bluuebunny/crossref_metadata_2025_split huggingface dataset:
Heat and Mass Transfer Processes Caused by Natural Thermal Convection in Oil-Containing Media
Authors: Kuneevsky V. V. , Osnos V. B. , Vankov Yu. V. , Larionov V. M. , Saifullin E. R. 
Published: October 2017

Abstract
This article presents the results of experimental modeling of heat and mass transfer processes in oil-containing media caused by natural thermal convection. In this research we designed the laboratory setup and obtained experimental data for single- and two-component liquids medium with different permeability. It was shown that the dynamic of the media heating and the value of the oil recovery coefficient obtained experimentally and numerically by using the CMG STARS program coincides well. It was found that the processes of heat and mass transfer occur most intensively when the temperature of the medium near the heater reaches the value equals to the boiling point of water. The heating of the zone around the heater occurs faster, if a medium has a lower permeability. The oil recovery coefficient reached 55% with an initial water saturation coefficient of 0.52 and other conditions which corresponded to Ashalchinskoye oil field, Republic of Tatarstan, Russian Federation. This result is in a good agreement with the numerical result calculated by the CMG STARS program.
Experimental Research of Simultaneous Water and Gas Injection Technology into Injection Wells using Mixing Devices
Authors: Sergeev E. , Vinogradov P. , Abutalipov U. , Ivanov A. , Kitabov A. , Esipov P. 
Published: October 2017

Abstract
The main task of this work was a comprehensive test of the technology of simultaneous injection of water and gas into injection wells to confirm the feasibility of this method of maintaining reservoir pressure (MRP), approbation of technical and technological solutions, taking into account further scaling and application of this type of injection at fields PJS OC Bashneft.
To study the process of simultaneous injection, an experimental test site was designed and implemented on the basis of one of the company's fields. The main elements of the technological scheme are: a fresh water pipeline, a pier with an electric centrifugal pump (ECP), a high-pressure gas pipeline that supplies associated petroleum gas (APG) from the compressor station (CS), and a mixing device that allows a fine dispersion mixture to be produced at its outlet. Regulation of the injection processes was carried out by control valves, which are installed on both lines. During the tests, the technology of the process of continuous simultaneous injection of water and gas into injection wells with a different percentage of these components was tested. On the basis of modeling, technical solutions for the preparation of a water-gas mixture with a fine-dispersed structure were developed, implemented and tested. Conditions and parameters of injection for obtaining a homogeneous fine-dispersed water-gas mixture (WGM) are determined. The behavior of the injection well in the implementation of various operating modes and with different structure of the water-gas mixture is analyzed. The main risks in the organization of this type of injection are identified and measures for their reduction are developed.
The basic principles of calculating the mixing device for obtaining a fine-dispersed water-gas mixture that improves the efficiency of the injection technology are developed. The obtained test results can be used in design and operation of reservoir pressure maintenance systems in conditions of water and gas impact.
The Evolution of ESP Technology in the North Sea: A Reliability Study Based on Historical Data and Survival Analysis
Authors: Pastre L. F. , Fastovets A. 
Published: October 2017

Abstract
High intervention costs to replace electric submersible pump (ESP) completions and high deferral production caused by ESP failures in offshore and remote locations are driving the efforts to increase ESP reliability around the world. ESP designs vary considerably depending on the application, for example, unconventional resource, heavy oil, high temperature, and high abrasives. Because of the wide range of ESP applications, the equipment specification requires a tailored solution for each application to increase reliability. This paper presents typical failures and the evolution of ESP technology deployed in the North Sea as well as the enhancements proposed to increase system reliability.
The equipment improvements are based on failure analysis performed in the strings pulled from the North Sea. A large ESP population is analyzed, including 219 installations and 162 failures. Survival analysis enabled splitting the population into subsystems and analyzing the ESP performance individually after each major change in equipment specification. This approach made it possible to confirm the effectiveness of the changes and quantify the increase in reliability after each investment in equipment enhancement. It was also possible to identify the "less reliable" subsystem to focus on further improvements.
Investigation of Temperature Field in the Formations by Hydraulic Fracture
Authors: Valiullin R. , Sharafutdinov R. , Ramazanov A. , Sharipov A. , Nizaeva I. , Badetz C. , Jaffrezic V. 
Published: October 2017

