bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design of WAG Parameters
Authors: Valeev A. , Shevelev A. 
Published: October 2017

Abstract
When an oilfield reaches the final development stage it becomes crucial to plan enhanced recovery methods. In case of low and medium viscous oil in depleted reservoirs it is feasible to use water-alternating-gas (WAG) treatment. Application of the method depends, first of all, on the availability of non-commercial supply of associated gas. To evaluate the amount of gas necessary for the treatment, it is required to estimate the operation's efficiency. The important thing here is to decide on the optimal ratios of the injected water and gas. This work is dedicated to the methods of planning the required ratios of injected water and gas, which can be used for further estimations.
The issue in question is studied using the oilfields in Kogalym region as an example. Analytical evaluations, numerical and experimental simulation were employed to reach the work's objectives. The analytical approach enabled to define the efficient ratio for gas water as a mixture with the minimal mobility or with equal mobility of water and gas in a porous media. The numeric simulation was done using a 2D model of a parallel flow calculated in ECLIPSE software. The laboratory testing was done using a standard porous flow model with dry and wet gas.
As a result, the ratios of injected water and gas were found and compared, recommendations on WAG planning for Kogalym oilfields were issued.
The studies enabled to estimate the need for the gas to be used for the treatment, detailed and justified to different degrees.
Prioritizing the fields depending on the amount of gas reserves enabled to define the ones best suited for applying gas EOR methods.
The novelty of the study is the complex approach to the injected gas water ratio estimation. Comparing analytical, numerical and laboratory studies enabled to adequately consider the parameters affecting the process and to justify the means of sweep enhancing.
High-Pressure Air Injection Laboratory and Numerical Modelling in Bazhenov Source Rocks
Authors: Bondarenko T.. , Khakimova L.. , Cheremisin A.. , Spasennykh M.. 
Published: October 2017

Abstract
In this paper, key aspects of constructing a hydrodynamic model of high-pressure air injection into Bazhenov source rocks were highlighted. Most of them are associated with the choice of pseudo-components of kerogen required to describe thermal decomposition and oxidation of kerogen and needed for construction of a kinetic model. Sensitivity analysis was carried out. As a result, high sensitivity of output to the change in the content of components reflecting the presence of kerogen in the formation and its participation in oxidation processes and thermal decomposition was confirmed.
Based on the above, a list of experimental studies was formulated, which must be carried out to determine the parameters of numerical simulation and to evaluate the effectiveness of the high-pressure air injection method.
High-pressure ramped temperature oxidation of kerogen was carried out. As a result, temperature profiles, gas composition, and volume of generated/displaced fluids were obtained. 24.8 g of water-oil emulsion were generated from 92 cm3 of rock. Kerogen in the sample was completely converted, which was confirmed by the results of conducted pyrolysis studies.
OGIP Evaluation by using Specific Drainage Volumes Method: Theory and Case Study
Authors: Kolbikov Sergey , Klimov Mikhail , Ramazanov Rinat 
Published: October 2017

Abstract
The paper describes the features of using the methodology for calculating the specific drainage volumes for estimating the initial gas in place and the formation water volumes invading the formation for gas condensate reservoirs. It is shown that the application of thespecific drainage volumes method is a simple tool in the engineer'shands, allowing to do analysis of the variable drainagevolumes for wells with a minimal set of initial data. The method of specific dynamic volumes allow to determine them foreach producing well and to obtain an integral curve of the drainage gas-saturated volume of the resrvoir and determine the necessary time to drain the entire hydrodynamicallyconnecte gas-saturated volume of the deposit. The knowledge of time when the entire gas-saturated volume of the deposit is envolved in drainage is a necessary basis to justify the application of the material balance methods to calculategas in place volumes. The deviation of the integral curve of the gas-saturated drainage volume from its maximum value makes it possible to assess the water invading volumesin the reservoir in time, taking into account the processes of deformation of the reservoir and the drop out of condensate. Estimation of the gas-saturated pore volume and its reduction in time due to formation water encroachmentfrom the method of specific drainage volumes application allows to reduce the limits of uncertainty for original gas in place volumes(OGIP) and the aquifer parametersin the process of geological-hydrodynamic model history matching.
Frac Size Matters: The Experience of Achimov Deposits Development in Urengoyskoe Gas Condensate Field
Authors: Yudin Alexey , Kubyshkin Dmitry , Lyapunov Konstantin , Zakharzhevskiy Yuriy , Snokhin Alexey , Romashkin Sergey , Prokhorov Alexey 
Published: October 2017

