bluuebunny/crossref_metadata_2025 huggingface dataset:
Peculiarities of Identification of Reservoir Fluids Properties of Two-Phase With Oil Rim and Gas Cap Deposits: From Sampling to Justification of the Parameters for Calculating Reserves and PVT Data for Hydrodynamic Simulation of Field Development
Authors: Promzelev Ivan , Brusilovsky Alexander , Kuporosov Dmitriy , Yushchenko Taras
Published: October 2018

Substantiation of the composition and properties of hydrocarbon (HC) reservoir fluids is one of the important stages in the calculation of reserves and has a significant impact on the results of field development planning and engineering. The article discusses the current methodological issues of identification of PVT properties of reservoir oil and free gas (gas cap) in a twophase deposits.

The first part of the article is devoted to the problem of obtaining representative samples of reservoir oil in two-phase deposits and describes the methodical approach allowing to reproduce properties of the formation oil which is in thermodynamic equilibrium with the existing gas cap. The identification procedure is based on the complex use of the results of laboratory and theoretical studies, the basis of which is the mathematical modeling of the phase behavior of multicomponent hydrocarbon systems. The results are illustrated by the example of reservoir oil from the West Siberia field. It is confirmed that in the case of partially degassed (unrepresentative) deep oil samples, the saturated hydrocarbon fluid can be restored by modeling the process, reverse degassing in reservoir conditions.

In the second part of the article, a scientific and methodological approach to the restoration of the composition and reproduction of the PVT properties of reservoir oil of two-phase deposit is proposed in the case of limited input information. On the basis of the identified composition of the reservoir oil, its thermodynamic model is created, which adequately reproduces the results of laboratory and field studies.

The composition of the gas cap is determined using the fundamental physical foundations of the phase equilibrium in multicomponent systems and free gas thermodynamic properties are estimated on the basis of PVT-modeling. PVT models of reservoir oil and gas-condensate mixture of the gas cap can be used in the design and monitoring of the development using modern hydrodynamic simulators based on both Black Oil and compositional models. The application of the method is illustrated by the example of a real deposit.

The suggested methodological approaches are recommended to be used in the estimation of reserves and design of fields development.
A Novel Multi-Well Interference Testing Model of a Fractured Horizontal Well and Vertical Wells
Authors: He Youwei , Cheng Shiqing , Qin Jiazheng , Tang Hewei , Chai Zhi , Wang Yang , Chen Zhiming , Yu Haiyang , Killough John
Published: October 2018

High water-cut has been observed for many multi-fractured horizontal wells (MFHWs) in China soon after waterflooding begins. Available well-testing models of single well ignored the effect of adjacent wells on the MFHW, and they are unable to evaluate whether MFHW (producer) and surrounding vertical wells (injectors) are in good pressure communication. To fill this gap, this work presents a multi-well interference testing (MWIT) model to consider the interference of injectors and further match the interference pressure data.

The MWIT model is established to investigate the effect of multiple injection wells on transient-pressure behavior of the MFHW. Due to the interferences from injectors, the pressure and pressure-derivative curves of MWIT move down beginning with the biradial flow regime for single MFHW model, and pseudo-radial flow (horizontal line with the value of 0.5 on pressure-derivative curve) disappears. Sensitivity analysis was conducted to discuss the effects of crucial parameters on the pressure response, including total injection rates, unequal injection rates of injectors, well spacing, injector distribution, number and production of hydraulic fractures. When total injection rates are lower than the production rate, the pressure derivative will eventually stabilize at 0.5*(1-Σ(qIncjD)) during the interference-flow regime on the log-log type curves. Since only the positive number can be shown in the log-log graph, semi-log curves are also developed to fully characterize the flow regimes of MWIT. A novel finding is that pressure derivative also ultimately behave as a horizontal line with the value of 0.5*(1-Σ(qIncjD)) when total injection rates are equal or higher than production rates on the semi-log curves. The total injection rates and well spacing between the MFHW and injectors have a significant effect on middle and late pressure behaviors, whereas the number and production of fractures mainly affects the pressure responses during early to middle period. Type curves indicate that the effect of surrounding injectors are significant and cannot be ignored, and the novel characteristics provide potential application of the MWIT model to estimate formation parameters. Case studies highlight the application of the proposed method in effectively matching the interference pressure data. Interference-testing analysis of the MWIT provides a better reservoir evaluation compared to single-well testing model.
Reservoir Development Aspects and Surface Facilities Design of Gas Condensate Fields with Oil Rims
Authors: Shelepov Konstantin , Struchkov Ivan , Poltoranin Vadim , Trusova Anna , Chashchin Mikhail , Kuzevanov Maxim , Buchinskiy Stanislav
Published: October 2018

The operation of gas condensate fields under natural recovery drive is accompanied by retrograde condensation in the well bottomhole zone, which inhibits the movement of hydrocarbons in this area. One of the main methods of maintaining reservoir pressure under these complications is the injection of dry gas into injection wells, which is limited by economic factors. The problem of the development of gas condensate fields with oil rims is that the traditional reservoir pressure maintenance system does not provide a high oil recovery factor. Thus, the effective production of hydrocarbons requires new technologies and technical means. The paper considers a complex strategy for the development of such reservoirs, based on integrated modeling and the use of smart-well solutions.

