bluuebunny/crossref_metadata_2025 huggingface dataset:
Geophysical Monitoring of the Multilayer Reservoir with of Flooding and Induced Fractures Growth in the Injection Wells
Authors: Davletbaev A. , Zorin A. , Usmanov T. , Valiullin A. , Valiullin M. , Tikhonov I. , Fursov G. , Nazargalin E. , Slabetsky A. , Asalkhuzina G. , Ivaschenko D.
Published: October 2015

This paper considers the results of geophysical logging of multi-layer pumping wells with a bypass system of ESP units. Multi-layer production well testing with Y-tool assembly supports logging under commercial operation upon achievement of a steady-state flow regime.

Here, several formations within the field are being operated. Testing of flooding in a low permeability reservoir takes place when injection pressure is higher than the formation fracturing pressure of self-induced fracturing. Downhole logging in multi-layer wells with bypassing of ESP units is used to determine flooded formations where self-induced fracturing takes place. This approach is essential to plan activities to decrease water-cut in multi-layer production wells with injected liquid breakthroughs.

In the course of the study, certain field regions with considerable undrilled reserves were found in various formations. The risk of wellbores intersection with dynamically induced fractures in injection wells must be considered with regards to kick-offs of horizontal sidetracks and other well completions. This paper presents the results of numerical simulation using the reservoir model of a development element configuration with a long auto hydraulic fracture and several horizontal wells (HW) with multi-stage hydraulic fractures drilled perpendicular to a fracture in an injection well. Susceptibility to reservoir permeability, number of fractures in HW with multi-stage hydraulic fractures and a distance between fractures were analyzed.
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

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

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

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

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

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

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

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

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

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

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

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

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.
Two-Way Coupled Geomechanical Analysis of Naturally Fractured Oil Reservoir's Behavior Using Finite Element Method
Authors: Dubinya N. , Lukin S. , Chebyshev I.
Published: October 2015

In this paper to the coupled hydrodynamic and geomechanical simulation is presented. The physical poroelastic problem is mathematically interpreted and is solved within numerical simulation of fluid flow in reservoir and corresponding deformation processes. Special theoretical methods and their implementation in practice are presented for the problem of geomechanical and filtration processes occurring in the case of naturally fractured medium. The proposed algorithm is realized via special software created within the study. The process of developing a three-dimensional numerical dynamical geomechanical model of oil and gas field characterized by naturally fractured rocks is considered. Effect of mechanical parameters on the production rates is analyzed using a set of computational models, the appropriate sections of oil and gas field. The effect of changes in the pore pressure on the collector conductivity and ultimately on the characteristics of the production well is investigated.
Integrated Approach To Modeling Naturally Fractured Carbonate Reservoirs
Authors: Ardislamova D. , Salimgareeva E. , Gallyamova D.
Published: October 2015

The paper discusses the problematics of choosing the approach to modeling naturally fractured reservoirs. Relevancy of this study is connected not only with the increasing number of oil fields characterized by naturally fractured reservoirs which are being brought into development but also with the complexity and diversity of solutions for geological and hydrodynamic modeling of natural fracture networks.

Modeling of naturally fractured reservoirs presents a challenging task due high heterogeneity of their porosities and permeabilities. There is no such thing as a classical oil field with natural fractures as any such field is unique both in terms of its geology and reservoir engineering issues.

The integrated approach to modeling naturally fractured reservoirs is presented as a case study of R. Trebsa oil field. The approach is based on combining reservoir characterization studies at different scale of investigation. Conductive properties of natural fractures are analyzed with the help of rock mechanics. Pore pressure influence on conductive properties of the system is also discussed.

The results of the modeling revealed that the integrated approach gives a robust and reliable representation of the system under the study. Estimation of in-situ stress influence on conductive properties is a valuable analytical tool which should be used in the framework of this approach. Dynamic simulations of the system behavior based on the discreet model are found to be very sensitive to compressibility. Thus, this parameter needs to be adequately defined. It is also demonstrated that when pressure declines the fracture permeability may significantly reduce due to compressibility.