Abstract
Urengoyskoe oil and gas condensate field is second large conventional reserve of gas condensate in the world. Active development of Achimov deposits of this field is in progress now. Specific features of Achimov layers are low permeability, extremely high reservoir pressure and 15-90 meters of Net Pay. Increase of hydraulic fracture frac half-length is main strategy for such environment to optimize well productivity and reservoir fluid recovery. Logistic in tough arctic conditions is challenge here. Method to increase volume of hydraulic fracturing treatment and its effect on well productivity is described in this article.
Some technological tasks were solved to optimize hydraulic fracturing process of Achimov deposits. Pumped proppant volume was a main one. Treatment design was modified to be more aggressive step by step to decrease used slurry volume and enhance fracture geometry. Full laboratory support was provided for this project. Fracturing fluid composition was optimized to provide fluid stability during approx. 7 hours fracturing job as well as fluid friction decrease to meet surface limitations of treatment pressure. Using open channel fracturing technology allowed to optimize logistics in limited space well pads without additional pad construction works and increase job efficiency. The technology provides required size of hydraulic fracture due to proppant pulsing method with proppant consumption decrease.
Before 2014, fracturing treatment size was in a range from 50 to 300 tons of proppant. It did not provide parameters of optimal fracture geometry for pay zones having average Net Pays of 76 m. Increase of frac tanks amount and special frac fleet equipment units combined with permanent technological and laboratory support allowed increasing pumped proppant volume per job up to 400 tons providing high quality of operations. Implementation of open channel fracturing technology was next step in direction of frac job volume increase (up to equivalent of 700 tons of proppant) keeping the same resources and from the same size of well pad. Analysis of efficiency of open channel fracturing technology in comparison with conventional fracturing treatment in wells having similar geological conditions and stimulated with the same slurry volumes was done. It confirmed success of channel fracturing technology using results of the conducted well tests.
Implemented hydraulic fracturing optimization workflow was effective to increase well productivity in turbidite reservoir. To date, sizes of hydraulic fractures created in Urengoyskoe field are one of the largest worldwide. Experience accumulated in Achimov deposits development could be successfully used in other hydrocarbon fields having similar geological challenges.
Specifics of Development, Infrastructure Construction and Production of Oil-Gas-Condensate Fields. Integrated Model Application Experience
Authors: Konstantin Povyishev , Sergey Vershinin , Olga Vernikovskaya 
Published: October 2017

Abstract
This article describes specifics of engineering work performed to develop oil-gas-condensate fields and build their infrastructure facilities. Unlike conventional reservoirs, it is not unusual that oil-gas-condensate fields cannot be produced by the artificial lift method (using electrical centrifugal pumps or sucker-rod pumps). The success of any efforts to increase efficiency of an oil-gas-condensate field development project depends on balanced decisions that need to be made when drilling, building infrastructure facilities and producing both the oil and the gas part of the field. To address this issue, the global industry leaders have developed special tools and technologies that will allow meeting the emerging challenges. The goal of this work is to introduce and adapt new technologies for assessment, planning and management of oil-gas-condensate assets.
The proposed tools and algorithms can be used to identify possible losses and constraints across the entire Reservoir-Well-Infrastructure value chain. Based on analysis of reservoir and wellhead interferences, a balanced system can be created with the highest technical and economic parameters possible.
These algorithms have proven to be highly efficient as is shown by the example of an integrated development concept for Yaro-Yakhinskoe and Novoportovskoe oil-gas-condensate fields.
Yaro-Yakhinskoe oil-gas-condensate field is characterized by a fairly rapid transition from oil production to gas production, with a multi-fold increase in wellhead pressure. Because of the wellhead interference, taking into account the well drilling and commissioning schedule, joint operation of oil and gas wells results in a significantly lower production plateau and, consequently, poor economics of the project. Such integrated approach has allowed the field operator to come up with a fluid gathering and treatment system configuration that ensures a profitable return.
In case of Novoportovskoe oil-gas-condensate field, without an integrated Reservoir-Well-Infrastructure model the operator was failing to make consistent production and development decisions. Analysis of the reservoir and wellhead interference has identified the risks of not achieving the design wells flow rate numbers which would make the project uneconomical. Once the Reservoir-Well-Infrastructure model was developed the field operator could make targeted steps to ensure the desired field production performance.
Capabilities of the integrated Reservoir-Well-Infrastructure model are not limited to the conceptual engineering stage. At present, mechanisms are being developed to use this model for day-to-day monitoring and planning of production activities, engineering of gas lift operations, balancing of reservoir pressure maintenance and gas re-injection system.
EOR Miscible Gas Project in Oil-Gas Condensate Field
Authors: Glavnov Nikolay , Kuntsevich Vitaly , Vershinina Maiia , Penigin Artem , Badgutdinov Ruslan , Perevozkin Igor , Bazhenov Dmitrii , Shorokhov Aleksey , Garipov Ilnar , Ushmaev Oleg 
Published: October 2017

