bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Fracture Azimuth in Palnikovskoye Field Western Siberia Using Tiltmeter Technology
Authors: Mironov V. S. , Diyashev I. R. , Brovchuk A. V. , Stanley G. R. , Davidson B. M. 
Published: October 2008

Abstract
Knowing the direction or azimuth of the fracture orientation is important in development of a low permeability reservoir with horizontal wellbores. The orientation of the horizontal wellbore will determine if the hydraulic fractures are longitudinal or transverse to the wellbore. The angle of the wellbore to the hydraulic fracture not only affects the recovery factor from the reservoir, but also influences the completion strategy.
The objective of this project was to measure the azimuth of the far field fracture during hydraulic fracture treatments to determine the preferential fracture direction. Prior to the mapping project it was assumed that preferential fracture orientation in Palnikovskoye filed is North-South. Initially the orientation of the horizontal section of the well 436 was designed transverse to the plane of fracture propagation.
Using an array of 42 Surface Tiltmeters the fracture azimuth was measured during the hydraulic fracture treatments performed in the Palnikovskoye Field, Western Siberia. The fracture azimuth measured with the tiltmeters was different than estimated in the field development plan. Therefore, the direction of the horizontal wellbore was altered so the fracture would propagate transverse to the wellbore.
Application of this technology is important in any field where fracture stimulation is important to field development. This was the first deployment of tiltmeter mapping in Russian Federation, several modifications were made for the standard procedures that have been developed from mapping thousand of fracture treatments in other parts of the world. Future fracture treatments in Western Siberia can now be mapped in a more efficient manner.
First phase of the project included hydraulic fracture mapping on three vertical wells to estimate fracture orientation, and use this data to optimize drilling direction of the lateral in horizontal well. The second phase included hydraulic fracture mapping of five stages in the horizontal wellbore.
Gas Drainage Reserves Evaluation Based on Specific Reserves Per Well
Authors: Kolbikov Sergei 
Published: October 2008

Abstract
Gas reserves estimation based on the actual well production data has a particular interest due to big spacing for gas fields. Proposed method is based on the differential equation of specific reserves depletion and uses mostly primary well production data. The method was proved on the results from numerical modeling for different reservoir quality and time dependent well completions.
An example of the method application to an actual field development is described with analysis of drainage volume variations in time. The method allows to calculate the values of drainage volumes as a function of time for individual wells, group of wells, pools. Calculation of drainage reserves of the pool in time allow to verify geologic reserves, estimate an effectiveness of its development.

Summary
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Why Dual Porosity Models are not Applicable for Simulation of the Near-Wellbore Zone of Gas Condensate Well for Naturally Fractured Reservoirs
Authors: Rudenko D. , Shandrygin A. , Zyryanova A. 
Published: October 2008

Abstract
The peculiarities of retrograde condensation in the near wellbore region in naturally fractured formation were studied with the use of dual-porosity/dual permeability models and the direct numerical simulation based on the "Sugar Cube"19 representation of the fractured porous media. Serious spatial inhomogeneity of the saturation distribution in porous matrix blocks was demonstrated. Dual porosity/permeability models are obviously unable to reproduce spatial condensate distribution in near wellbore zone of the reservoir but after proper tuning these models can be used for the simulation of the well production profile in naturally fractured reservoir and of the flow picture in the near wellbore zone in general.
Definition of Oil Displacement Mechanism at Field Development
Authors: Karnauhov Mihail , Gaponova Larisa , Klimov Mihail , Piankova Elena 
Published: October 2008