The results of the study pave the way to more efficient field depletion strategies for fractured reservoirs, optimization of well patterns and more realistic and robust reservoir flow simulations.
Operational Decision Making Reaching New Frontiers with Real-Time Downhole Telemetry in the Russia's Arctic
Authors: Tanygin I. A. , Sherstobitov A. V. , Barylnik S. A. , Abramochkin S. A. , Davidovskiy A. O. , Belov M. V. , Zhandin A. O.
Published: October 2015

This paper presents the first experience of using a system for transmitting downhole data to surface (a telemetry system) based on wireless acoustic signal transmission during drill-stem testing (DST) in four carbonate reservoirs penetrated by an exploration well on Dolginskoye field in the Pechora Sea. Because no fluid would be recovered at surface during well testing, the job sequence program was optimized so that a full set of geological data could be obtained for each carbonate reservoirs in one trip.

The purpose of a wireless acoustic telemetry system is to provide a communication link between downhole and surface equipment by means of acoustic signals passing through the well testing bottom-hole assembly (BHA) and enabling a two-way communication channel to be established so that bottomhole data can be received on surface in real time, and downhole equipment can be monitored and controlled. The system allows operators to adjust the well testing program based on bottomhole pressure data and to check whether sufficient amount of data has been collected for the well testing objectives to be achieved.

Using a wireless acoustic telemetry system during dynamic well testing has many advantages compared to conventional testing with no downhole telemetry: bottomhole data can be received during job execution, operators have opportunity to monitor and analyze testing data and rely on a full set of representative data received in real time to make decisions for optimizing the job sequence program. The paper emphasizes the significance of receiving average formation pressure data during DST operations as it clarifies geological framework of the intervals under investigation and makes it possible to compare them with pressure data obtained by wireline tools when testing reservoirs with low porosity and permeability. The paper demonstrates a testing procedure optimization process which resulted in saving time on one well up to 36 hours and on other two wells – up to 24 and 48 hours, respectively, where acid treatments were considered unnecessary.

For the first time, dynamic well testing were completed on the Russian Arctic shelf in four carbonate reservoirs without any fluid recovery on surface, under an optimized testing program. Considering a short navigation season, this technology is ideal for real-time bottomhole data transmission applications.
Estimation of Safe Operation Life of Oil and Gas Wells Based on Examination of Production Casing and Borehole Annulus
Authors: Abakumov A. A. , Abakumov A. A. , Semin E. E. , Bazhenov V. V. , Mukhamadiev R. S.
Published: October 2015

The technology of well integrity evaluation has been developed and tested. The technology is based on magnetic introscopy equipment developed jointly by TATNEFT and Introsco Ltd. Present paper focuses on results of well integrity evaluations and provides requirements to the scope of data required to evaluate well integrity and the sequence of operations. Paper demonstrates the possibility of implementing the technology of well integrity evaluation in planning of workover operations.
Triple-Barrier Thickness Scanning Using Through-Tubing Pulse-Magnetic Logging Tool
Authors: Ansari Arsalan A. , Libdi Ziad , Khan Naeem , Aslanyan Arthur , Aslanyan Irina , Volkov Maxim , Arbuzov Andrey , Achkeev Andrey , Shnaib Fathi , Makhiyanov Ruslan
Published: October 2015

Servicing oil and gas wells requires their integrity assessment both during operation and before abandonment. One of the main objectives in well integrity analysis is the location of metal losses in tubing and/or casing caused by corrosion, erosion or other types of pipe damage. The first three metal barriers (normally tubing, production casing and intermediate casing) are of the most interest to the industry. Dual string completions is an additional complication to through-tubing assessment of the second and third barriers.

