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Zavyalov, Alexsandr (LLC Lukoil - Niznevolzhskneft) | Yazykov, Ivan (LLC Lukoil - Niznevolzhskneft) | Nukhaev, Marat (Siberian Federal University, Institute of Automation and Electrometry, SBRAS) | Rymarenko, Konstantin (MF-Tehnology) | Grishenko, Sergey (SIANT) | Golubtsov, Alexsandr (SIANT) | Aitkaliev, Galymzhan (SIANT) | Kabanov, Vasilii (SIANT)
Abstract This paper is aimed at the mobile gas-lift unit installation workup to shift the wells of the conductor platform of the Yu. Korchagin field to mechanized extraction instead of constructing a gas lift pipeline. The paper presents all the stages of this technology implementation, from conceptual design, engineering calculations, to the economic feasibility study, implementation and operation of this unit. During the operation of the wells of the conductor platform at the Yu. Korchagin field, the following problem occurred: a gas-lift gas pipeline was not constructed from the offshore ice-resistant fixed platform to the conductor platform, as they wanted to shift the wells to the mechanized extraction method (artificial lift). An alternative option to provide gas-lift gas to the wells of the conductor platform is to install a mobile gas-lift unit directly on an unmanned platform. This mobile gas-lift unit will be a compact separator of a gas-liquid mixture from a donor well, and it will pipe a separated gas-lift gas supply system with control and flow metering sets into the production wells. This system enables a shift of the wells of an unmanned conductor platform to a compressor-less gas-lift operation and a remote regulation of production and control over the wells operation.
Lukoil has begun wildcat drilling at an exploration well at the Shirotno-Rakushechnaya prospect structure, located north of the V.I. The well is at a water depth of 4.5 m and will be drilled to a target depth of 1650 m from Eurasia Drilling Co.'s (EDC) jackup rig Astra. The company said it also began studying the Khazri and Titonskaya features of a new block in the south part of the Caspian Sea, within the central Caspian license block in the East Sulaksky bank. It is drilling at the Khazri feature from EDC's jackup floating rig Neptune to the target depth of 5200 m; the sea is 45 m deep at the point of well. Lukoil is constructing the sixth well at a riser block platform at the Yury Korchagin field. The length of the borehole of this horizontally directed producing well is 5165 m, and daily target production is 348 mt.
Golenkin, Mikhail Yur'evich (LUKOIL Nizhnevolzhskneft) | Biakov, Aleksandr Petrovich (LUKOIL Nizhnevolzhskneft) | Eliseev, Denis Vladimirovich (LUKOIL Nizhnevolzhskneft) | Zavyalov, Aleksandr Aleksandrovich (LUKOIL Nizhnevolzhskneft) | Zhirkina, Anna Andreevna (Schlumberger) | Pico, Yamid Lopez (Schlumberger) | Shapovalov, Alexey Petrovich (Schlumberger) | Bulygin, Igor Aleksandrovich (Schlumberger) | Yakovlev, Ivan Mikhailovich (Schlumberger)
Abstract For the first time Russian oil company has applied a new generation intelligent completion system in the Caspian offshore; the system can measure zonal phasic flow rates, fractional composition of the flow, zonal water cuts, pressures and temperatures. This equipment allowed to perform well cleanup with the new strategy, making optimization in the real time. This article describes experiences of running these operations, which are unique both for the Russian and for the world industry. Since the technical resources in offshore field development are limited, it used to be impossible to run a thorough cleanup and assure the production of ERD wells at optimal level of performance. It states question about the practicability of long wells drilling. Three ERD wells in the Caspian offshore were the first ones where the Russian oil company used a unique all-electrical intelligent completion system. The system includes the flow control valve with infinite number of positions and the set of downhole sensors that provide a unique composition of measurements – pressure, temperature, phasic flow rates, fractional composition of the flow for each zone individually. Novel technology opened an opportunity to optimize the cleanup process by cleaning every zone separately. Meanwhile, it became possible to understand the extent to which every zone is cleaned and in real-time optimize the process by increasing the drawdown in the undercleaned zones. New methodology to speed up cleanup process, test and commission the well was designed. It is a crucial aspect for the wells that are drilled from an offshore drilling rig. Currently there are 5 wells in Russia and 9 of them in the world where the cleanup operations were performed with the use of described completion technology. Methodology and technology that are described in the article are innovative for the world industry. Interpretation of the expanded dataset that was obtained from the downhole sensors used to be unavailable for general use during the cleanup and it is described for the first time using an example from several wells. Practices, experiences and technology described in the article will be useful for the field engineers, reservoir engineers and specialists who make decisions related to planning and organizing the operations both for the offshore and onshore fields.