Abstract
Today, number of fracturing operations (fracturing) is increasing every year due to the development of low-permeability formations classified as hard-to-recover formations. The actual task is to determine parameters of fracture obtained in order to confirm the planned design, toimprove technology of fracturing fluid injection and proppant, toprevent premature watering and to frac non-target reservoirs. The fracture properties do not remain constant over time: under the influence of rock pressure, the proppant is compressed and destroyedandduring production part of proppant is washed out of fracture. Therefore, it is also important to monitor the change of fracture parameters over time.
Technologies are known to determine the fracture parameters [16, 17]. Anywork aiming at developping accessible technologies with high level informativeness is relevant: Temperature transient ananlysis is one of them.
Thermometry method is actively used in borehole geophysics. Unlike well tests (hydrodynamic studies), thermometry allows individual characteristics of each formation (inflow intervals) to be obtained in case of a multi-layer system.
Thefield results and theoretical studies have shown that temperature is sensitive to the presence of fracture: by means of temperature measurements in the well, the fracture height is determined reliably now. An important task is to determine thefracture geometry - length, width, azimuth direction. The complexity of this problem solutionis due tothe fact that thermohydrodynamic processes in reservoir – fracture systemhas not been yet sufficiently studied. Therefore, theoretical studies are needed to study the effect of fracture on temperature and pressure fields in reservoir. In the presented work the problem is solved with help of mathematical modeling:analytical solutions are obtained and numerical model is developed. The results of multivariate calculations and their comparison with field data of temperature recovery in wellbore are presented.
A New Approach to Test Production of Exploration Wells in the Territory of Eastern Siberia
Authors: Dadakin N. M. , Rymarenko K. V. , Nukhayev M. T. , Lavrov V. V. 
Published: October 2017

Abstract
Trial operation of prospecting and exploratory wells tends to be affected by the remoteness of the field from the main transportation routes, weakly developed industry, energy, and transport infrastructures, the lack of a well surface facility system and the oil preparation system to start production.
This report describes an example of a trial operation of a remote prospecting well that includes all pre-development works, a surveying program that allows obtaining the maximum information about the productive horizon in a short time. It also provides recommendations for the adoption of technologies for pilot operation based on the block-modular production complexes for the early production launch of exploratory and prospecting wells or individual sections of the field, and technologies for continuous well monitoring and management, including bottomhole pressure gauges, a distributed temperature sensing system and a system for real-time data receiving and transmitting to the subsoil user.
This approach allows us not only talking about early production, but also solving a number of tasks, e.g. petroleum evaluation, extraction capacities of a deposit, drainage area, formation pressure evaluation, optimal well operation mode identification, gas/oil ratio change estimates, water cut, and other geological tasks. The report also describes the key drawbacks of applied trial operation methods and technologies as compared to the proposed technologies.
Production Logging in Horizontal Wells without Well Intervention
Authors: Ovchinnikov Kirill , Gurianov Andrey , Buzin Pavel , Katashov Aleksander , Dubnov Oleg , Agishev Ruslan 
Published: October 2017

Abstract
For the last decade, the global trend in the oilfield industry is to improve the oil and gas production by drilling as well as by completing horizontal wells and later on, improving the process using multistage fracturing. Though the number of horizontal wells is rapidly increasing, the production of hydrocarbons is not always up to the designed volume. In this regard, acquiring the knowledge on the performance of producing intervals is an important task for operating companies to fully optimize the productivity and maximize the recovery as well. Production logging solutions proved to be efficient in vertical wells, however, encountered various challenges in horizontal laterals as the logged section is often more than 20 times longer compared to vertical wells [1]. Common factors that complicate the production logging are layered flow of formation fluid, deviation and accessibility of wellbore, and changes in fluid velocity moving past or through the tools. Direct transfer of production logging technology and interpretation algorithms from vertical wells to horizontal wells leads to erroneous conclusions about the well performance [2]. Moreover, the quality of well completion and reservoir management decisions for production wells largely depends on the production logging data such as mechanical flowmeter and fluid capacitance surveys.
Until recently, there is no alternative to wireline downhole tools being used to evaluate the placement of fracturing proppant or acids, production rate and zonal water breakthrough. In practice, well intervention in horizontal wells requires implication of coiled tubing or tractor services to deploy logging tools downhole. The success of well intervention depends on several factors and among of these are as follows: well accessibility, completion IDs and length of the horizontal lateral, etc. There are also key aspects to be considered such as the significant cost of well intervention and the availability of wireline and coiled tubing equipment. This article provides an overview of one of the alternative methods of production logging in horizontal wells which doesn't require well intervention using PLT tools, Coiled Tubing or Tractor services. This method employs tracer technology of quantum dot markers placed in the reservoir during stimulation. The method also allows reducing the cost as well as the complexity of acquiring downhole data. Unlike the conventional PLT, the technology described below can provide production logs on demand during one year after well stimulation.
Permeability Anisotropy in the Thinly-Bedded Pokurskaya Formation from Advanced Wireline Logs and Formation Testers
Authors: Zagrebelnyy E. V. , Glushcenko N. A. , Martynov M. E. , Tsiklakov A. M. , Blinov V. A. , Weinheber P. , Karpekin Y. A. , Ezersky D. M. , Bugakova Y. S. 
Published: October 2017