The paper presents PVT-analysis, special core analysis, geophysical studies and well test results. An integrated field model has been created that allows to identify effective technologies for the development of gas condensate formations and the oil rim, as well as to account for the operational capabilities of surface facilities, while maximizing hydrocarbon recovery. The assessment and recommendations for the long-term development of a gas condensate field with an oil rim are suggested.

Multivariate calculations are performed to assess the productivity of wells and reach the field's maximum potential. The proposed field development strategy involves optimization of the surface infrastructure and hydrocarbon transportation system.
Application of Well Tests for Naturally Fractured Reservoir's Analysis with Complex Void Structure
Authors: Akberova Aigul , Davletbaev Alfred , Chudinova Anastasiya , Efimov Dmitrii , Abdullin Rim , Urazov Ruslan , Nazargalin Eduard , Gizatullin Damir
Published: October 2018

The paper discusses the examples of field study by different well tests in a carbonate field with a reservoir having a complex void structure. For studying the properties of productive layers the researchers used pressure build-up tests with the use of drill stem testing (DST) in open hole, build-up tests after well completion, injection tests, steady flow tests, analysis of production/pressure with the use of downhole telemetric system, well interference testing. Having generalized of the obtained data, the authors have identified the limits of applicability, advantages and disadvantages of each method, as well as the matrix of well-testing methods for the considered carbonate reservoir was developed.
Automatic Well Log Analysis Across Priobskoe Field Using Machine Learning Methods
Authors: Belozerov Boris , Bukhanov Nikita , Egorov Dmitry , Zakirov Adel , Osmonalieva Oksana , Golitsyna Maria , Reshytko Alexander , Semenikhin Artyom , Shindin Evgeny , Lipets Vladimir
Published: October 2018

This paper is devoted to the testing of of automatic well logs interpretation testing, developed on the basis of machine learning methods.

The basis of the method presented in the paper is recurrent artificial neural networks. For their training and adjustment, log curves and their corresponding interpretation of different years are used. The set of well data is divided into training, validation and test samples. The resulting tool is set up on training and validation samples, and then used on a test sample of wells for which the interpretatoin was hidden, in order to automatically predict net pays and compare the results with the interpretation performed by an expert petrophysicist. For the test sample, traditional machine learning metrics metrics and special geological were calculated to assess the quality of the algorithm.

During the work a number of experiments were carried out, in which the dependence of the forecast quality was estimated not only on the different architecture and settings of the artificial neural network, but also on the amount of input data. The iterative approach in the research allowed to determine the best parameters for the solution of the task. For each well of the test set, a forecast of reservoir intervals distribution is made. The resulting interpretation shows high accuracy, both in terms of different mathematical metrics, and the results of analysis and evaluation of the expert petrophysics. Also, during the experiments, an important conclusion was made about the generalizing ability of the proposed methodology. The use of several variants of interpretation of well log data, performed by different specialists at different times and on the basis of different petrophysical models, allows to generalize and use all the accumulated experience of well logs interpretation, thereby improving the quality of the forecast. The main conclusion of the study can be considered a statement about the efficient applicability of machine learning algorithms for automatic well logs interpretation.
The Approach to Modeling and Optimization of Technological Regime of Complex System: Gas Condensate Field – LNG Plant
Authors: Pashinsky Alexey , Sullagaev Alexey , Epryntsev Anton , Yamov Andrey , Valiev Rinat
Published: October 2018

Nowadays many oil and gas companies demonstrate a great interest to technology of liquefying of natural gas (LNG). LNG technology is especially topical for gas and gascondensate fields of Yamal and Gydan Peninsulas located so remote from network of transfer pipelines.

The exploitation of the field, which provides the output to LNG plant, has its peculiarities in compare with traditional approaches. Development of new approaches to the LNG plant start-up optimization is among the foreground tasks today. Failure prediction and monitoring of operation on the field, providing the production to LNG plant, are inconceivable without dynamic multiphase flow simulator.

Main purpose of this work is failure prediction and optimization of South Tambey field operation in the period of start-up and ramp up, taking into consideration posible uncertaincies and risk estimation. In this article authors present the results of predictive computation of the field operation while start-up, and describe their optimization sugestions.

