bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improvement of the well performance optimization methodology based on integrated modeling
Authors: Bikbulatov S. M. , Vorobyev D. S. , Smirnov A. Y. , Mukminiov I. R. , Romashkin S. V. 
Published: October 2015

Abstract
CJSC "Rospan International" developing the Achimov deposits on the two license areas. These reservoirs have the gas condensate saturation, low permeability at the level of 0.8-1.6 md, abnormally high formation pressure by a factor of ∼ 1.7 abnormalities. Reservoir Engineering conducted using large volume fracturing with proppant loading of 150-400 tonns.
Geological formations heterogeneity, nonsimultaneous entering wells and as a result, the uneven development of reservoirs necessitate of regulation of technological modes of operation wells. The task is to select the well operating mode, maximizes the production of liquid hydrocarbons at a constant level of gas production. The results presented in this paper, represent a further development of approaches to solving the problems previously described in two papers [1], [2].
The model is presented as a single complex network model collecting the two license areas and merged with reservoir model and the model of the GTU. The type of reservoir models as part of the integrated model is a matter of finding the most suitable to the conditions of the problem being solved tool and is considered in detail in the article. This paper describes the approaches to setting up model to the actual data, including the use of automated tools. The concept has been used to set up an equal uncertainty in the evidence. So, to build a table of pressure losses along the wellbore, the work carried out at the choice of a single correlation flow in the wellbore without the individual correction factors. It was chosen the single choke model, which does not provide for individual tuning coefficients of variation, as a way of setting pressure drop across the each well. It was justified choice of options in the calculation of temperature performance and thermal conductivity of selected wells.
As a result of the work is considered an upgraded integrated model, which allows to carry out work on the automated setup to the actual data and to optimize technological operating mode wells. The optimizer takes into account the dependence of the condensate-gas factor on the selected operating mode of the well, and can thus be used for the oil fields, where the limiting factor may be the high GOR and for gas condensate fields to improve the current condensate recovery. Developed in the course of the project methodology reduces uncertainty of the model set up procedure to the actual data and carry out optimization calculations for choosing the best wells operation mode.
Optimising Spacing of Horizontal Wells in Gas and Gas-Condensate Reservoirs
Authors: Abdul-Latif Benson Lamidi , Kwesi Dziwornu Christian , Ernest Adaze , Fahd King 
Published: October 2015

Abstract
An increase in the demand for gas in this current generation and the availability of several technologies including horizontal drilling technology has opened up the development of tight gas reservoirs throughout the globe. Efficiently draining the reservoir using hydraulic fracturing strongly depends on well spacing, especially for low permeability reservoirs. Most of the majority of work done by petroleum industries in the world especially in the Russian Federation to find the optimum well spacing is based on economic and technical considerations.
Key factors influencing performance of gas and gas condensate reservoirs include controllable and uncontrollable factors. Uncontrollable factors include porosity, water saturation, net-to-gross, initial pressure, permeability, natural fractures and fluid properties. The most relevant parameters among the controllable factors to consider for optimizing well spacing in gas and gas condensate wells are well design variations, well placement, surface facilities design, completion technologies and operating conditions which also include parameters such as the reservoir thickness, permeability anisotropy ratio, fracture conductivity, induced fractures and fracture half-lengths.
Due to the dearth of interference test data in gas wells and the inaccuracy of analytical solutions, numerical simulation is the most suitable approach for optimizing spacing in gas wells. In finding the optimum well spacing, several simulation runs are carried out for a real range of well and reservoir variables. The results are then tabulated and translated into a 15 and 45-year cumulative production as a function of well spacing, with the results indicating that lower permeability reservoirs require closer well spacing. In the case of a large number of long fractures, wells need to be placed further away from each to reduce well interference. This paper outlines the outcomes of optimization studies on well spacing in which both analytical and numerical tools were used in the presented workflow for several development scenarios in the gas and gas-condensate reservoir environments.
Interpretation of Non-Isothermal Testing Data based on the Numerical Simulation
Authors: Valiullin Rim , Ramazanov Ayrat , Khabirov Timur , Sadretdinov Alexander , Kotlyar Lev , Sidorova Mariya , Fedorov Vyacheslav , Salimgareeva Elmira 
Published: October 2015