Abstract
Field development planning requires a proper understanding of layer permeability in order to predict production rates. Experience with horizontal production wells in the Pokurskaya formation of the Messoyakhskoye field showed systematically lower flow rates from the B sands versus the C layers even though their petrophysical properties appear similar. It was proposed that differing permeability anisotropy between the layers might be the cause and an upcoming well in the field offered the ability to test this hypothesis. A logging program that included Vertical Interference Tests (VIT) with a Wireline Formation Tester tool (WFT) and advanced petrophysical logs, 3D resistivity, NMR and dielectric scanner was run to estimate the the kv/kh ratio pointwise with VIT and extrapolate these measurements through the entire section.
VIT tests were done at several depths with a dual-packer for the fluid withdrawing and a pressure probe for pressure monitoring. Estimated anisotropy coefficient varies mainly from 0.02 to 0.07 but with both higher and significantly lower values at some depths, which indicate extremely limited connectivity in some intervals. In general, the kv/kh ratio is significantly lower in the upper interval of the PK1-3 formation versus its lower interval. The triaxial induction logging shown the anisotropy of the reservoir electrical properties (Rv&gt; Rh), caused by thin interbedding of the sandy fraction rocks with the interlayers of clays and siltstones, which are several times lower than the resolution of standard logging methods. Similarly, interlayering of thin sand and silty rock types, which have different absolute permeabilities, causes anisotropy of the formation permeability. It is possible to estimate the permeability of the macroanisotropic formation along and across the bedding knowing the water-retaining capacity as well as the laminated sand fraction coefficient. The VIT and the logging results are consistent enough. The VIT test results are the reference measurements while the 3D induction logging results are used for interpolation and extrapolation of these direct measurements through the entire interval and in wells without VIT tests including horizontal wells.
The subsequent analysis showed a significant anisotropy of permeability in the Pokurskaya formation, which varies along the interval of the formation and, probably, laterally. This must be taken into account when calculating the flow rates of the well. The complex of studies makes it possible to perform an express estimation of the permeability anisotropy in the pilot wells in order to select the optimal interval for horizontal wells landing.
Natural Fractured Reservoirs Characteristics Estimation Based on Production Data using Simplified Correlation. Examples from Russia
Authors: Syrtlanov V , Kovaleva E. , Aleev A. 
Published: October 2017

Summary
This paper suggests the simplified correlation ratios, that are an approximate analytical representation of exact numerical solution, for evaluation of fracturing characteristics of the fractured reservoirs with the use of decline curves. Formalization and automation methods are suggested for finding fractured reservoir approximate parameters and range of uncertainty under the Warren-Root model.
Investigation of a Pressure Barrier at OWC and its Effect on Waterflood
Authors: Stasyuk Bogdan , Camerlo Virginia 
Published: October 2017

Abstract
Understanding the pressure history of a field brings valuable information that could affect decisions regarding future field development. Sequential formation tests (RFT, MDT, XPT, RDT, Stethoscope and other tools) done while drilling a new well can help describe the dynamics of pressure conditions in the reservoir. In the early life of a field, sequential formation tests describe initial reservoir conditions (gradients, contacts, compartments). Sequential formation tests obtained in wells drilled after the start of production can help the understanding of communication within the field (injector to producer; producer to producer; aquifer/peripheral injection effect; barriers; and connectivity across faults).
Historical sequential formation tests performed on a nearly 30-year-old oil and gas field in West Africa were analyzed and used to identify, confirm and describe a significant pressure barrier at the OOWC (e.g. "tar mat" that gives up to 1000psi difference across contact). Systemizing sequential formation test data by time and area allowed estimation of the pressure barrier extent and its effect on communication between peripheral injectors and the oil zone. Pressure breaks were then plotted on well logs and located in conventional core, where possible, to determine a possible geologic explanation for the pressure barriers.
Smaller pressure barriers are attributed to lithologic changes associated with either facies changes or secondary dolomitization. However, the largest pressure barrier appears across the OOWC. Visual inspection of 5 conventional cores across the field, confirms the presence of 6-9 ft. of solid hydrocarbons, interpreted to be a "tar mat," across the OOWC, except in the northwest portion of the field. Core analysis of samples within the tar mat zone shows unaltered, high permeability (as per testing procedure all cores were cleaned with solvent before testing). The pressure barrier is likely due to the presence of soluble, but highly viscous, long chain hydrocarbons that effectively create a no flow barrier across the OOWC.
Wells with a long period of water free production correspond to areas with a predictable strong pressure barrier at the OOWC. Conversely, wells located in an area with a poorly defined barrier at the OOWC had quicker water break-through. Thus, we conclude that peripheral water injection perforated below the OOWC is less effective in areas where the tar mat is present.
Oil Production Enhancement Operations Recommendations by Well-Testing and Decline Analyze
Authors: Lazutkin D. , Gulyaev D. , Morozovskiy N. 
Published: October 2017