The concept of integrated modeling of the entire system "formation-well-pipeline system-inlet facilities" introduced in this paper could be used for the purpose of subsequent monitoring of operation regime.
Applicability Analysis of Optimization Algorithms for Oil Fields Development Control
Authors: Nuzhin Egor , Yaubatyrov Ramil , Kotezhekov Viktor , Babin Vladimir
Published: October 2018

The paper presents a comparative analysis of advanced numerical optimization algorithms for solving a specific problem of increasing the efficiency of the waterflooding in a mature field (Brownfield).

Via multivariate iterative calculations produced by the optimization algorithm, on the basis of the reservoir simulation model the optimal waterflooding strategy (optimal combination of well modes) is determined. This strategy maximizes the economics of the field which is expressed in the value of net present value (NPV). The optimization process in most practically significant cases is complicated by the following factors: large dimension of the solution space, high complexity of the optimized function and high computational cost of each reservoir simulation. As a result, for the allocated project time the final solution can strongly depend on the chosen optimization algorithm.

Comparison of the algorithms was based on the solution of the real Brownfield waterflooding optimization problem with more than 100 active wells. Relative improvements of the objective function, NPV, were compared with respect to the number of required reservoir simulations. As a result, the set of recommendations for choosing the most effective algorithm depending on the available project time was obtained. For the considered problem, algorithms that show high efficiency (relative increase of NPV by 4-6 times) using comparatively small optimization budget (the ratio between the number of reservoir simulations and the problem dimension varies from 1 to 5) were determined.
Method of Anisotropy Modeling and its Application to Hydrodynamic Simulation
Authors: Kolbikov Sergey , Kuznetsova Yana , Smirnov Artem
Published: October 2018

In the practice of hydrodynamic modeling the anisotropy parameter (the ratio of vertical permeability to horizontal – kv/kh) is usually determined by experts as a fixed value varying in the range of 0.1-0.01, for the formation or for the field as a whole, and it is specified in the adaptation process of the model to the development history. This approach is applicable and is successfully used for deposits characterized by low degree of lateral heterogeneity. However, at the present time, a significant number of deposits are in development, the productive layers of which were formed in continental and coastal-marine environment, and therefore are distinguished by a complex geological structure due to high lateral and vertical anisotropy. For such objects the use of the conventional approach with a fixed value of kv/kh leads to an incorrect consideration of the influence of the heterogeneity on effective vertical permeability. Thus, the necessity of an alternative method for constructing the kv/kh cube, recommended for use in the complex structure of reservoirs, is obvious.

The paper proposes a method for calculation the anisotropy parameter in 3D model cells intersected by wells as the multiplication result of the true anisotropy coefficient by the coefficient of pseudoanisotropy, which is modeled in the interwell space differentially for the facies zones by the method of cosimulation with NTG, reproducing the heterogeneity of the formation structure. The coefficient of true anisotropy is defined as the arithmetic average value from the results of core studies. The pseudoanisotropy coefficient characterizes the vertical heterogeneity of the formation within a single cell of a 3D grid. It is calculated for cells intersected by wells as a ratio of vertical permeability, which is the result of the geometric averaging of well log interpretation values, to lateral permeability, determined as the result of the arithmetic averaging [1]. For other cells of the 3D grid the anisotropy parameter is modeled by the method of cosimulation with NTG, which correlates with pseudoanisotropy coefficient.

The use of the proposed method for modeling of anisotropy cube in process of hydrodynamic calculations allows to take into account the influence of heterogeneity on the effective vertical permeability differentially for facies zones and sedimentological units within facies zones.
Numerical Simulation of Reservoir Salt Dissolution Using Fully Implicit Scheme Within Isothermal Compositional Model of Hydrocarbon Filtration
Authors: Bogachev Kirill , Milyutin Sergey , Nazarov Vladimir
Published: October 2018

The article addresses the problem of numerical simulation of the salty water properties after the dissolution of hard reservoir salt following water flooding. A new method is being proposed for the simulation of reservoir salt dissolution within the isothermal models of black oil and compositional model of hydrocarbon filtration, based on fully implicit numerical scheme.

As with water flooding of hydrocarbon fields the injected water and the reservoir water differ in salinity, there is a need to simulate mixing waters of different salinity since such key water properties as density and viscosity depend greatly on the concentration of the dissolved salt. An additional source of salinity in the water phase comes from the hard reservoir salt, its dissolution affecting not only water properties but also the overall reservoir characteristics such as porosity and absolute permeability due to the increased pore volume open to fluid filtration.