Byakov, Aleksandr (LUKOIL-Nizhnevolzhskneft LLC) | Eliseev, Denis (LUKOIL-Nizhnevolzhskneft LLC) | Senkov, Aleksandr (LUKOIL-Nizhnevolzhskneft LLC) | Shafikov, Rustem (LUKOIL-Engineering LLC) | Mavrin, Aleksandr (LUKOIL-Engineering LLC) | Lesnoy, Aleksandr (PJSC, LUKOIL) | Sibilev, Mikhail (PJSC, LUKOIL) | Bulygin, Igor (Schlumberger)
Abstract The Yuri Korchagin field is the first of the fields introduced by LUKOIL in the Northern part of the Caspian Sea. The main object of development – Neocom-Volzhskaya Deposit is represented by a thin oil rim, with the underlying bottom water over the entire area of the Deposit with a massive gas cap. Given the elongated configuration of the deposits and dimensions of the Eastern and Western parts, for drilling and production of hydrocarbons in the square fields placed one offshore ice-resistant fixed platform (OIFP) in the Western sector and the block-the conductor (BC) on the Eastern section. In order to ensure the effective development of oil rims of the im field. Yu. Korchagina and reduction of geological risks associated with the lack of detailed information on the geological structure of the layers in the locations of producing wells, the adopted system of field development by horizontal wells of large extent. In total, more than two dozen production wells with the length of horizontal wells from 450 to 4900 meters have been drilled at the field. In the conditions of the shelf field. Yu. Korchagina the most important aspect in the production of hydrocarbons is to ensure a constant and uniform flow of fluid to the horizontal barrel. The basis for this is to maintain equal depression at all points of the horizontal section and reduce the risks of gas and water breakthrough. This paper describes the evolution of the completion strategy of horizontal wells of extreme length, reveals the main characteristics of the completion systems used, the results of their operation.
Shtun, Segey (LUKOIL-Nizhnevolzhskneft LLC) | Senkov, Alexander (LUKOIL-Nizhnevolzhskneft LLC) | Abramenko, Oleg (LUKOIL-Nizhnevolzhskneft LLC) | Nukhaev, Marat (Siberian Federal University, Resman) | Mukhametshin, Ilkam (RusGazBureniye LLC) | Naydenskiy, Konstantin (Resman) | Galimzyanov, Artem (Resman) | Popova, Ekaterina (Resman)
Abstract This paper presents the experience of LUKOIL-Nizhnevolzhskneft of implementation of various completion designs and continuous monitoring systems for extended-reach horizontal wells. The article describes the evolution from stand alone sand control screens and passive inflow control devices to the introduction of multi-zone advanced smart wells with inductive coupling. In addition, the work presents experience with fiber-optic distributed temperature measuring systems and chemical tracers. Since 2010, There are a lot of advanced technologies for well completion and continuous monitoring has been introduced at the field named after Yu. Korchagin, including nozzle-based inflow control device (ICD), autonomous ICD, ICD with check valve, sliding couplings, multiposition couplings, interconnected sand screens, fiber optic systems, chemical tracers, hydraulic and electric smart wells. The application of some technologies turned out to be limited in the conditions of the field named after Yu. Korchagin, part of the technologies had limited implementation due to the long length of horizontal wells, and some technologies showed unique benefits and were recommended for further wide implementation. Pilot projects of some technologies, as well as the use of various completion systems and continuous monitoring systems at the wells of the Yu. Korchagin field, allowed LUKOIL-Nizhnevolzhskneft not only to solve current operation problems, but also to select optimum technologies for usage in the following fields of Caspian shelf.
Golenkin, Mikhail (LUKOIL-Nizhnevolzhskneft) | Khaliullov, Ildar (LUKOIL-Nizhnevolzhskneft) | Vereschagin, Sergey (Schlumberger Logelco, Inc.) | Ovsyannikov, Dmitry (Schlumberger Logelco, Inc.) | Kobets, Vladimir (Schlumberger Logelco, Inc.) | Kulinich, Nikolay (Schlumberger Logelco, Inc.)