Abstract
The definition of oil displacement mechanism is one of major questions in problem of reservoir processes: or as mixed oil-water flow, when oil and water phase relative permeability (kro and krw) of water flood zones are specified; or as piston flow, when takes place frontal drive of oil by stream of approaching water.
Phase relative permeability for water and oil are usually defined on the basis of learning filtering of oil-water mixtures through a core. Just on the basis of such experiments the curves of phase relative permeability to oil and water are performed, which then used in the different design documents and projects of field development.
At the same time it is known, for example, that using modern methods of engineering inclusive reservoir simulation model are large difficulties at history matching with applying of such relative permeability curves of filtered fluids. Frequently forced variation of parameters of filtering at history matching results in concurrence of calculated and actual indexs to development at final parameters of filtering much distinguished from source, obtained in laboratory conditions.
It is necessary to mark also, that in the literature last years many papers have appeared that the core is a poor material that only on its basis to plan field development because of unrepresentative of coring, as a result of which it does not mirror property of all reservoir system; high created gradients of stresses at studies in laboratory conditions as contrasted to actual; strictly oriented directivity of flow of fluid through a core with impossibility of an estimation of anisotropy of formations on permeability and etc.
In a paper the features of extraction of oil reserves on some fields of Western Siberia are reviewed. Is shown, that as a whole on fields there are complex processes of fluid flow, where are formed as regions of water inrushes with consequent catastrophic watering out of individual wells, and zones of oil displacement with waterless wells, working a long time, and recovery of reserves in such zones much greater, than initial oil reserves in drained areas of these wells. It is impossible to explain by widespread assumptions about influencing reformative phase relative permeability or complex heterogeneity of oil reservoir. Formed zones of oil displacement to durable waterless operation of wells, as a rule, are connected with frontal drive. The examples of operation of some horizontal wells with high oil recovery factor (more than 0.5) in area of their drainage. The results of numerous production and injection well testing and conducting of hydrolistenings testify to such nature of water-oil displacement.
The concrete offers on rational field development methods are made, when the piston condition of water-oil displacement is organized predominantly.
Features of Oil Fields Development by the System of Multilateral Horizontal Wells, Practical Experience
Authors: Klimov Mikhail , Karnauhov Mikhail 
Published: October 2008

Abstract
This paper summarizes practical results of oil fields development by multilateral horizontal wells. By the example of Severo-Yangtinskoe and Chatylkynskoe oil fields the whole cycle of works from well-planning to development monitoring is described.
Severo-Yangtinskoe is one of the newest oil fields operated by the Company. Field Development Project regulating its development was drawn up and approved in Central Development Commission in 2006 after that production drilling of the main object began. All project decisions are based on reservoir simulation model. According to FDP, development scheme involves irregular placement of horizontal and subvertical wells.
Severo-Yangtinskoe reserves may be classified as difficult to recover; in practice it is problematic to involve such a deposit into development by conventional subvertical well schemes. During the two-year period of field development 8 horizontal wells have been successfully drilled and put on production, of which 3 are multilateral, that is the latest well completion technology probe-tested in the Company. This technology has been put into practice on the other Company's oil fields. Present work demonstrates and proves the advantages of complex reservoirs development by dual horizontal wells.
Chatylkynskoe oil field is also one of the newest Company's assets. FDP regulating the development was composed and defended in Central Development Commission in 2006. The pilot project specifies horizontal wells application as well as marginal waterflooding by deviated wells for the field development. The main reservoir has significant thickness, but its geological structure is complicated by tectonic disturbances and heterogeneity. All the decisions worked out are based on a reservoir simulation modeling. During the period 2006 – 2008 7 horizontal wells have been successfully drilled, 5 of which are dual wells.
Solution of Problems of Water-Gas Influence (WGI) on the Layer Using Jet and Electrical Centrifugal Pumping Technology
Authors: Drozdov A. N. , Telkov V. P. , Egorov Yu. A. , Verbitsky V. S. , Dengaev A. V. , Lambin D. N. , Krasilnikov I. A. 
Published: October 2008

Abstract
Waterflooding – is currently the most popular method of oilfield development, but very often it does not guarantee high development effectiveness. This fact is the significant problem taking into account that the amount of hard to recover reserves is being increased constantly. The combined water and gas injection to the layer enables us to essentially increase the oil recovery ratio. Use of associated gas for water-gas influence also enables us to solve a problem of its utilization.
About 100 field applications of WGI are known since this technology was used in North Pembina (Canada 1957 year) for the first time, and only single cases failed.
Today, different technologies of WGI are applied that can be classified in two ways: alternate or simultaneous injection of water and gas (WAG or SWAG Injection). However, traditional ways of applying WGI were not widespread in Russian oil fields, but instead significant amounts of associated gas were flared.
WAG compressor technology requires the purchasing of import equipment, essential investments in the initial stage, and high operating costs. Besides compressor stations, the construction of gas treatment plants is required.
The separation of rich fraction from associated gas is required for the proper work functioning of compressors. These fractions are not always utilized and than the usage of dry gas for WGI it is less effective in terms of increasing oil recovery.
TNK-BP Idle Well Stock Reactivation Program
Authors: Manapov T. , Alekseeva V. , Zhigalov V. , Aksenov M. 
Published: October 2008