The newly proposed method for the simulation of reservoir salt dissolution draws significantly on the ideas formulated in paper [2]. For a more specific description of the change in the pore volume in the process of reservoir salt dissolution, the filtration scheme is amplified with the mass conservation equation for reservoir salt. Most hydrodynamic simulators modeling salty water properties rely on a numerical scheme with splitting where salt concentration at each new time step is found after solving a set of equations consisting of the components' mass conservation equation and the volume conservation equation, calculated for the salt concentration at the previous time step. By the virtue of the fact that water density depends greatly on the concentration of dissolved salt, using the splitting scheme results in the failure of the volume conservation equation following recomputation of salt concentration at the new time step. In this paper, the discretization of the filtration system and the reservoir salt mass conservation equation are proposed to be tackled with the fully implicit scheme devoid of the above drawback. Within numerical experiments with test models as well as actual reservoir models, the proposed fully implicit method of simulation of reservoir salt dissolution has proven its high stability and efficiency allowing computation with large time steps.

Not infrequently, in simulating salty water properties the effect of reservoir salt is being ignored despite its significant effect for the reservoir porosity and absolute permeability. In this paper, the newly proposed method adds importantly to the base model of salt water tracing, while its fully implicit realization allows for stability and high numerical efficiency in computation.
Determination of the Optimal Bottomhole Pressure in Order to Reduce the Removal of the Solid Phase in the Weakly Consolidated Reservoir
Authors: Chebyshev Igor , Shapovalova Alina , Zhigulskiy Svetlana , Lukin Sergey
Published: October 2018

The elaboration of weakly consolidated terrigenous collectors is accompanied by considerable removal of the solid particles. At one of the reservoirs of Western Siberia technique of evaluation and forecast of the volume of the removed solid particles on the basis of Finite-element modeling was tested.

Suggested way to evaluate the volume of the removed particles includes multiple stages. Reconstruction of the dynamic, static properties of the deformation and durability with taking into account the textural features of the rock samples. Construction of the 1D geomechanical models in target layer and exceeding coal-measures. Creation of three-dimensional model of mechanical qualities for realization of further calculations for the well which is included in contour of 3D-model. Finite-element modeling of the part of the trunk of the well in poroelastic arrangement for evaluation of plastic effects which are arising in collector - sandstone and non-collector – aleurolite, argillite with fruit her calculation of the volume of the removed solid particles.

It allows to determine the safest bottom hole pressure for the highest possible conservation of the stability of the well type "fishbone".
Experimental and Theoretical Study of Fracture Toughness Effect on Hydraulic Fracture's Geometry
Authors: Dubinya Nikita , Trimonova Mariia , Tyurin Alexander , Golovin Yuri , Zenchenko Evgeny , Samodurov Alexander , Turuntaev Sergey , Fokin Ilya
Published: October 2018

The article is devoted to mathematical and physical modeling of the process of hydraulic fracture initiation and propagation in the material with known physical-mechanical properties. Fracture toughness was the main focus of the research as it is a parameter characterizing the rock's ability to resist fracturing process. This parameter alongside with rock elastic properties and pumping conditions is one of the governing parameters while considering the fracture propagation in terms of mechanics of brittle fracture. The study is aimed at understanding the impact of fracture toughness on geometric properties of a fracture by means of numerical modeling of laboratory experiments of hydraulic fracture propagation in a model material. The strength properties including fracture toughness of the used model material have been studied using the indentation methods. The difference between experimentally observed and numerically calculated (keeping in mind the estimated strength properties) fracture geometry is studied in the paper and the possible reasons for this difference are discussed.
The Strategic and Tactical Value of Geomechanics for Drilling Operational Excellence of ERD Well in Uzen Field
Authors: Chettykbayeva Kamilla , Petrakov Yuriy , Sobolev Alexey , Tatur Olga , Zozulya Andrey , Kalinin Vadim , Miletsky Mikhail
Published: October 2018

The traditional considerations and guidelines regarding well planning were not applicable to the challenges that extended reach well #101 of the Uzen field have presented. On the one hand, the reservoir itself was shallow, highly heterogeneous and structurally complex. On the other hand, the well trajectory involved the long interval placed nearly parallel to the bedding of catastrophically unstable shales.

The importance of geomechanical study and mud weight optimization have become very clear after reaching TD of 295.3mm section. There were no signs of instability while drilling, however the pulling out of hole was impossible without rotation, the overpulls, torque and pressure spikes resulted in fracturing the well and circulation loss, the well conditions imposed the high risk of BHA LIH.

The mud was gradually weighted up from 1.15 sg to 1.40 sg according to geomechanical calculations performed in a short time. After having conditioned the mud and performed several circulation cycles the drilling string was safely extracted out of hole. Due to the highly unstable hole conditions, the decision was to sidetrack the new borehole.

The main adjustment of the new trajectory of well #101 was dropping as much as possible the inclination angle when drilling through shales, at the same time allowing the maximum distance to water-oil contact. The PDM was planned to be used in the interval with high dogleg while where extended intervals of well trajectory went subparallel to bedding, the RSS was preferred, as there was a high need for lower vibrations and better cleaning quality.