Abstract
The goal of this paper is demonstration of an approach to enhancing reliability of quantitative interpretation of well tests data. The new approach comprises joint interpretation of transient temperature, pressure and flow rate data taking into account flow rate history before the test. It provides additional information about near-wellbore zone, flow profiles and hydrodynamic properties of a multilayer reservoir.
The transient model for solving the coupled thermal-hydraulic problems in the reservoir, formation, and wellbore is described in the paper. It takes into account heat convection and conduction, Joule-Thomson, adiabatic effects, thermal effect caused by degassing as well as mixing of fluids in the well, heat transfer between wellbore fluid and formation, frictional heat release and thermal effect of fluid compression or expansion. This model allows simulating flow behind casing, crossflows during shut-in and different properties of the near-wellbore zone.
Transient temperature and pressure fields, and temperature profiles along the wellbore are simulated for a given flow rate history. The model parameters are determined by solving the inverse problem based on a comparison of simulated temperature data with measurements in the wellbore.
Application of new approach to quantitative interpretation of well test data and developed transient numerical code are demonstrated on the example of field data from the Bashneft - Polus oil well. The data from production logging during flow at different choke sizes and transient station measurements of temperature and pressure after change of regimes are available and simulated with the developed code.
Standard Pressure Transient Analysis (PTA) was used for pressure and flow rate data interpretation, while available temperature measurements were simulated with a numerical code developed for solving the coupled thermal-hydraulic multiphase problems by Bashkir State University and Schlumberger Moscow Research center.
The paper demonstrates the results of quantitative interpretation of the field data and sensitivity study of the model parameters to uncertainties in measurements, flow rate history, thermal properties and other input data.
Formation Pressure While Drilling Technology Applied in Arctic Environment: Yamal Region Case Study
Authors: Ivashin Maxim , Truba Andrey , Zhernakov Vladimir , Gluschenko Mariya , Pavlov Valeriy , Korelskiy Evgeny , Weinheber Peter , Yakovlev Alexander , Makhmotov Akikat , Zadvornov Dmitriy , Kozlov Vsevolod , Glebov Evgeniy , Shokarev Ivan , Buldin Albert , Gulov Artur , Chimbulatov Feliks 
Published: October 2015

Abstract
Formation Pressure While Drilling tools were introduced to the industry several years ago (Pop, 2005). They have had widespread application and success especially in difficult offshore environemnts (Mishra, 2007) and very long horizontal sections (Larsen, 2008) but until recently they have been limited to high cost, deepwater environments. In many land environments Wireline Formation Tester (WFT) tools have often made more economic sense. In Russia FPWD tools have been run in the North Caspian and offshore Sakhalin both for drilling optimization (James, 2012) and for formation pressure guided well placement (Gupta, 2013) but had not ever been run on Land. In 2014, however a unique opportunity presented itself with very high angle wells drilled by Novatek in the field under Taz Bay. The wells being drilled had over 7000 m of vertical departure with deviation over 70 degrees. Additionally, since the field had been on production for some time, the wells were expected to encounter highly depleted sand layers. This implied highly unstable hole conditions and a significant risk of differential sticking. However, understanding the current reservoir pressure and therefore the amount of depletion was critical for managing the drilling hazards for this and future wells and for an accurate update of the hydrodynamic model. Given the risks associated with the hole instability a pipe-conveyed WFT was judged to be too risky and the FPWD tool was proposed.
In this paper we will divide our presentation of this operation into three areas: conveyance and operational considerations, pretest design and execution and data analysis and integration
Dielectric Permittivity Dispersion Measurements in Downhole Conditions – Effect on Porosity Measurements
Authors: Bondarenko A. , Dorovsky V. , Perepechko Yu. , Velker N. , Golikov N. 
Published: October 2015

Abstract
The dielectric dispersion of porous media saturated with water and oil is described by the Havriliak–Negami curve in the frequency range 10 kHz – 50 MHz with characteristic values of polarization parameters. Laboratory data show the relationship between porosity and polarization parameters. This relationship allows us to determine porosity of water-and-oil saturated formation under downhole conditions, using borehole dielectric logging methods. In this study, a possibility of using borehole electromagnetic (EM) inductive measurements for determining dispersion of complex dielectric permittivity of the formation, including the invaded zone was investigated. The influence of the inductive measurement error when finding formation porosity when determining polarization parameters of the frequency dependence of complex dielectric permittivity (the Havriliak–Negami spectrum) was studied.
For this study, a vertically oriented coil is placed in the well (along the borehole wall), creating a harmonic electromagnetic field. Several receivers that are aligned with the borehole axis measure this harmonic electromagnetic field. By using the magnetic field values on the well axis, we solve the inverse problem of determining complex dielectric permittivity of the formation, taking into account the invaded zone. Dielectric permittivity of the formation is calculated at different frequencies and is then used to restore the frequency dispersion curve, which enables us to find polarization parameters for the Havriliak-Negami polarization curve, taking into account the measurement error. Subsequently, these parameters can be used to find formation porosity. The proposed method of finding porosity uses inductive logging technology and is an alternative to the method based on the mixing formulae.
Lower Cretaceous Aptian-Albian formations - new exploration play in Shaim region
Authors: Akhmetzyanov R. , Sazonenko D. , Makarova A. , Ismagilov R. , Seryakova M. , Goitia V. , Ravilov M. , Evdokimova E. 
Published: October 2015