Abstract
The development of oil rims is usually accompanied by the production of a significant amount of associated gas. It is often a positive monetization through sale or generation of electricity, due to the remoteness of oil fields and/or consumers.
This work provides experience in carrying out a technological assessment of the implementation of the miscible displacement in the oil rims by rich gas, with the simultaneous injection of dry gas in the gas cap for one multizone oil field of Western Siberia.
The oil rims in the field are presented by the rims of the edge and the underlying type. The producing gas in the field is reasonably dry, with about 10% of the molar C2-C4 concentration, which prevents miscibility of gas and oil in the reservoir. In the comprehensive preparation of gas, there is a technology for the allocation of the intermediate group of C2-C4 and C1 methane, which allows the further gas to be obtained by another gas composition that satisfies the pressures and temperatures conditions of the reservoir.
The base field development plan of oil rims includes the gas return to the gas cap of the reservoir of the total amount of gas produced. This development strategy to increase the level of oil production is achieved only at the expense of maintaining the reservoir pressure. More oil can be obtained through the organization of miscible displacement by rims, by increasing the proportion of mobile oil in the reservoir (reduction of residual oil saturation) and reduce oil viscosity.
Increased detail calculations of phase and component behavior in the reservoir when changing pressure and component concentration fields was achieved by performing compositional simulation, the major task of which is to correct the forecast performance for oil and gas with optimization and selection of an effective strategy for gas cycling-process in the field.
The article describes the basic steps to build and configure compositional model, assess the effectiveness of implementation miscible displacement and its infrastructure constraints based optimization, as well as the results of the comparison of accounts with similar projects worldwide. Based on the performed calculations identified potential to increase oil recovery and improve the effectiveness of field development.
Assessment of Drained Gas Reserves in the Process of Gas and Gas Condensate Field Operation in Water Drive
Authors: Glumov Dmitry N. , Sokolov Sergey V. , Strekalov Alexander V. 
Published: October 2017

Abstract
The most common method for determination of drained gas reserves is a method based on the solution of material balance equation. In case of gas drive, this equation can be solved quite simple and clear. In case of water drive, the application of classic approaches on the basis of solution of material balance equation is quite complicated. Usually these approaches are not used. The alternative approach was suggested within the framework of this paper in order to develop an express method for determination of drained reserves at water drive. This approach allows to identify the amount of invaded water in the accumulation and to estimate drained gas reserves.
Integrated Laboratory Research Procedure for Core Cavernous Samples
Authors: Vahrusheva I. A. , Gilmanov Ya. I. , Nikolaev M. U. , Zagidullin M. I. 
Published: October 2017

Abstract
Evaluation of storage capacities with a separate evaluation of vuggy components of porous-vuggy reservoir rocks is quite complicated with the use of conventional logging methods. The use of nuclear-magnetic logging (NML) makes it possible to increase the reliability of evaluation of storage capacities of such reservoirs, but to adjust algorithms for NML interpretation, it is required to perform petrophysical study of core, which in turn are complex for practical implementation under the laboratory conditions. The solution of this issue requires an integrated approach and leads to development of integrated methodology of core studies. Two methods are used as a basis: X-ray computed tomography (X-ray CT) and laboratory nuclear magnetic resonance studies (NMR).
At the first stage of the research, X-ray CT method is used to determine the cavernosity in the available whole core, on which the targeted zones are identified, and then whole core samples (100mm) are prepared. After that 100mm samples are extracted, conventionally tested to determine gas and liquid porosity, reextracted, and then samples of 50mm in diameter are drilled out to be compatible for testing in NMR-spectrometer (relaxometer). 50mm samples are restudied with the use of X-ray CT method to determine gas and liquid porosity at saturation with formation water or kerosene, after which a complex of studies is performed in NMR-spectrometer (relaxometer) to determine the total porosity by using NMR method, to identify cavernous porosity and to specify transverse relaxation time boundaries for caverns, T2cav. cutoff which are the values separating the cavernous porosity from the matrix porosity obtained by NMR curves of transverse relaxation time distribution T2. Ultimately, the methodology is based on the knowledge of cavernous porosity value, obtained by X-ray CT method on NMR curves, as a result of which it is possible to determine the value T2cav. cutoff, which can be used for determination of cavernous porosity on NMR curves. Additional methods of petrophysical studies (extraction, gas and liquid porosity) are required to obtain additional reference data on the properties of studied core samples.
The distinctive feature of this work is the study of the method combining laboratory X-ray CT and NMR, to examine oversized cavernous core samples of 50mm with the suggestion to use method based on the developed design for retention liquid in the caverns during the laboratory NMR studies, on which application for a patent was made (invention). Conclusions on the good potential of the suggested methodology were made; a list of practical remarks for further works and improvement of suggested method of laboratory studies was prepared and includes the following: design modification, account of "undesired" components in the NMR results, optimization of studies consequences.
Experimental and Theoretical Study of Microstructural Wettability of Oil and Gas Reservoirs
Authors: Mikhailov N. N. , Motorova K. A. 
Published: October 2017