The morning meetings included the reports and discussion of all the involved parties: Volga Gas management, mud and drilling engineers, geomechanicists, mud loggers and geologists. The thorough inter-disciplinary analysis was performed before making any decision: routine (time and number of reaming after drilling the stand, tripping speeds, circulation timing and duration) and strategic (trajectory change, geostopping, place to perform sidetrack, completion optimization, etc) too. The holistic approach of risks’ assessment and the proactive management resulted in drilling success of the first horizontal well in the field (2480m MD, 717m TVDSS). It was drilled safely and efficiently, allowing to access the reserves, delay the onset of water production, accelerate time to reach planned production level, and increase cumulative production of oil. The success of the drilling performance was publicly acknowledged by Volga Gas.
Advanced Computer Modelling for Metal-to-Metal Seal in API Flanges
Authors: Patel Harshkumar , Hariharan Hari , Bailey Greg , Jung Gonghyun
Published: October 2018

API flanges maintain integrity through metal-to-metal seal between gasket and flange groove, where sealability depends on contact stresses through bolt makeup-load, tension, fluid-pressure, bending moment. Approaches like API-6AF2 have limitations. With increased deep-water operations, there is an urgent need to understand true sealability/leakage. This requires micro-scale examination of seal. Very few FEA in literature model surface conditions. The objective here has been to develop an analytical model to estimate contact stresses and leakage considering surface topography.

This work presents a novel approach for modelling sealability/leakage in metal-to-metal surfaces. It utilizes a contact-mechanics and a fluid-flow model. Deterministic multi-asperity contact-mechanics model provides quantitative estimation of gasket contact stresses, contact gap, and contact area. The leakage model uses contact gap information and correlates it with hydraulic permeability between gasket and groove surfaces and predicts leakage using fluid flow through porous media equations. User inputs are gasket surface topography, size, material properties, operating pressure, and fluid viscosity. The calculations are performed on a small surface domain and results are then scaled-up to obtain contact load/leakage for the entire flange/gasket.

Various types of artificially generated surfaces were considered in the model and a parametric study was conducted. Effects of surface finishing have been explained by visual representation of model outputs such as contact status, load distribution, and leakage path. It was observed that critical contact stress to achieve complete sealability is highly dependent on surface characteristics. For similar surface topography, leakage rates are primarily a function of surface RMS. For the same RMS, it is more difficult to seal a randomly rough surface than a patterned or uniform one. As expected, it is easier to seal a soft gasket than a harder one. Similarly, it becomes progressively difficult to seal larger flanges.

Parametric studies/analysis can help improve understanding of leakage. The models can be used to understand relative magnitude of challenges in sealing gases/liquids at true viscosities. With further refinement and experimental validation, the models could serve as a design tool that could greatly assist in selecting effective seal and improve well process safety. Further, the presented approach can also be applied to develop leakage models for other metal-to-metal seal applications such as tubular connections, expandables, etc.
Approaches and Instruments for Well Cost Estimation at PJSC Gazprom Neft
Authors: Tretiakov Sergei , Maksimov Yurii , Sobolev Alexey , Sozonenko Gennadii , Khomitskiy Aleksandr , Karachev Arkadiy , Kosolapov Roman
Published: October 2018

In this article is review an experience of PJSC "Gazprom neft" at well cost estimation, methodologies development and building IT instruments for well cost calculation. The process from sketch diagrams to IT realization is presented and this process includes concept phase, transformation of needs to requirements to IT products, methodologies development, development of IT alghoritms, prototyping and verification via testing tools and validation through approbation at production units of company. At the final there are some conclusions about using this alghoritms and tools and future plans.
Tensorial Permeability Obtained from Pore-Scale Simulations as a Proxy to Core Orientation in Non-Aligned Rock Material
Authors: Gerke Kirill , Karsanina Marina , Khomyak Aleksey , Darmaev Bator , Korost Dmitry
Published: October 2018

In order to parameterize hydrodynamic models and optimize hydrocarbon production one needs to obtain as detailed information on flow properties of reservoir rocks as possible. The most critical petrophysical properties such as permeability are obtained from core measurements. Such core samples are usually subdrilled from full-size core material along a number of different directions, which not necessarily coincide with the directions of the major fluid filtration. It is believed that the most accurate data is obtained if subdrilling occurs parallel or perpendicular to bedding within the full-size core material. In this work we calculate the permeability tensor based on pore-scale flow simulations within pore geometries of the carbonate sample obtained using X-ray microtomography imaging. This allowed us to obtain the full tensor and flow directions without any sample orientation knowledge. The technique is promising for any petrophysical studies, as it allows to obtain tensorial petrophysical properties, and can be especially useful in case the original orientation of the core material is not known. We found the simulated permeability tensor to be highly non-symmetrical, which is in agreement with other published results and can be explained by the boundary conditions used for simulations. Additional research is needed to elucidate the influence of boundary conditions on the simulated permeability tensor.
Application of the Combined Real-Time Petrophysical and Geosteering Model to Increase Drilling Efficiency
Authors: Koryabkin Vitaliy , Stishenko Sergei , Kolba Pavel , Tatur Olga
Published: October 2018