Magnetic Imaging Defectoscope (MID) is an electromagnetic scanning tool that recor

ds magnetisation decays induced by high-power electromagnetic pulses. Metal pipe barriers contribute to magnetisation decays at different times depending on their diameters, which makes it possible to differentiate each of them and determine their individual thicknesses. Thickness determination requires the numerical finite-element modelling of each recorded magnetisation decay and iterative fitting of the properties and thickness of every metal barrier to the actual tool readings. A data array can store hundreds of thousands decays, and the data processing optimisation loop therefore requires parallel computing with multi-core processors to process data within a reasonable time frame. The MID hardware and interpretation algorithm have been tested on multiple laboratory stands simulating various downhole multi-barrier completions from 2–7/8″ up to 13 3/8″ pipes with artificial defects of various shapes and sizes ranging from 7 mm to 140 mm.

This paper presents laboratory results and three selected field cases demonstrating the application of Magnetic Imaging Defectoscopy (MID) in single-string and dual-string completions for thickness evaluation of three barriers independently by a memory through-tubing survey.

Well W-01 with metal losses found at the same depth in the second and third barriers, i.e. 9 5/8″ and 13 3/8″ casings Well W-02 with metal loss found in the second barrier, i.e. 9 5/8″ casing, in an interval containing two strings. This corrosion has been confirmed by a repeated MID survey after pulling out the completion Well W-03 with through-hole metal loss found in the second and third barriers, i.e. large-diameter 9 5/8″ and 13 3/8″ casings, through a 7″ liner. This through-hole corrosion has been confirmed independently by High-Precision Temperature Logging and Spectral Noise Logging

The above metal losses have been located by through-tubing memory surveys in offshore wells that were to be abandoned. The results of the MID surveys were then used to design environmentally safe abandonment procedures.
Development of Integrated Modeling Tools for Field with SWAG
Authors: Efimov D. V. , Shlychkov K. E. , Vinogradov P. V. , Sergeev E. I. , Zaynulin A. V. , Dobrin V. K. , Savichev V. I.
Published: October 2015

The paper presents a case study from integrated modeling (IM) of R. Trebs oil field. The field development project assumes SWAG technology as the main production strategy. The gas for injection is planned to be sourced from R. Trebs and the adjacent A. Titov oil fields. Both fields are remote and located at a considerable distance from the existing infrastructure. Thus apart from enhancing oil recovery SWAG will also solve the problem of efficient use of the available gas resources.

The introduction of SWAG technology involves a number of engineering and operational challenges which need to be solved for its successful implementation. One of such tasks is designing the process flow structure of interconnected surface facilities: from the gathering system and treatment facilities to the pressure maintenance system. In this case material flows become conjugated, i.e. production rates affect injection rates which in their turn control the flow behavior of fluids in a reservoir. The produced associated petroleum gas after getting separated at the Central Processing Facility (CPF) and treated to the specified conditions is pumped into the pressure maintenance system to the well pads where after mixing with water it is injected back into the reservoir as a water and gas mixture.

The results of the study on the field characteristics as well as both surface and subsurface aspects of its development plan dictate the need for an integrated model in this project. This implies clearly set objectives and tasks for such integrated approach as formulated within the scope of this work. The workflow for integrated modeling is also developed with definition of requirements to the functionality and selection of tools for the realization of such model. Special emphasis is placed on the analysis of the requirements to the accuracy of the calculations and their efficiency with an effort to compromise the two.

These distinguishing features of the project are reflected in the developed integrated model. The paper describes the approaches to calculating various elements in the analytical model. Some of these algorithms have been modified to improve the accuracy of the calculations. The solution to the problem of history matching or calibrating the analytical model against the actual data is also discussed.
Utilization of associated petroleum gas at oil production facilities located in remote area for the generation of heat, electricity and synthetic liquid fuel
Authors: Buslaev George , Voloshchuk Yury , Baitalow Felix , Pardemann Robert , Meyer Bernd
Published: October 2015