Abstract
Lower Cretaceous Leushinskaya (LSH) and Vikulovo (VK) formations have recently tested oil and gas for the first time in the Shaim Region located in the western border of West Siberian Basin (WSB). Before that, these formations were known as hydrocarbon reservoirs only in Krasnoleninskoye region (Kamennoye field) where they produce oil from VK sandstones and siltstones. The presence of commercial gas accumulation in the Cretaceous section in this part of the basin is also new, as no gas fields had been discovered before 2013.
The aim of this paper is to present the evaluation of a new play and new reservoirs for this region in the Vikulovksaya and Leushinskaya formations. The main studies and their results are shown.
The evaluation comprises the following works: –2 D seismic interpretation, including the identification and evaluation of "bright spots"–Core analysis – lithological description and sedimentological study, which was used later for correlation verification; petrophysical analysis – routine and special.–Wire line log interpretation of exploration wells, which was challenging due to lithology of the formations.
As a result of those works, Ourinskouye field was discovered in 2013. Two oil and gas deposits were defined and evaluated within Leushinskaya and Vikulovskaya formations.
Based on 2D interpretation and core sedimentological analysis gross depositional environments were defined.
As a result of wire line log evaluation – main parameters for in place volumetric calculations were acquired.
According to the Minprirodi report, Ourinskoye field is the largest discovery in two years in West Siberia basin.
Features of Tyumen Formation facial structures according to the spectral decomposition
Authors: Butorin A. V. , Zinnurova R. R. 
Published: October 2015

Abstract
According to most researchers of the West Siberian basin, in Tyumen Suite contains significant oil deposites not involved in the development, due, primarily, their complex facial structure. The task of reconstruction of depositional environment and mapping of prospective paleochannels is possible with the involvement of 3D seismic data. However, to solve such tasks require high-tech non-standard approaches to the analysis of the wave field.
The article shows study of the facial structure of the Tyumen Suite of fields in the Noyabrsk region of the West Siberian basin. To solve this problem we use a relatively new method of analysis of seismic data - spectral decomposition. The study can be divided into two parts: theoretical and practical.
In the theoretical part discussed the applicability of the method of spectral decomposition. The necessity of this stage is associated with the relative novelty of the technique used, which leads to insufficient understanding of the observed anomalies and the impossibility of their correct interpretation. The practical part is the result of extrapolation of the theoretical research to problem of mapping of prospective areas of the Tyumen Suite.
Application of spectral decomposition has allowed mapping in the study area complex network of paleochannels developing in the west-east direction, the efficiency of which is confirmed by several deep wells. The presence of such facies scheme allows to evaluate the potential site for the development of the Tyumen deposits, and to identify key areas for further exploration drilling.
Specifity and Practical Effect of Geological Modeling of Coastal-Marine Deposits
Authors: Afanasev O. , Konoplev A. , Nugaeva A. , Zianberdin R. 
Published: October 2015

Abstract
A number of Bashkirian oil fields belong to the terrigenous Devon formations of shoreface origin.
Such deposits are characterized by elongated geological bodies of different genesis (shoreface bares, channels and deltas).
The use of traditional, like stochastic and deterministic methods, not allowed to reproduce the above features in full and, in some case, to reproduce in hydrodynamic model movement of water flood from injectors to the centre of field.
An original technique of geologic modeling was introduced and implemented on Shkapovskoe field.
Applied Uncertainty Analysis to Mitigate Subsurface Risks at Planning and Implementation Stages of the UV1 Sidetrack Drilling Campaign for One of the Fields in Western Siberia
Authors: Semenov A. A. , Ishmuratov I. F. 
Published: October 2015

Abstract
This work focuses on an implementation of a procedure for assessing uncertainties using a reservoir model and subsequent sidetrack drilling program optimization for one of the fields in Western Siberia. We investigated the uncertainties of porosity and permeability models, net thickness, initial and residual water saturations, OWC level, PVT properties of oil, relative phase permeabilities, pore volume compressibility, aquifer parameters, vertical permeability anisotropy as well as hydraulic fracture height and minimum nonconductive thickness of otherwise impermeable layers. The performed sensitivity analysis showed that the uncertainty of the production profile is significantly influenced only by permeability, aquifer parameters, vertical permeability anisotropy and threshold conductivity thickness. An ensemble of reservoir model realizations was created for uncertainty estimation, which takes into account both the production history and the initial geological and geophysical data. The analysis using the technology of proxy models revealed that all realizations matching the production history can be divided into two clusters: with the prevalence of lateral and vertical fluid flow tendency. One realization from each cluster was taken for further investigation.
Optimal length and reservoir entry points were determined as a result of the joint analysis of remaining volume of oil reserves for both sidetrack realizations. Using automated optimization procedure for each realization separately we determined the optimal number of sidetracks, their lateral location and position of the sidetrack relative to formation top. Sidetracks which gave a positive forecast for both realizations were then chosen for drilling. The resulting drilling program consisted of two primary, one dependent and three sidetracks with high risks.
This work presents the results of practical application of uncertainty assessment methodology and successful implementation of sidetrack drilling program for UV1 (Jurassic period deposits) formation of the Varingskoe oil field in Western Siberia. In total, five oil flowing horizontal sidetracks were drilled. According to the data obtained during the drilling program implementation stage it was concluded that lateral fluid flow is dominating during production (i.e. impermeable layers were indeed good flow barriers and hydraulic fracture length proved to be insufficient for significant vertical fluid flow away from producing wells).
Pay Zone Distribution of CSR Field using the Climate Stratigraphic Approach
Authors: Yalalova Venera , Volnov Ignatiy , Ermilov Andrey 
Published: October 2015