The complexity of the geological conditions in the places where the wells are currently drilled, as well as a set of tasks to be solved by teams of drilling experts and the challenges to radically increase the efficiency of operations under low oil prices – all these challenges require a comprehensive engineering approach to real-time support of well drilling.

Regarding development of complex high-risk projects with a high degree of uncertainty, an emphasis should be made on creating and using a unified integration platform for various disciplines involved in the drilling process and real-time interaction.

A single unified petrophysical & geosteering simulation environment will make it possible not only to solve the issue of increasing the efficiency and safety of well drilling, but also boost further improvement of the automatic on-line interpretation of log data for drilling horizontal wells.

The article provides basic steps to designing and building a combined model, real use cases, evaluations of implementation efficiency and possible ways of development the methods proposed.
Improvement in Cement Sealing Properties and Integrity Using Conductive Carbon Nano Materials: From Strength to Thickening Time
Authors: Ahmed Shawgi , Ezeakacha Chinedum Peter , Salehi Saeed
Published: October 2018

Cement sheaths are designed to protect the integrity of oil and gas wells by mitigating movement of formation fluids and leaks. A failure of the cement sheath can result in the loss of zonal isolation, which can lead to sustained casing pressure. Gas migration through a cement sheath in the annulus is one of the main challenges that compromises zonal isolation. Failure in cement-casing bonding and micro annulus creation are other huge issues that compromises wellbore integrity. Even though some past studies have shown the application of nanomaterials, very few have conducted full scale tests measuring the compressive strength, thickening time and gas transition time of these materials.

In this study, nanosynthetic graphite with designed expansive properties has been introduced to fresh cement slurry. The expansive properties of nanosynthetic graphite were achieved by controlling the preparation conditions. The material was made from synthetic graphite and has a surface area ranging from 325-375 m2/gram. Several tests including compressive strength, rheology, and thickening time were performed. An addition of only 0.5% nanosynthetic graphite with appropriate reactivity was sufficient to maintain expansion in the cement system, leading to an early compressive strength development. It has excellent thermal and electrical conductivity and can be used to design a cement system with short and long-term integrity. Rheology and thickening time tests confirmed its pumpability. Controlling the concentration of the additive is a promising method that can be used to mitigate gas migration in gas bearing and shallow gas formations.
Prospects for Using the Microbiological Method of Enhanced Oil Recovery
Authors: Bezverkhaya Elena , Trofimov Igor , Karepov Vladimir
Published: October 2018

Resume

The use of strains of bacteria that destroy aluminosilicates leads to a change in the molecular structure of rocks of a low permeable clay-containing oil-bearing layer. In processed samples, the reduction in silicon content makes up one to five and a half percent, aluminum totals up to twelve percent. A high intensity of biogenic leaching of silicates (including quartz) is noted during the destruction of silicate minerals by cultures of silicate bacteria, in comparison with the abiogenic process. Among the layered silicates and aluminosilicates, the most decomposable were aluminosilicates (clay minerals). The results of the research may be relevant for the development of clay containing oil-bearing formations in Western Siberia and Yakutia, for the restoration of the reservoir's filtration capacity after drilling on a clay basis, and geological and technological measures.
Methodology of Fibers Impact Calculation on Proppant Transport in Hydraulic Fracture
Authors: Badazhkov Dmitry , Plyashkevich Vladimir
Published: October 2018

The paper provides details of two experimental methods that were developed during the study and performance characterization of fiber-assisted stimulation services. The first method is focused on measuring the change in terminal settling velocities of proppant, which changes are caused by fiber material loading to fracturing fluid. The experimental approach allows us to calculate hindered-settling functions and to predict fiber-assisted proppant settling control for some type of fracturing fluids (linear gels). The second method is focused on analysis of thermal stability of degradable fibers. The thermal stability is estimated by direct fiber performance examination immediately after exposure of material to fluid media under specific conditions. A static proppant settling test was applied here as a criterion of the fiber additive's ability to perform. The key output of the fiber stability test is the critical time, which is the limit of material stability time under given conditions. Mathematical processing was based on degradation rate calculations for set temperatures and calculation of critical time at varied temperature as a sum of fixed time stability functions. Validation was done by repeating calculated varied step temperature conditions experimentally and comparing actual fiber stability versus calculated stability.