Abstract Yuri Korchagin field, located in the Russian sector of the Caspian Sea, is one of the largest field on the Caspian shelf with proven reserves stand at 29 million tons of oil and 63 billion cubic meters of gas. Since the beginning of commercial operation, in the spring 2010, the field production passed eight million tons of oil. The operator company conducts development of Yu. Korchagin field by a system of horizontal wells with a length up to 8000 m, from a fixed offshore ice-resistant platform, installed in the dome area of the structure. The main challenges in the field development are associated with premature water and gas breakthroughs at high permeability intervals of horizontal wells. Currently, as a result of the sharp increase in the field water cut, the oil production is constrained due to the existing limitations on volume of produced water that can be utilized in the conditions of the offshore field. Two water-injection wells were drilled and commissioned to utilize produced formation water into the aquiferous zone of the carbonate reservoir. In order to restore and increase the injectivity factor, small-volume acid treatments are carried out yearly on the carbonate reservoirs in the lower horizontal sections of the water-injection wells. Since 2014, more than 20 matrix and hydrochloric acid treatments were performed with application of acid systems of different compositions and volumes. In some cases, the wells injectivity increase after matrix acidizing treatments with traditional acid systems was below expectation, demonstrating limited and short-term effect. Therefore, with constantly increasing volume of produced water at the field, it was required to increase the frequency of acid treatments to maintain the appropriate level of injectivity of the water-injection wells. The additional treatments are associated with significant time and financial costs because of the offshore platform standby and production suspension. The need exists to improve efficiency of acid stimulation treatments performed in the field to achieve sustainable increase in injectivity index of existing wells. The purpose of this study is to analyze acid stimulation treatments carried out on carbonate reservoirs of the horizontal water-injection wells in 2014-2017, evaluate the efficiency of the treatments with different acid systems to change the injectivity factor, discuss the prospects for their application in Yu. Korchagin field and formulate recommendations for further efficiency improvements of acid stimulation treatments in the field.
Shtun, S. Y. (LUKOIL-Nizhnevolzhskneft) | Senkov, A. A. (LUKOIL-Nizhnevolzhskneft LLC) | Abramenko, O. I. (LUKOIL-Nizhnevolzhskneft LLC) | Matsashik, V. V. (LUKOIL-Nizhnevolzhskneft LLC) | Mukhametshin, I. R. (RESMAN Rus LLC) | Prusakov, A. V. (RESMAN AS) | Nukhaev, M. T. (Siberian Federal University)
Abstract The purpose of this paper is to compare the permanent monitoring systems based on optical fiber systems and intelligent chemical tracers. This analysis was carried out based on an operational assessment of similar systems for permanent monitoring of horizontal wells in the Yuri Korchagin oilfield for 3 years in various regimes of operation. The paper discusses the main advantages and limitations of these systems and provides their comparison to conventional production logging tools (PLTs).
Skobeev, Andrey (LUKOIL-Nizhnevolzhskneft LLC) | Senkov, Alexander (LUKOIL-Nizhnevolzhskneft LLC) | Danilko, Alexey (LUKOIL-Nizhnevolzhskneft LLC) | Volkov, Vladimir (LUKOIL-Engineering) | Akhmadiev, Ruslan (Lukoil Upstream West)
Summary The requirement of the use of models in the of oil and gas condensate fields development is determined by the legislation of the Russian Federation with regard to application of hydrodynamic models. Thus, an absolute majority of oil and gas companies create and use topical hydrodynamic models within the existing legislation. However, if we talk about the practical application of models for solving the applied problems of developing oil and gas condensate fields, the use in calculations only hydrodynamic models will not allow taking into account the characteristics of used downhole equipment, gathering and processing system Application of integrated approach permits to link "reservoir-well-gathering facilities" as a single whole. An integrated model is a model that combines all the key components of field development, such as a productive formation, wells and a collection network. The decision to create an integrated model was the need for an operative change in the operating practices of the well stock operation in the conditions of technological limits during operation of technological complex. It is expected that the integrated model will allow to calculate the production of liquid, oil, gas, taking into account all the constraints in the existing production system, and also to estimate design capacity of newly developed fields. Additional requirements have been introduced for the integrated model: it must be expandable (for further use of the model of target reservoir), the time of full modeling and forecasting for a month should not exceed more than 24 hours. This article is an example of the construction and application of an integrated offshore field model. Within the example, the field includes two production targets that have a hydrodynamic relationship between themselves. The following functional areas were identified for which it is planned to use integrated modeling as applied