The goal of this contribution is the introduction of a multinational research project aimed to the development of a novel concept for the utilization of associated petroleum gas (APG) using small-scale facilities located in remote areas in the Russian North. This project is funded by the ERA.Net RUS Plus program focused on the enhancement of the collaboration between European Union and Russia in the R&D area. It involves research institutions and companies from Russia, Germany and Poland and will be started in September 2015. The key step of the mentioned APG utilization route is the Syngas-to-Fuel (STF) process for the conversion of syngas into high-quality gasoline. One of the main challenges will be the selection of an appropriate technology for the syngas formation from APG, which is optimal adapted to the specific composition of APG usually containing (besides methane) higher hydrocarbons, CO2, N2, noble gases, sulfur-containing impurities, etc. The Russian-German-Polish project will be focused on the development of a comprehensive model for the overall process chain, including syngas generation, gas treatment, generation of heat and electricity, liquid fuels synthesis. Based on this model, technically viable and economically beneficial process integration schemes have to be defined taking into account the available infrastructure and the severe boundary conditions of the Russian North. For instance, a compact process design is desirable in terms of the reduction of capital costs. The final result of the ERA.Net RUS Plus project will be a technical and economical assessment of the novel technology for the APG utilization in remote areas, which is able to satisfy the needs of Russian oil and gas companies.
Selecting a Development System for Offshore Coastal Gas-Condensate Fields
Authors: Romanov A. S. , Buchinsky S. V. , Yushkov A. Yu. , Glumov D. N. , Voikov G. G.
Published: October 2015

A case study of a gas-condensate field located on the northeastern shelf of Sakhalin Island demonstrates the possibility of development of condensate-containing gas reserves by drilling very long ERD wells (drilling from the shore). The development system described in the paper includes drilling well with upward orientation. Such design provides complete cleaning of a wellbore from fluids and solids accumulated over a long period of maintenance-free operation. The choice of a development system using horizontal wells is also associated with the geological structure of the field (massive type accumulation with a single gas-bearing contour is broken by tectonic faults into separate blocks with different hypsometric elevations). Under the technical, economical (drilling from platform and from land, the use of subsea production systems, ice gouging with hummocks), and environmental (presence of valuable fish species in water areas and permanent residence of indigenous peoples) limitations, the development of individual wells with vertical completions turned out to be unprofitable. For the first time for this type of accumulation located in a coastal zone, a unique method of monitoring the recovery of reserves within the cross-section, as well as movement of the gas-water contact without the use of monitoring and pressure observation wells was suggested.
An Approach for Artificial Lift Applicability Maps Construction
Authors: Khabibullin R. A. , Krasnov V. A.
Published: October 2015

Using software for engineering calculations in oil production is a common practice. Wide spread software packages often focused on solving specific tasks - downhole equipment design, well performance analysis etc. Multiple wells calculations using standard software can be tricky. Moreover, visualization for multiple calculations results even trickier task with standard software.

A convenient way for presenting the results of the multiple calculations is construction of applicability maps. This paper discuss artificial lift technologies applicability maps construction. Applicability maps become useful for choosing lifting technique or analyze efficiency of current lift method in comparison with alternatives. It allows performing sensitivity analysis based on two most affecting on technology applicability parameters. In addition, maps can show technology applicability ranges which can be overlapped with production or forecast data.

The paper proposes a simplified method for constructing artificial lift (AL) applicability maps. It discusses natural flow, ESP and gas lift. Methods allows building maps on the fly, taking into account the main AL limitations with respect to multiphase flow and PVT properties. Case studies for Western Siberia fields in with AL applicability maps analysis discussed.
Prospects of Development of Jet Pump's Well Operation Technology in Russia
Authors: Drozdov A. N. , Drozdov N. A.
Published: October 2015

Oil production with submersible jet pump's installations can successfully solve many problems of well's operation in the complicated conditions. However, this technology, unfortunately, is not widely used in Russia. The purpose of this work is the study and improving of the oil production technology with jet pumps, and developing of recommendations for its effective application.