Abstract
Large inactive well stock is one of the factors complicating current Russian oil field development process. As per 1 January 2008, the Russian Federation IWS amounted to over 26000 oil wells. Long-continued inactivity of a large well number reduces potential of development optimization and oil recovery enhancement methods, deteriorates production and economic performance, increases environmental impact risks.
IWS re-activation requires complex well servicing involving water isolation, fishing, sidetracking etc. Therefore, idle stock reactivation efficiency, as a rule, is lower than that of active well interventions. In these conditions particular emphasis is placed on selection of methodology for dealing with IWS, which considers retention of the project development system, achievement of maximum oil recovery factor and improvement of the field development cost-performance ratio.
A comprehensive TNK-BP Idle Well Stock Reactivation Program was developed within the frame of Company's strategy, to reach the following objectives:
– by end of 2013, to reduce IWS to the amount close to the standard (10%); – complete license obligations fulfillment in the part of drilled well-stock utilization, including solutions of the approved project process documentation; – application of advanced technology to re-activate idle wells and enhance their performance.
The article considers results of comprehensive Idle Well Stock Reactivation Program implementation, describes examples of idle well reactivation and design technology / project development system recovery technology implementation, and identifies ways to improve performance. It is demonstrated that even in conditions of high depletion ratio and extremely high watercut, substantiated use of modern technologies allows to guarantee efficient production of remaining oil reserves.
A Sedimentologic Model for Lower Cretaceous Sediments Within the Northern Portion of the Surgut Arch as Exemplified by the BS102 Zone
Authors: Supolkina I. V. , Saratinyan L. V. , Kozhevskikh A. S. , Gorbunov A. A. 
Published: October 2008

Abstract
Due to decrease in oil reserves caused by their depletion new exploration activities and development targets are required. One of such development targets is the BS10 zone. The origin of the BS102 zone is the object of the present report.
The BS102 zone confined to Lower Cretaceous sediments is the most productive among pay zones within the northern part of the Syrgur arch. In terms of geology the zone is very complicated. Exploratory drilling in the Severo-Konitlorskoye, Severo-Kochevskoye, Kochevskoye and Tevlinsko-Russkinskoye oil fields made possible to reveal different water-oil-contacts of different level. This means that hydrocarbon accumulations in the BS102 zone are hydrodynamically separated. Due to variations in depositional environments the deposits of the zone are characterized by lithology substitution, pinchind-out, variations in thickness of lens-shaped bodies the zone is composed of as well as variations in reservoir properties.
The study area is located in the Surgut region of the Khanty-Mansi Autonomous okrug, 150 km north of the city of Surgut. From a tectonic point of view the area is confined to the northwestern part of the Kogalym uplift which is supposed to be the 2nd structure order. In the north this structure complicates the Surgut arch - the 1st order structure. The area is investigated by various types of exploratory activities. They include geomorphologic, airborne magnetic surveys, exploratory and development drilling, and 2D, 3D seismic surveys.
Reservoir Parameters Evaluation Based on Production Data Analysis
Authors: Khasanov Mars , Krasnov Vitaly , Guk Viatcheslav 
Published: October 2008

Abstract
Evaluation of reservoir properties such as permeability, formation pressure and skin factor by means of welltest data interpretation is widespread. Usually these tests are implemented using pressure build up technique which leads to production losses. This fact makes regular well tests conductions to be undesirable by operators.
Another opportunity for reservoir parameters evaluation is given by transient period of well operation, the one starts after a new well start up and lasts until the pressure disturbance reaches the boundaries. In case when transient period lasts long enough (Priobskaya field) and production regimes are logged regularly, using this data seems to be reasonable.
A new approach to permeability, reservoir pressure and skin factor evaluation by production data analysis is presented in this study. This approach is based on broadening of the NODAL analysis concept onto transient case. The system operational point on the NODAL analysis plot is an intersection of inflow performance relationship curve and lift performance curve. During the transient flow regime, inflow performance curve changes with time. This allows developing expression for productivity index variation with time as dependent on permeability and skin factor. Matching the model curve of rate-time dependence to the actual curve allows resolving a system of equations containing reservoir parameters as unknowns.
Proposed method is approximate. A comparison to the rigorous solution for linear inner boundary condition is given. The results of calculation by proposed method were shown to be in good agreement to the ones obtained with the analytical solution. The case study including comparison to the build-up test also showed good performance of proposed method.
Implementation of the method proposed in this study allows, in particular, performing identification of transient regime, defining and ascribing production change to influencing factors and planning production optimization.
Hydrodynamic Reservoir Simulation of Prediction Cases
Authors: Moiseevich Olenchikov Dmitry , Rustamovna Kruglikova Ludmila 
Published: October 2008

