bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Fractured Horizontals Performance with Well Test Data
Authors: Krichevskiy V. M. , Morozovskiy N. A. , Gulyaev D. N. , Bikkulov M. M. 
Published: October 2015

Abstract
Paper presents multi-fractured horizontals performance analysis in case of low-permeable formation. The puppose of the analysis is to suggest a method of optimizing multi-frac parameters (such as number of fracs, fracs spacing, Xf etc.) in different geological conditions. Paper describes an algorithm of estimating main formation and well characteristics and forecasting future production. In addition, an approach to multi-frac design optimization for new wells is shown.
The main tools of well performance analysis are production logging, well testing, decline analysis and simulation. Authors have performed all these survey types analyzing multi-fractured wells behavior. Authors have developed and successfully implemented of Company fileds new technologies of testing and production logging on such wells. Active development and massive implementation of permanent data gauges systems (PDG) let Company to use decline analysis methods of well performance. A lot of data obtained has led to new interpretation theories development, allowing to explain wells behavior and match pressure and rate data. For more robust estimation of parameters, production logging was performed with use of modern tool with arrays of sensors.
With the results obtained, series of one-layer model calculations was performed, resulting in optimal multi-frac design for one of the fields being studied.
Improved Approaches to Determination of the Current Oil Saturation of Reservoir Rocks According to Geophysical Data in the Fields of LUKOIL-PERM LLC
Authors: Gabnasyrov A.V. , Shilov A.V. , Ustinova Yu.V. , Nekrasov A.S. 
Published: October 2015

Summary
Determination of the current oil saturation is one of the most urgent problems arised during monitoring of field development and well interventions planning on the fields being at the late development stage. At that, saturation nature in the casing is defined on the quality level with success rate of 50–60 % and it does not allow to predict water cut of the exposed interval since the determination error Fo ± 10 % may result in a water cut determination error of up to 90 %. Analysis of pulse neutron logging (PNL) results demonstrated that the main reason for low reliability of the studies is underestimation of rock and fluid lithological composition effect on the method indications.
To improve quality of developed formations saturation determination, PNL results (as the main method of determining the current oil saturation at LUKOIL-PERM LLC fields) and pilot work methods were analysed using WLS methods: ISGRL-Cl, SPNLGL-Cl, PPNGSL, С/O-logging, NEL for 2011–2014 period.
During the works, the most promising methods for current oil saturation determination – C/O logging and nanoelectronic logging were specified, which reliability was 80 % and 100 % respectively. At the same time, these methods were insufficiently tested for their mass usage.
To improve the PNL information content, an up-to-date interpretation approach is proposed, providing quantitative determination of oil saturation factor and prediction of the well water cut with accuracy of more than 80 % by taking into account the effect of lithological composition of the reservoir rocks and fluid properties on PNL indications.
The main advantage of the developed method is determination of current oil saturation factor and water cut prediction, and, therefore, a direct risk estimation during uncovering of any permeable interlayer. In addition, the approach implemented in the work, allows to check the formation recovery rate to provide monitoring of the well interventions development and performance according to the domestic geophysical methods.
East Siberian Field Waterflood Management
Authors: Burdakov D. A. , Rukavishnikov A. P. , Tuzovskiy M. A. 
Published: October 2015

Abstract
Waterflood strategy for balancing reservoir pressure and improving sweep is proposed. Work objective was to introduce new workflow that utilizes system approach in waterflood management for maximizing field performance.
The workflow included classic pattern analysis with rating of zones of interest based on complex parameters and diagnostic diagrams coupling recovery, pattern production, reservoir pressure and cumulative production before water breakthrough. Top rated patterns injection regimes are optimized with the aid of reservoir simulation. When choosing a well for conversion producing flow rates and chance of early water breakthrough or poor pressure response were considered. Detailed correlation, understanding of reservoir architecture, accurate mapping of properties and multiple simulation runs give the base for producer to injector conversion decisions.
Implementing of the waterflood management workflow resulted in watercut decrease in wells with early water breakthrough and promises higher recovery for new patterns since uniform injection replacement is controlled; Process of waterflood management turned into a routine process with known deliverables, action list is made and discussed every month; Zones with uneven sweep were identified and injection rates were optimized; Process of conversion candidate selection and making a conversion priority list was mastered; Injection wells with completion damage are spotted with the use of production analysis and added to stimulation program; Intervals of water breakthrough were determined based on correlation, petrophysics and production logging, squeeze jobs were planned;
Currently there are only few waterfloods online in East Siberia and sharing management experience and best practices can without a doubt add value to an existing work process or show the right route for the new one.
Iron Precipitation in Calcite, Dolomite and Sandstone Cores
Authors: Rady Ayten , Nasr-El-Din H.A. 
Published: October 2015

