveness of Thermal Gas Treatment on Bazenov Formation Using Numerical Simulation
Authors: Shakhmaev Artur 
Published: September 2019

Abstract
This paper presents a description of the technology for numerical simulation of thermal gas treatment on Bazhenov formation, taking into account features of Bazhenov formation and thermal gas treatment and assumptions of the simulator.
First of all it is required to determine the following parameters: voidness (porosity), permeability, fracturing, free oil (initial oil saturation), TOC (Total Organic Carbon). And also it is important to establish dependence of the parameters on temperature and pressure. Then, the process of thermal gas treatment can be conditionally divided into several stages: Effective production of light oil from drainable (permeable) zones (miscible displacement in front of the combustion front)Involvement of zones of reservoir containing kerogen during to heat treatment (pyrolysis reaction) and liberation of light oil and gaseous hydrocarbons from "locked" zones of reservoir.Involvement of the initially non-drainable (impermeable) zones of reservoir, named matrix (doesn’t mean the same as in dual porosity/permeability system). Especially these zones are the greatest interest among reservoir engineers because it can contain huge reserves of hydrocarbons.
As a result of the steps described above, a 2D model was created, a numerical realization of the key processes taking place during thermal gas treatment on Bazhenov formation was carried out. Further, the main zones characterizing the process were identified and a physical justification for the individual indicators was given. Calculations of variants involving the matrix in the drainage process were carried out.
The calculated technological effect over a 50-year period of thermal gas treatment on the model (involving the production from matrix) was about 50% of the additional oil production, relative to the thermal gas treatment variant without involvement of matrix.
According to the results of the work, an evaluation of the efficiency of wet combustion was carried out during thermal gas treatment. The results of the calculations clearly demonstrate the advantage of using wet combustion. It is as stimulation of production of reservoir oil, as of additional synthetic oil as a result of kerogen pyrolysis reaction.
Capillary Condensation in Shale: A Narrative Review
Authors: Barsotti Elizabeth 
Published: September 2019

Abstract
Shale reservoirs are estimated to account for approximately 10-30% of oil and gas worldwide, yet operators rarely produce more than 10% of the original hydrocarbons in place from them. These poor production numbers are a result of the assumption that the same pressure-volume-temperature (PVT) analysis procedures that are employed in conventional reservoirs are also applicable to shale and tight reservoirs. However, traditional PVT analysis does not account for the nanoporosity of the shale and, therefore, neglects the ability of nanopores to significantly alter the phase behavior of reservoir fluids. To quantify the effects of shale nanoporosity on the phase behavior of reservoir fluids, a novel gravimetric apparatus was developed. Unlike other gravimetric apparatuses in the literature, ours is compatible with both simple and complex experimental fluids and up to several hundred grams of unconsolidated or consolidated porous media at temperatures and pressures up to 232ᵒC and 5,000 psi, respectively. Furthermore, our apparatus does not require a buoyant force correction, which is one of the major shortcomings of most commercially available gravimetric apparatuses. These unique features allow us to study fluid phase behavior in shale and tight cores with high accuracy and efficiency. In the course of an exhaustive three-year research program, we have used this apparatus to measure the first capillary condensation isotherm for a fluid mixture with more than two components and discovered new phenomena of capillary condensed and supercritical fluids in the nanopores of shale rock and synthetic porous media. By reviewing the works produced over the course of this research, we are now able to answer longstanding questions as to when and how nanoconfinement-induced phase behavior occur in shale reservoirs and the implications that different types of phase behavior, including capillary condensation and nanoconfined supercriticality, have for oil and gas production.
Injection Scheme to Reduce Retention and Improve Economics of Polymer Enhanced Oil Recovery
Authors: Ferreira Vitor H. 
Published: September 2019

Abstract
Polymer enhanced oil recovery (EOR) has been successful in onshore and offshore reservoirs, and is especially promising for heavy oil or heterogeneous reservoirs. Polymer retention, mainly due to adsorption, results in the removal of polymer from the solution, leading to the formation of a polymer-free bank. Thus, determining the retention is a key factor in evaluating the feasibility of polymer flooding. This work investigates a method to reduce polymer adsorption and improve the economics of polymer EOR. This is done through laboratory experiments and reservoir simulation. The experimental investigations consisted of five dynamic retention core floodings in fresh and non-fresh high permeability sandstones. Five concentrations of a HPAM-AMPS in high salinity brine were tested. Two types of experiments were performed: fresh-adsorption, and re-adsorption. Injection of the polymer solution in porous media that had never been in contact with polymer composed the fresh-adsorption experiments. Differently, the re-adsorption experiments were performed in media that had been flushed with the same polymer previously. The experiments indicated a type IV isotherm for fresh-adsorption, while the re-adsorption isotherm was of type I. For a polymer concentration of 1250ppm, the fresh-adsorption was 166.7μg/g while the cumulative re-adsorption was 64.8μg/g. Therefore, reduction of ∼61% may be achieved by pre-flushing the medium with a low polymer concentration solution before the injection of the mobility control bank. Other properties of the polymeric system were measured in the core floodings to serve as inputs to the reservoir simulation model. The field-scale simulation studies evaluated the economic impact of the injection of a low concentration polymer slug to reduce polymer loss during EOR, such as observed in the re-adsorption experiments. The production strategy optimization was composed of eight steps, and targeted net present value (NPV) maximization. The case studied was a heavy oil offshore sandstone field, based on a benchmark. The strategy to reduce polymer retention represented a 4% increase in the final NPV over the conventional polymer flooding. Additionally, risk curve analysis demonstrated the advantage of this reduced-retention strategy over waterflooding and conventional polymer flooding. This work shows experimental evidence that polymer overall retention may be reduced through injection of a low polymer concentration bank prior to the mobility control one. Additionally, through numerical simulation and economic analysis, it indicates that the reduced retention allows for an economic advantage in polymer EOR, which may improve the feasibility of polymer flooding projects.
Characterization of Organic Pores within High-Maturation Shale Gas Reservoirs
Authors: Hardy Jay 
Published: September 2019

Abstract
Shale gas is a very important natural resource which can significantly affect the natural gas production of the world (e.g., in United States, Canada, and China). The organic matter within shale is the material that generates hydrocarbons, such as natural gas, under high thermal maturity. Throughout this process, a significant amount of pores within organic matter, called organic pore, are also generated, as the organic matter itself becomes a porous solid. These organic pores contribute significantly to the overall gas storage and flow of the reservoir as a whole. These organic pores are especially important to the process of gas adsorption and desorption within organic pores, which makes the storage and flow of shale gas very different from conventional reservoirs. The structure of organic pores, including pore volume, surface area, geometry, size distribution, etc., is significant to understanding their influence upon gas adsorption and desorption and gas flow. Thus, it is necessary to quantitatively analyze these organic pores; however, studies that quantitatively analyze organic pore structure in detail are rare. By better understanding characteristics and relationships of these pores through statistical analysis, it is possible to be able to ascertain more characteristics of the reservoir as a whole. Therefore, this research aims to develop the quantitative method to characterize pore structure and discuss the feature of pore structure of high-maturity shale samples from the Sichuan Basin.