Abstract
In the report the analysis of the basic difficulties of prediction cases hydrodynamic modeling is executed. It is offered to describe prediction cases not in terms of simulator key words, but in terms of events and patterns of actions. It will raise the quality of prediction cases and will reduce time necessary for its designing. Also it will free the reservoir management engineer of necessity of detailed studying numerous simulator key words.
Main Tendencies of the Sweep Efficiency Improvement Evolution in Russia
Authors: Shandrygin A. N. , Lutfullin A. 
Published: October 2008

Abstract
The sweep efficiency enhancement technologies applied in Russia were analyzed. It was shown that the most common sweep efficiency enhancement techniques are sidetracking, non-stationary flooding and different flow-diverting technologies, based on chemicals injection, restricted by volume. In some cases, hydraulic fracturing can be considered also as a means to improve the sweep efficiency by treatment. The case histories of all treatment techniques specified in the paper are presented and trends of their development in the future are identified.
Hierarchy of the Integrated Models
Authors: Khasanov M. M. , Afanasiev I. S. , Latypov A. R. , Pavlov V. A. , Antonenko D. A. , Surtaev V. N. 
Published: October 2008

Abstract
The end of an «easy oil times», realization of expensive projects on developing fields in the remote from infrastructure areas, with severe climate and complicated topographical conditions, raised new challenges for the field development engineering. First of all, it is related to a necessity of developing a general of field preparation prior to the detailed design and construction works.
A standard approach to field development projects is based on a series of calculations on different scenarios for reservoir development, facilities construction together with economical evaluation. As practice shows, selection of optimal reservoir development scenario, irrespective of surface facilities issues, or selection of optimum surface facilities case, calculated without taking into account reservoir performance, eventually, do not provide optimal economic indicators for the entire system. Considering this interrelation, it is not possible to transfer sensitivity analysis for parameters of one system into another and, ultimately, economical indicators of the project.
All this confirms that the effective, self-consistent solutions can be developed only using the integrated approach considering all aspects, affecting technological and economical field development indicators. To fulfill these objectives, Rosneft Oil Company implemented the integrated approach to field development engineering.
In this article, we introduce a concept of the integrated model hierarchy, allowing classification and reservoir model construction and design process facilitation depending on problem complexity. Various models application is demonstrated on the example of one of the largest Rosneft's new fields.
High GLR ESP Technologies Comparison, Field Test Results
Authors: Bedrin V. G. , Khasanov M. M. , Khabibullin R. A. , Krasnov V. A. , Pashali A. A. , Litvinenko K. V. , Elichev V. A. , Prado M. 
Published: October 2008

Abstract
One of limitations of achieving full potential in pumped wells is due to the presence of excessive free gas at pump intake. The presence of free gas at pump intake has several effects on the pump performance. A reduction in the pressure drop developed by the pump is usually observed when pumping multiphase flow mixtures. This performance reduction sometimes may be severe, resulting in unstable pump operation, production losses and may lead to premature equipment failure.
Electric submersible centrifugal pumps (ESP) are commonly used in Russia and other parts of the world for oil production. Currently operators are being required to produce wells under non conventional and challenging operational conditions. One of such conditions is the use of ESP in wells with a high free gas liquid ratio that requires the use of special technology. Under those circumstances it is very important to understand more profoundly the processes of ESP operation as any mistake in the equipment design may have severe economical consequences. One of the crucial information needed is the technical limiting operational conditions for different ESP technologies when handling high gas liquid ratio mixtures.
Determination of the technical operational envelope is itself a challenge. Experimental work conducted in Universities and industry research centers are very important for an understanding of the problem and advance of the technologies. But it is difficult to recreate in the lab the same conditions that exist in a well bore. Working with actual fluids at high temperatures and pressures are still challenging conditions to be reproduced in the lab. Therefore theoretical models, experimental correlations manufactures technical guidelines need to be verified against the conditions existing in a real oil well.
This work presents the conclusions of the use of state of the art engineering methods describing the reservoir-pump-production system to analyze the performance of gas handling technologies based on real well field test results. The field tests were conducted under the New Technologies System project of Rosneft Oil Company. Field tests estimated technical limits for ESP gas handling technologies for up to 75% of volumetric gas fraction at pump intake conditions, as well as confirmed the possibility of oil production enhancement with the tests (the NPV for 11 ESP tested was more than 40 mln. rubles in 2007). It is estimated that more than a 100 wells would benefit from ESP gas handling technologies in Purneftegas alone, yielding significant economic impact for the company, increasing oil production by more than 700 tons/day.