Abstract
Formation damage due to iron precipitation has been a major problem in the oil field. It has been established that as the pH of the injected acid increases, iron (III) ions start to precipitate and block the pores. However, where exactly this iron precipitates and how iron precipitation changes with different lithologies has not yet been studied.
Coreflood experiments were conducted to assess the effects of temperature and iron concentrations on the degree of damage caused by iron precipitation during an acid job. The temperature values tested were 200 and 300°F. Iron concentrations ranging from 5,000 to 10,000 ppm was used. The core effluent samples were analyzed by ICP to measure the concentrations of key cations.
After conducting core flood experiments, it was found that iron precipitation occurs across the entire core. Iron precipitation was severely detrimental in the sandstone cores compared to those of calcite and dolomite. While the limestone cores showed the least formation damage from iron precipitation, core flood tests indicated that as the iron concentration increases, the damage was more evident, especially in the sandstone cores. On the other hand, increasing the temperature adversely affected sandstone and dolomite cores but improved the final permeability of limestone cores.
In this study, the location of the iron precipitation is determined for three different lithologies. The effects of different parameters are studied to determine the best conditions that would lead to a decrease in iron precipitation and hence prevent formation damage. Iron control agents are not always needed, as previously thought.
WAG Optimization Algorithms Based on the Reaction of Producing Wells
Authors: Kazakov Kirill Viktirovich , Bravichev Kirill Arsenievich 
Published: October 2015

Abstract
Selection of optimal technological parameters of water-alternating-gas injection (WAG) in the oil reservoir is an important task. Technological parameters of WAG include volume ratio of injected water and injected gas, and total volume of water and gas (in reservoir conditions), injected in one cycle. The paper contains results of studing of efficiency of WAG with various technological parameters. Technological parameters of WAG had constant values and values varying in time depending on the reaction of producing wells for several algorithms.
Injected water and gas are distributed unevenly in the reservoir due to difference in their viscosities and also because of the heterogeneity of reservoir permeability. Distribution of saturations and relative permeabilities of fluids in the reservoir are being changed during WAG. It may require changes in the technological parameters of WAG during injection.
Compositional hydrodynamic simulation was used for the studies. The simulation took into account hysteresis of relative permeabilities and their change depending on the surface tension between oil and gas. The model for the simulation had the properties of the achimov deposits in Western Siberia. Fluidal model was adapted to a series of tests of samples of reservoir fluid. End points of relative permeabilities and the dependence of oil relative permeability in three-phase flowing was being selected during playback the results obtained with the replacement of oil by water, gas and WAG in core samples. Multivariate calculations were performed for uniform and nonuniform distribution of permeability (by area and by thickness) in the oil reservoir. It was considered waterflooding, gas injection, water alternating gas injection and simultaneous water-gas injection.
The simulation results showed that the oil recovery for a heterogeneous reservoir may differ significantly depending on technological parameters of WAG. The wrong choice of technological parameters of WAG can lead to substantial loss of oil recovery. It was developed algorithms for adjust technological parameters of WAG based on water-oil ratio and gas-oil ratio of producing wells of the impact area. Implementation of WAG by using these algorithms can achieve a maximum or close to a maximum oil recovery compared with water flooding, gas injection and WAG (simultaneous or separate injection of water and gas with constant in time of technological parameters). These algorithms can be used for implementation of WAG when distribution of permeability by area and by thickness is uncertain.
Determining Methods of Static Mechanical Properties of Poorly Consolidated Sand-rocks (by the Example of the Yuzhno-Russkoye Field)
Authors: Lushev Mikhail , Markin Maxim , Dubnitskiy Ivan , Vorobyev Vladislav 
Published: October 2015

Abstract
The article deals with the methodological approach to the research results correction of the rocks mechanical properties of the Turonian age based on the replacement of commonly used models of continuum mechanics for theoretical models of granulated solids mechanics. This method effectiveness is considered by the example of the Yuzhno-Russkoye field of the West Siberian Petroleum Province for producing interval T1-2dedicated to the Turonian Stage of Upper Cretaceous Series. Results correction of laboratory experiments of rocks strength properties is carried out that allows increasing the accuracy of their determination and improving the quality of geomechanical model of rocks that form the borehole for subsequent hydraulic fracturing design, and analyzing the bore hole stability correctly.
Analysis of Black Oil Correlations for PVT Properties Estimation
Authors: Odegov A. , Khabibullin R. , Khasanov M. , Brusilovsky A. , Krasnov V. 
Published: October 2015