Abstract
The CSR field is one of the largest gas condensate field located in the Amu-Darya petroleum province. The studied basin situated in the central and eastern parts of Turkmenistan, western part of Uzbekistan, and in the north of Afghanistan and Iran. The main target is Callovian Oxford-carbonate deposits characterized by high heterogeneity and this fact greatly complicates the prediction of reservoir rocks distribution.
The object of the study is to improve the methods of constructing a geological model of the CSR field based on the climate stratigraphic method and development of recommendations for gas stimulation depending on the lithofacies features of productive deposits.
In order to achieve the intended purpose the following tasks were discussed: Studying the sedimentation patterns in the Callovian-Oxfordian basin in the north-western part of the Chardjou tectonic stage;Core analysis and lithofacies/petrotypes identification;Well correlation based on the climate stratigraphic method;Reservoir properties analysis of identified lithofacies, evaluation of their productivity;Production logging (PLT) analysis;Areal distribution prediction of various lithofacies/petrotypes.
The research methodology is based on a climate stratigraphic approach which enables the calculation of the gamma ray and gamma-spectrometry spectral trends sensitive to the conditions of sedimentation.
The deposition model of the Upper Jurassic productive deposits of the CSR field constructed according only to lithological and facies core analysis is lack of credibility due to the small amount of core material. The reliability increasing can be achieved through the use of the climate stratigraphic method in order to improve the understanding of the depositional environment in which pay zones were deposited as well as to predict the composition of the sediment facies.
This work has allowed the prediction of the areal distribution of pay zones and significantly improves the accuracy of geological and simulation models that are the basis of efficiency for geological exploration and field development.
Modeling of PVT-Properties of Natural Gas Condensate Mixtures Adjusted for Presence of Residual Water in Collector
Authors: Yushchenko T. S. , Brusilovsky A. I. 
Published: October 2015

Abstract
The article is considering a recent mathematical method of phase equilibria calculation of natural gas condensate systems taking into account the presence of brine in reservoir media. This method is based on a three-parameter Peng - Robinson cubic equation of state and Huron - Vidal mixing rule.
The applicability of the PVT-modeling method is illustrated by comparison of the calculation results and experimental data by the examples of binary mixtures of water with methane, ethane, propane, n-butane, nitrogen, carbon dioxide and hydrogen sulfide. The new values of Huron - Vidal mixing rule parameters are proposed, allowing to improve the accuracy of phase equilibria calculation for binary mixtures of natural gas condensate systems component and water in a wide range of pressure and temperature.
A comparison of the results of engineering formulas (Bukacek method) based and a mathematical method (equation of state and Huron – Vidal mixing rule) based calculations of hydrocarbon mixture water content was made.
The effect of the residual water presence on the gas condensate system phase behavior at reservoir development is evaluated on the base of constant volume depletion (CVD) test mathematical modeling with the application of the discussed method of phase equilibria calculation.
Examples of residual water presence effect on the PVT-properties of natural gas condensate systems distinguished by initial reservoir conditions, potential content of stable condensate (C5+) and composition are considered.
Mechanism of Oil Displacement During WAG in Porous Media with Micro-Inhomogeneities
Authors: Shandrygin A. , Shelepov V. , Ramazanov R. , Andrianov N. , Klemin D. , Nadeev A. , Yakimchuk I. 
Published: October 2015

Abstract
The dynamics of oil displacement using water and gas mixtures in porous media is studied using digital rock analysis. The technology includes scanning of core samples using X-Ray micro tomography, creating of digital models for the samples, and running hydrodynamic modeling on pore scale using the density functional approach. The results include visual snapshots of phase distributions on pore scale for various time instants of oil displacement by water and water-gas mixtures. Due to WAG the displacement coefficient was increased by 5% to 10.5% for water-wet samples and by 20-21% for oil-wet samples. This effect was explained by analyzing the dynamics of oil displacement on a pore scale. The simulations also allow studying the dependency of the displacement coefficient on WAG regimes for water-wet and oil-wet media.