problems:Production plan optimization; Development of operating practice for production wells; Development of 24-hour forecast for a month in respect of production wells; Modeling of the current and newly commissioned fields; Evaluation and updating parameters of well performance; Engineering of downhole equipment and process equipment and etc.; The article describes the main problems encountered by specialists of LUKOIL-Nizhnevolzhskneft LLC in integrated modeling development/actualization, as well as examples of its use for solving applied problems. In the course of the project, a common methodology was developed for the making/updating a single integrated modeling, uniting a reservoir model, well models, collection systems and reservoir pressure maintenance. Application of PVT Black Oil was reasoned both for the reservoir and wells. Results of PVT-modeling were applied in multiphase flowmeter as well. A consolidated reservoir model was made consisting of two production targets. This model was successfully adjusted for the production history and adequate forecast for reservoir pressure were demonstrated. Well models were calibrated based actual data of multiphase flowmeter, borehole and surface transmitters (oil production, liquid rate, gas rate; wellhead pressure, line pressure, bottom hole pressure; line and BHT), well test results (reservoir pressure, production ratio). Well bore fluid in the gathering network was modeled with Black Oil. Elaborated integrated model demonstrated consistency in description of PVT reservoir fluid properties. Integrated model was used to complete the following process tasks: Production plan optimization; Development of operating practice for production wells; Modeling of ICD completions and optimization; Gas lift system engineering; Optimization of well connection to separation stages.
Abstract The first installation of intelligent tracers system in extended reach horizontal well was deployed by LUKOIL-Nizhnevolzhskneft LLC in a thin oil rim reservoir with a large gas cap located in the North region of the Caspian sea. Putting in operation of the Yu. Korchagin field is challenging serious tasks during development:relative zone inflow estimation; identifying intervals of water breakthrough; long-term monitoring of oil extraction and water level; monitoring of completion equipment functionality. Traditional technologies of production logging, considering complex well trajectory, are highly risky and expensive. Fiber-optic system of monitoring of Distributed Temperature Sensors (DTS) would be an ideal instrument identifying the source of gas breakthrough, but such technology is not always feasible due to necessity of rotation of the completion during its running in extended reach horizontal well. Performance of periodic field research via cable is limited due to drilling operations on the platform. In addition to perform such survey it is required to use downhole tractors to transport logging tool. Practice of tractors usage in extended horizontal wells in the field has a negative statistics to reach the toe of the well, as for a project operator it's important to verify remote flow contribution (e.g. 7000 m) in total well flow rate. To solve the above problem a relatively new monitoring technology has been applied. At stage of equipment fabrication downhole intelligent chemical sensors were installed in sand screens. Sensors are placed in the drainage area in different intervals along the well to meet objectives by the engineers of LUKOIL Nizhnevolzhskneft LLC to provide flow profiles, identify the location of gas breakthrough and confirmation of the functional work of AICD in the course of time. After selection of surface samples of hydrocarbons at the wellhead, a laboratory analysis is conducted for chemical tracers in the sample and interpretation of tracer signals during unsteady and steady state production is performed. Some period has passed related to operation of the well after its start. The first well equipped with intelligent chemical indicators has its history of production; the well performance can be evaluated both in whole, and for each zone equipped with chemical indicators. This paper will review the experience of wireless monitoring for extend horizontal well on the shelf of the Caspian sea.
Delia, S. V. (Oao Ritek) | Chertenkov, M. V. (Ooo Lukoil-Engineering) | Zhakovschikov, A. V. (Ooo Lukoil-Nizhnevolzhskneft) | Matsashik, V. V. (Ooo Lukoil-Nizhnevolzhskneft) | Zhuravlev, O. N. (Ooo Wormholes) | Shchelushkin, R. V. (Ooo Wormholes)
Abstract This article reports the results of field testing of new generation flow control system (ICD) carried out in wells No. 128 of the Kotovskoe Field and No. 11 of the Yu. Korchagin Field by OOO LUKOIL-Nizhnevolzhskneft. The new well completion system reported herein has been developed and is manufactured in Russia. Its distinctive feature is the possibility of adaptation to production conditions and producing additional impedance for the passing gaseous phase regardless of pressure drop for the liquid phase. The new ICD significantly reduces the gas factor and prevents free gas breakthrough in the oil well. This article also reports the results of bench testing carried out at the flow control system development stage. Further the equipment was installed into the wells as a recompletion system. We present results of daily average gas and oil rate measurements before and after the installation of the flow control equipment. The tests were run in different well operation modes.