Abstract
Over the last 30 years, considerable research into the assessment of PVT-properties of hydrocarbon formation has been carried out. Based on laboratorial and field research of oil and gas samples, two basic approaches of PVT-properties assessment were developed. They are correlation approaches, based on statistical analysis of the result of research and compositional simulation approach based on the equation of state (EOS) solution. These approaches have both advantages and disadvantages. It is clear that both of them are essentially dependent on the quality of the initial data obtained from the analysis of reservoir and surface samples of hydrocarbons. Therefore, it would be wrong to contrast two approaches in terms of priority. Compositional simulation is indispensable for the assessing of reservoir system behavior near the critical point for volatile oil and gas condensate systems, which have no correlation models, or give results with poor accuracy. The basis of compositional simulation is the composition of the formation system, which consists of individual components to C6 inclusively, and fractions of C7+ pseudocomponents. Correlation models are successfully used in assessing of the behavior of black oil. Basic parameters of PVT model correlation are Rsb - gas-oil ratio at bubble point, γo - oil specific density, γg - gas specific density, Pb - bubble point pressure, Tres - reservoir temperature. It should be noted these parameters can be obtained in different experiments of degassing, namely, single or differential, as well as within the framework of standard or commercial separation. Moreover, each PVT correlation usually tuned to its own regional data bank. As a result, different correlations may use different statistics on overlapping intervals. Recently, several articles have been published, which analyzed the correlation approaches of PVT properties assessment [1-3]. However, the study provides an analysis of correlations without recommendations for their use. The main conclusion of these studies is a statement of fact that the choice of correlations should be conducted with respect to basic oil properties. Usually, it recommends to use new coefficients for the standard correlation model.
Special Treatment of Thermo-Hydrodynamic Well Studies in Massive Fractured Reservoirs of Crystalline Basements
Authors: Shtyrlin V. Ph. , Fomkin A. V. , Plynin V. V. 
Published: October 2015

Abstract
In recent years, geologists have discovered new oil-bearing lithospheric layer – fractured oil-bearing igneous and metamorphic basement rocks, so interest in foundation as oilfield facilities increased significantly. Analysis showed that oil in 32.5% of reservoirs is confined to granitoid rocks, in 29.0% of reservoirs oil is concentrated in metamorphic rocks, in 14.0% - in carbonates, and in 12.5% - in volcanic formations. Not more than 7.0% of reservoirs are in weathering mantle of penetrative rocks.
Known methods of reservoir structure studying can be divided into external and internal. External methods are based on acquisitions from the land or sea surface, where seismic survey (seismic waves) is a tool of study. Internal methods are based on acquisitions in reservoir itself, where the well is object of study. Innovative well survey technology SOTGDIS (special treatment of thermo-hydrodynamic well studies) enables to identify texture of internal structure for borehole environment in massive reservoirs. This technology is based on data acquired during standard thermo-hydrodynamic well studies and does not require changes in oil production technology and well survey.
Developed technology enables to describe flow geometry in reservoir near-wellbore zone, which significantly improves quality of hydrodynamic simulation and provides additional information for flow analysis. As a result, there is a possibility to build adequate hydrodynamic model and locate remaining recoverable reserves in complex reservoirs such as crystalline basement.
Based on data stored in thermodynamic and hydrodynamic well studies, SOTGDIS developed by the authors enables to determine a variety of new parameters describing internal structure of massive fractured reservoir: –Geometrical size of super-fractures (effective length, width and openness);–Super-fracture angle;–Geometrical size and location of active well zone.
In other words, it is possible to describe flow properties geometry in bottom-hole zone for fractured reservoir conditions.
Fold Belts: Shall We Expect a Shift in Petroleum Exploration Priorities?
Authors: Sobornov K. O. , Afanasenkov A. P. , Danilov V. N. , Zhemchugova V. A. , Volozh Yu. A. 
Published: October 2015

Abstract
Oil and gas exploration in Russia passed through 3 cycles of rapid reserve base build-up. The first one is related to the exploration in the foothills of the Caucasus. The second successful exploration campaign occurred in the Volga-Urals. The last one took place in the West Siberia. All of them were driven by new ideas coupled with technological advances. The vast Soviet legacy provided sufficient reserves to boost oil and gas production for many years to come. As a result exploration activities in Russia were drastically reduced. Oil and gas companies were mainly focused on capitalization of business through increasing of oil and gas recovery on existing fields. It seems that this period comes to an end. Production from the aging giants is getting more expensive. The existing producing fields have predominantly hard-to-recover reserves with a high water cut.
The identification of new exploration plays to offset the declining production on old fields eventually becomes an important issue. Petroleum exploration in the mature areas, such as the West Siberia and Volga Urals, deliver predominantly small fields. This necessitates the identification of new exploration opportunities capable to provide large volumes of oil and gas to support future production. Examination of G&G data characterizing petroleum potential of Russia indicates that reserve replacement may have three possible directions. These include: (1) exploration in the Arctic shelves; (2) realization of potential of shale deposits; (3) exploration in the underexplored fold belts. It is likely that the third option may provide very substantial resource potential. In addition, while the Arctic exploration and shale development projects are affected by the sanctions, equipment and technologies needed for operations in the fold belts are available for Russian companies.
Paleogeographic Reconstruction and Structural Morphology of Domanik Formation in the Repubilc of Tatarctan
Authors: Liang X. , Philippov V. , Galushin G. 
Published: October 2015