Abstract
Wettability of the rock surface is an important parameter. Wettability of the rock surface is a key parameter which determines the development efficiency of any field. Effective solution of such problems as evaluation tasks of reservoir properties, simulation of two-phase filtration processes, determination of oil recovery factor, substantiation of formation and bottom oil area stimulation methods is associated with the adequacy of the existing concepts of wettability determination and the real wettability of the formation. However, the established ideas about wettability, laid down in standards and techniques, were based on research conducted in the last quarter of the XX century and currently need to be updated, as it was based on homogeneous type of wetting. Thus, substantiating of the new perception about wettability and determination methods is an actual task for effective enhancement of oil and gas fields development. In this paper the results of theoretical and experimental studies of the effect of the pore space microstructure on the hydrophobization of oil and gas reservoirs are presented. A new type of heterogeneous wettability – microstructural wettability, and a possible mechanism of formation is described here. The mechanism of the microstructural wettability formation demonstrates that hydrophobization of the inner pore space in mixed wettability can be associated either with large or small pore sizes. It was proven experimentally that the process of hydrocarbon adsorption depends on the shape, size, and distribution of pores, the mineralogical composition (particle composition and size, presence of clay), as well as on the time of contact of hydrocarbons with the inner pore surface. The concept of the hydrophilic nature of rock prior to the migration of oil into it can be considered as accurate. However, as was shown in the experiments, oil can present in the small pores (up to 10 μm), which is especially significant for the carbonate reservoirs.
Evaluation Method of Influence of Catalyst Precursors on Initiation of In-Situ Combustion and It's Dynamics
Authors: Sadikov Kamil , Larionov Victor , Varfolomeev Mikhail 
Published: October 2017

Abstract
The growing demand for energy requires alternative technologies for the development of new deposits with tar sands and heavy oil, as well as the rehabilitation of depleted, abandoned deposits. Combining all the advantages of thermal methods, the method of in-situ combustion in the presence of catalyst precursors caused interest in petroleum industry due to the possibility of upgrading or primary refining of heavy oils directly in the reservoir.
This article describes an experimental method for studying the effect of catalyst precursors on initiation of in-situ combustion of heavy oils. Thermograms in air atmosphere (combustion curves) for oil-saturated sandstones from Permian deposits in the presence of different precursors were obtained. As a precursor, resinates of copper, cobalt, iron and nickel were used. The possibility of evaluation the catalyst effect on the initiation of in-situ combustion was shown.
New Take on Mechanical Core Testing Methods and Results Interpretation for Geomechanical Rock Properties Evaluation
Authors: Zinovyev A. , Kostina A. , Maximov D. , Korelskiy E. , Samohvalov A. , Strakhov S. , Kharchenko A. 
Published: October 2017

Abstract
Within the framework of the article, detailed comparative study of Russian normative documents (GOST) and international standards (ASTM) related to elastic properties and rock strength was done. In the article, strength and weakness analysis of existing methods of core sample testing was done and necessity of their revision was shown. It was demonstrated that rock strength characteristics, such as uniaxial compression strength (UCS) and angle of internal friction (FANG), determined following GOST’s procedures, do not always meet the requirements of geomechanical modelling.
The results gathered within the scope of the study could be used as methodological foundations for triaxial compression tests (TXC). The described technique of core sample testing implies confining pressure values different from those in GOST procedures; this allows specifying the values of UCS, FANG, and elastic constants measured by core sample tests. In addition, an algorithm was developed to determine strength characteristics based on results of reinterpretation of strength failure envelopes, also known as rock strength passport, compiled according to GOST.
The study shows that the proper selection of core sample test parameters such as confining pressures corresponding to reservoir conditions is a critical consideration and is directly linked to obtaining reliable results from geomechanical modelling in the future.