The analysis of the field experience of implementation has shown that, despite the achievements, the effectiveness of the known systems of oil jet pumps production is currently low.

To solve this problem, various methods have been developed.

One is the well operation with jet pumps driven by electric submersible pump (ESP), located in the bore pit, which is also the storage capacity and phase separator. The use of ESP, which is located in the bore pit, can significantly improve the reliability of the hydraulic drive of jet pumps in compare to the power plunger pumps.

It is necessary to achieve the best balance between ESP energy cost and efficiency of jet pumps. To optimize the system of oil production and achieve the highest efficiency of the jet operation of wells were developed methods and programs of software equipment selection and analysis, combined in a single software product. It allows select the most energy-efficient equipment and design the best system for the jet operation well cluster using ESP as a power unit deflated in bore pit. The developed method of jet pump selection and the calculation of ESP mode allows make a choice of the most suitable equipment for the jet operation of wells, including the power unit with the ESP and to increase the efficiency of the entire system.

There is another method of the technology of development, research and operation of complicated wells with jet pumps driven by the mobile power pumping complex.

Designed and manufactured mobile automated power station equipped with instruments to measure downhole pressures and temperatures, the operating fluid consumption and the well production rates. The station has successfully passed bench tests. The algorithms incorporated in this automated control system allow correctly handle the field information and set the optimal conditions of use.

A new technology has been suggested to use surface jet pumps for pumping out gas from the annulus and directing it with water into the injection wells. This technology is designed to increase oil production by reducing the annulus pressure and enhance oil recovery by SWAG injection.
Vulnerability of Arctic Coastal Environments to Oil Spill Impacts (White Sea Case Study)
Authors: Zagretdinova Dilyara R.
Published: October 2015

The abstract describes one possible approach to complex account environmental factors to determine the sensitivity of shoreline bays of the White Sea to the oil spill, proposed integral index of the sensitivity of coastal areas, taking into account the relationship of geological and geomorphological structure of the coast, the physical processes that occur in contact with the oil on shore and the vulnerability of biota to oil spills. The results of the practical implementation of the proposed approach and revealed the most stable and the most sensitive areas of the coastline of the Kandalaksha and Onega Bay of the White Sea.

The integrated vulnerability index portion is determined by summing the two components:

Vulnerability index components of the biota, in turn, defined as the sum of the biomass component of the biota ranged in a certain season, a factor of vulnerability of the component from exposure to oil spill (the latter was determined by expert assessment). Index ESI (Environmental Sensitivity Index), NOAA experts proposed in 1976, ESI allows typify the coast on a scale of 1 to 10, with the assignment of the appropriate category of sensitivity determined by the conditions and the duration of conservation of natural oil, wind and wave loading the coast, its geomorphological features and technical complexity of the cleaning oil. An analysis of the satellite imagery SPOT-4 in the visible range obtained data on 700 km of the coast of Bay of the White Sea, allocated 67 segments, differentiated by the two above indices. In ArcGIS environment built four integrated maps showing the sensitivity of the coasts in winter, spring, autumn and summer seasons.

In the project tree consists of the following layers: topographic base scale of 1: 25,000, the layers of hydrography, hypsometry, map the seasonal distribution of biomass components of biota and integral sensitivity maps coasts to oil spills. The study suggests that the coast of the Kandalaksha and Onega Bay of the White Sea over a large area have a relatively high index of sensitivity, which leads to the need for development and improvement plans LC, recycling technologies of oil pollution (mainly Ecobiotechnologies), methods of remote sensing, as well as the creation and expansion of the network of marine and coastal protected areas.

The novelty of the work is as follows:

Accounting for different responses to oil the various components of the biota; The approach to determining the sensitivity regarding the two main elements of the environment - geological and geomorphological base and biota;

It is worth noting the need to introduce in the index makrofitotsenoticheskoy components as well as the automation of the updating of the database project ArcGIS for constant updating sensitivity maps coasts.