Abstract
High OM shale formations are common in almost all sedimentary basins from the Cambrian to the Neogene period in Russia. Typical unconventional resource of oil and gas in Volga-Urals basin of Russian platform belongs to the deposits of Domanik complex, which is developed in undercompensated hollows and depressions from Middle Frasnian Semiluksky (Upper Devonian) to Later Tournaisian (Lower Carboniferous) formation, of which one of the most promising objects are in the Republic of Tatarstan (RT). It is not only theoretical but also practical in the studying structure of these sediments, their genesis and typing sections because these oil-gas bearing characteristics are not only existed in the sedimentation of Volga-Ural Basin, but also in other oil and gas provinces of the world.
On the basis of geological and geophysical studies, we use primary exploratory and drilling materials, including core analysis (lithological descriptions, definitions of reservoir properties, geological survey wells, etc.), analysis the paleontological conditions and characteristics of Domanik formation in Late Devonian on the territory of the Republic of Tatarstan (RT).
Domanik formation on the territory RT has a wide spatial distribution with dark siliceous-clayey-bituminous limestones and typical complex fauna in Semiluksky time. Higher in the cross section, Domanik facies are reduced as narrowing axial parts of the Kama-Kinel deflections (Ust-Cheremushansky, Nizhnekamsk, and others) from Upper Frasnian to Larer Tournaisian time with weakly bituminous and unbituminous carbonate rocks closer to the inner sides. As a result of differentiation in the vibrational motions distribution, from Semiluksky to Zavolzhsky time it is devided several zones with different conditions of sedimentation, of which the typical "Domanik" type is developed in relatively deep shelf.
The most greatly developed rock in the cross-section is chemogenic (granular) limestones, which are most widespread in Cm-3 and Mn-1 stratums with 2 genetic groups of collectors - pure crack (KP &lt; 4 %) and porous-cavernous fractured (KP &gt; 4 %).
The study result shows that tectonic fracture is the most important factor in reservoir formation, therefore favorable zones are mainly determined by the local lithology and tectonic conditions.
Modeling Gas Dissolution in BlackOil Models
Authors: Zubov V. R. , Indrupskiy I. M. , Bogachev K. Yu. 
Published: October 2015

Abstract
Light oil fields development often demonstrates some evidence of oil-gas phase transition hysteresis. Phase transition rate depends on the process considered: changing state from dissolved in oil to free gas or reverse gas dissolution (re-solution) in oil [1]. The difference in phase transition dynamics leads to such phenomena as continuous free gas production in reservoirs with pressure above initial bubble point. Reservoir simulators are used for forecasting reservoir dynamics and decision support. For most of the common practical problems, BlackOil model is the choice. The main object of the present study was to analyze reservoir simulators option for controlling gas re-solution and to modify the mathematical model of the option in order to account for the process dynamics known from experimental data.
The existing and new versions of the gas re-solution reservoir simulator option were considered on the example of a waterflood pattern. The process studied was gas liberation during primary oil production followed by waterflooding with increasing reservoir pressure. Fluid properties were taken by data from Sherkalinskaya formation Tala zone of Krasnoleninskoye field, for which the effects of slow gas re-solution were observed. Results of the simulations with different gas re-solution options were compared by basic field development indicators. Also the contact experiment in a pVT bomb was simulated in order to demonstrate physical effects observed for different versions of the mathematical model of gas re-solution.
The suggested extension of the option accounts for two major aspects of gas re-solution known from experimental data. The first one is the dependence of gas re-solution rate on the value of over pressure above the initial bubble point. The second one is the fact that re-solution is a relaxation process which has exponential time dynamics. The developed mathematical model included these two aspects and was implemented in a reservoir simulator. The results of the test runs show considerable influence of a gas re-solution option used on the dynamics of reservoir pressure, gas-oil ratio and oil production.
The presented approach to gas re-solution control in reservoir simulators is based on data of experimental studies of non-equilibrium phase transitions of hydrocarbons. A flexible tool has been developed for history matching of flow models for the reservoirs with pressure increase after primary oil depressurization below bubble point. Matched model can be used to produce physically consistent forecasts of efficiency of various technologies for gas re-solution and further field development.