Based on the obtained experimental data, it was possible to develop an empirical model suitable for integration into hydraulic fracture simulator. As a result, there is reliable tool for estimation of commercial fiber performance in hydraulic fracturing jobs.
Results of the Integrated Analysis of Discovering Undeveloped Reservoirs on the Mature Fields and Future Perspectives
Authors: Bashirov Ayrat
Published: October 2018

This work presents the development of method that allows to discover undeveloped reservoirs on the mature fields. The method was tested on the field located on south side of the West-Kuban trough – the Abino-Ukrainskoe field. This field is characterized by complex geology and final stage of development.

The existing geological model of the field is much-simplified what makes it impossible to solve the problem of localization remaining reserves and planning of well interventions.

The proposed approach is a sequence of actions that is of a general nature, and includes a number of detailed studies based on three types of input information: logging data, core and seismic data.

In the course of the work, the geometrization of the developed highly productive objects (HPO), which are related to the Miocene complex, was done and the promising areas of the HPO were predicted.

Also, the work revises the geological structure of the field and demonstrates the prospects of the Eocene deposits of sediments.
Effects of CEOR Chemicals on Asphaltene Precipitation
Authors: Curren Morgan , Kaiser Anton , Adkins Stephanie , Qubian Ali , Al-Enezi Huda , Sana Heba , Al-Murayri Mohammed , Delshad Mojdeh
Published: October 2018

Enhanced oil recovery methods are appealing to increase oil recovery from reservoirs due to market pressures in times of lower oil price. Chemical enhanced oil recovery (cEOR) methods such as ASP involve the use of alkali, surfactant, and polymer, to create an ultralow interfacial tension (IFT) between microemulsion and oil phases. These chemicals have the potential to interact with asphaltenes in crude oil and may cause either a decrease or an increase in asphaltene deposition. This paper presents an investigation into the effects of ASP chemicals on asphaltene precipitation.

Crude oil, from a cEOR-nominated Kuwaiti reservoir, was analyzed with an ASP formulation that was determined through microemulsion phase behavior experiments. Crude oil, chemical components, and incompatible solvent were added together, and light transmission was measured over a 15-minute period to determine asphaltene precipitation over time.

A blank graph of the crude in incompatible solvent showed a light transmission increase of 36.2% over the test duration indicating asphaltene precipitation. If asphaltenes remain suspended in oil, light transmission remains low and stable from the beginning to the end of the test. Addition of asphaltene inhibitor (AI) to the crude oil prevented asphaltene flocculation which was evidenced by a maximum light transmission of 3.0%, an efficiency of 91.7% dispersability relative to the blank sample. With addition of the ASP formulation, light transmission increased which indicates interaction between (1) chemical species of the ASP formulation with asphaltenes or (2) the alkali in the chemical package altering the pH and causing more asphaltene precipitation from suspension in the crude. Maximum light transmission of oil dosed with the chemical additives is 41.3% which is a decrease in asphaltene inhibition efficiency of 14.1% relative to the blank. With the addition of AI to the crude containing the chemical additives, the maximum light transmission is 6.5% indicating an efficiency of 82% asphaltene dispersability. Results indicate a clear relationship between addition of ASP chemicals and asphaltene precipitation. Conditions will differ for other crude oils and cEOR formulations, but asphaltene scaling issues should be considered for cEOR projects.
Case Study of Artificial Lift Strategy Selection and Optimization for Unconventional Oil Wells in the Williston Basin
Authors: Escobar Patron Katherine , Zhang Kathy , Xu Tao , Lu Haidan , Cui Shihao
Published: October 2018

As a major unconventional resource play, the Williston basin contributes more than 10% of total U.S. crude oil production. Due to significant concerns about net present value and payback period, the process to select the optimum artificial lift method has always been a top priority for operators. In this case study, we investigate the potential artificial lift strategies for new wells in Williston basin. The objective is to propose an artificial lift strategy that handles the challenges associated with unconventional resources and that maximizes the asset value.

In this study, a novel workflow that replaces subjective decisions with objective analysis has been applied for the process of selecting the lifting strategy that will best achieve an operator's goal based on analysis of technical criteria and economic calculated results. An initial prescreening is performed to narrow down the number of applicable artificial lift systems that will meet the technical challenges of the well. Then, the selected artificial lift methods are evaluated combining a steady state flow simulator and a reservoir model to determine the well performance and response to each lift system. This response is integrated with an economic model to determine the net present value of the proposed strategy. Different strategies and sensitivities on key parameters as oil price, expected production, and water cut are performed to determine the optimum artificial lift approach. The ability to include future well performance based on a reservoir model helps in building a strong analysis that goes beyond current well conditions and includes the changes that occur to the reservoir during the production phase, such as pressure depletion and consequent production decline. Those changes drive the need to switch from one artificial lift system to another as conditions evolve. The workflow allows the user to determine the best time to start the selected artificial lift system and the appropriate transition time to a second artificial lift method.