Abstract
In the paper, it is shown that the results of the interpretation of measurements of permanent reference gages on the electric submersible pump (ESP) together with the data on the change in the historical production rate of the wells allow carrying out the justification and support of the oil production enhancement operations and also the analysis of the efficiency of the oil production enhancement operations performed by estimating the current skin-factor of the wells and reservoir pressure. In particular, wells have been identified in which worsening of the skin-factor in time is observed. For them, the optimal time for performing repeated well interventions was chosen to improve the skin-factor and increase production from the wells.
Separate results of the work are represented by an express method for selecting the optimal time for transferring production wells to injectors for pressure maintains to optimize the production of a section of the oilfield based on the telemetry gages on the ESP. At the same time, the forecasts were made on the basis of express 2D models in the software "Topaze", which significantly increases the speed of work execution compared to full 3D modeling, and the accuracy of forecasts remains quite high.
The paper shows that the results of the historical flow rate of wells and the telemetry of pumps are a good informational basis for the application of a new method for analyzing cross-wellbore interference – multi-well deconvolution (MWD).
Thus, without a loss of production, a analysis of the results of a production decline was carried out on the basis of the algorithms for interpretation of the well test and recommendations of production enhancement operations were justified to increase production.
Well Index Calculation for Arbitrary Trajectory, Perforation, Hydraulic Fracturing and Geological Properties
Authors: Bakhty N. S. , Bembel G. S. 
Published: October 2017

Abstract
Calculation of inflow to a well and hydraulic fracture in the reservoir simulation is presented in this paper. An algorithm of well index (WI) calculation based on a new numerical-analytical solution is proposed. In simple cases, the proposed method is identical to the classic Peaceman's formula, and surpasses it in accuracy in more complicated cases, taking into account different properties of the perforated grid block and its neighbors, imperfect perforation, location of a well in a grid block, impermeable boundaries next to a well.
Acquired WI coefficients were compared with analytical solutions for imperfect well, five-spot pattern, inflow to infinite and semi-infinite hydraulic fractures and also for the problem presented in [1], in which production rates before and after fracturing are compared. It is shown, that in these cases presented algorithm provides a lesser deviation from the analytical results than Peaceman's formula. Therefore developed algorithm is proved to be more accurate and applicable in more general cases.
Additionally, to demonstrate the effect of using the WI coefficients acquired with different formulas in reservoir simulation both methods were applied to comparison project SPE1 [2], in which it is necessary to account for impermeable boundaries and imperfect perforation. A significant difference of simulation results can be seen in the oil rate of the producing well, gas oil ratio, and pressures.
The Concept of the Complex Carbonate Reservoir Saturation with the Variable Wettability
Authors: Kanevskaya R. D , Budkin K. D , Korobkin S. V , Lubimova O. V , Pimenov A. A. , Isakova T. G. , Markova A. Yu. 
Published: October 2017

Abstract
Rock wettability and its transformation in the process of formation and development of oil deposits is a crucial factor influencing fluid content and many aspects of reservoir performance, particulary in waterflooding and enhanced oil recovery techniques. The saturation concept for the complex carbonate reservoir with the variable wettability is presented. It is shown that rock wettability can significantly affect large-scale fluid distribution processes in the oil-saturated reservoir.
The analysis of the geophysical characteristics of the cross section allowed to separate three geological units with significantly different values of the electrical resistivity. By means of joint analysis of core examination and geophysical well logging it is demonstrated that zones of the «low-resistivity» geological unit are chiefly characterized by hydrophobik type of rock wettability, while zones of the «high-resistivity» unit are typically described by hydrophilic type of rock wettability. The predominantly hydrophobic unit lies between two hydrophilic and less permeable units. Oil saturation model is designed with the assistance of field and core data based on the capillary-gravitaty equilibrium concept taking into account variable rock wettability. The results of the relative permeability experiments and data on the initial water cut of well production are also used to identify initial saturation distribution in reservoir.
In the predominantly hydrophobic unit, the transition zone is insignificant and partially below the free-water level. There is water alone in the hydrophilic units at these depths. At depths corresponding to the transition zones of the hydrophilic units, there is an area of high oil saturation in the predominantly hydrophobic unit.
The presented approach to the creating of the saturation model enabled to consider previously ignored factors (the electrical resistivity of the geological units, the presence of bridges between them) that affect the efficiency of the reservoir pressure maintenance system and recovery of reserves. The identification of the thick lower unit with high water saturation made it possible to determine the source of water encroachment and explain the nature of water encroachment of production wells.
The proposed concept of the complex carbonate reservoir saturation with the variable wettability allowed to connect well log, core and field data to a single consistent model.