For the Williston basin case study, only electric submersible pumps (ESP) and jet pumps (JP) can be implemented during the high-flow-rate period. As production declines, a transition to a lower-flow-rate method is required. Hydraulic rod pump systems are considered the most appropriate transition method because they make it possible to pump the required volumes from deep installations. A production forecast is combined with two different water cut scenarios to evaluate the impact on the economic results of the project.

The successful use of this workflow has proven its ability to analyze the life cycle of an unconventional well and establish a process for artificial lift selection. Furthermore, the current workflow is flexible enough to be extended to other fields with different input variables.
Modifying Proppant Surface with Nano-Roughness Coating to Enhance Fracture Conductivity
Authors: Shrey Shubhankar , Mokhtari Mehdi , Farmer Warren R.
Published: October 2018

Nano-Roughness coating reduces the fluid/solid interaction leading to super-hydrophobicity or the Lotus effect. The objective of this study is to determine how this phenomenon can be applied in petroleum production system to enhance fluid flow in propped fractures using nano-roughness coating on the surface of proppants. The permeability and the wettability of coated proppant packs are compared with non-coated packs to determine the reduction in friction or enhancement in fracture conductivity.

The simulation of flow in a proppant pack is done using sand packs of different permeabilities. The base case for the work is established using sandstone samples with various permeabilities. The sandstone samples include Gray-Berea with uncoated absolute permeability of 86 mD, Buff Berea with uncoated absolute permeability of 374 mD, Bentheimer sandstone with uncoated absolute permeability of 277 mD and Leopard sandstone with the uncoated absolute permeability of 803 mD. The sand packs used are 20/40 mesh with uncoated absolute permeability of 31 D, 40/60 mesh with uncoated absolute permeability of 22 D and 50/70 mesh with uncoated absolute permeability of 21 D. After measuring the absolute permeability, wettability (using contact angle method) and relative permeability, all the samples were coated and the properties were measured again.

The results show that the modification enhances fluid flow through pores. The surfaces for all the samples were altered from a hydrophilic to a hydrophobic surface. The contact angle between the fluid and samples was observed to be almost 90° with water and >60° for oil, after modification. This confirms modification of samples to partial-wetting state. An increase in absolute permeability is observed from 14.54% for Gray-Berea to 184% for Leopard sandstone. The increase in absolute permeability for sand packs is observed from, 23% for 20/40 mesh sand, to 5.28% for 50/70 mesh sand. It was observed that modification is more efficient for a sample with a higher permeability, but further studies are in process to relate the permeability enhancement to total surface area.

Since the production rate of tight sandstone and shale reservoirs is low, especially in liquid-rich reservoirs and significant amount of water is injected for reservoir stimulation, enhancement in fracture conductivity resulting from proppant surface modification can have a meaningful impact on the recovery of these reservoirs. This study uses experimental techniques to show the effectiveness of nano-roughness coating on the reduction of friction which can lead to enhancement in fracture conductivity.
Validation of the Generalized Scaling Curve Method for EUR Prediction in Fractured Shale Oil Wells
Authors: Saputra Wardana , Albinali Ali A.
Published: October 2018

The generalized scaling curve method (Patzek et al., 2017) was proposed as a solution to substitute the empirical decline curve analysis that may be inappropriate to fit the production of shale oil wells. As the method is derived from the physics-based model on fractured well geometry, it can match the rapid one over square root of time declines in early production and moderate exponential declines in boundary- dominated production, where the popular decline curve analysis struggles. The proposed method was believed to deliver the results that are comparable to numerical reservoir simulation with less time and data requirement.

In this paper, the generalized scaling curve method is validated using field data from Niobrara and Eagle Ford shales. The results are then compared to an analytical solution from an anomalous diffusion approach (Albinali et al., 2016) that has been successfully applied to the data. A synthetic reservoir simulation model is also created and run with the reservoir simulator GigaPOWERS. The simulated oil production rate is then adopted as the synthetic data to feed the generalized scaling curve input. Sensitivity analysis is conducted using the numerical model to investigate the role of porosity, permeability, gas oil ratio, initial reservoir pressure and hydraulic fracture spacing on affecting the scaling curve.

The results suggest that the generalized scaling curve is a robust practical approach that is somewhere in between decline curve analysis and numerical reservoir simulation and can be used to predict the EUR of shale oil wells. The method is shown to give similar results to the analytical and simulation solutions with predominantly requiring production data only as the favoured empirical decline curve analysis.