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Gazprom's oil-focused subsidiary Gazprom Neft has signed a memorandum of understanding with AIQ, a joint venture between the Abu Dhabi National Oil Company (ADNOC) and the UAE-based cloud computing firm Group 42. The firms seek to jointly develop and commercialize digital solutions for the upstream oil and gas industry in Russia and the Middle East. The partners pledged to develop tools for oil and gas exploration and production using cognitive technologies that cross the spectrum of algorithms, robotic process automation, machine learning, natural language processing and generation, and artificial intelligence. This is according to Gazprom Neft's Science & Technology Center, the company's research and development arm. ADNOC and Group 42 created the AIQ joint venture in 2019 to commercialize advanced programming solutions specifically for the oil and gas industry.
When classifying the process of oil dehydration for preliminary assessments of the technological parameters of its treatment at various stages of the design and development of oil fields, it is necessary to take into account regional differences, starting with the geographical and geological location of oil deposits and the conditions of their occurrence, ending with the features of the physicochemical properties of reservoir fluids extracted to the surface. On the example of a number of fields in the Samara region, the dependence of the change in viscosity when changing from reservoir conditions to surface conditions is built, a comparative grouping of oil by viscosity in reservoir and surface conditions is considered, consistent with the classification of oil to assess the parameters of its preparation simultaneously in terms of density and viscosity in surface conditions. A conditional comparison of the classification parameters and the required temperature of the emulsion during oil dehydration to a residual water content of 10 wt% (preliminary dehydration) and 0.5-1 wt% (deep dehydration) was carried out according to various literature sources. It is proposed for the range of Paleozoic production of oil wells in the Volga-Ural oil and gas province, in addition to assessing the generally accepted characteristics of oil density and the content of paraffin in it, to select technological parameters for oil treatment, additionally use the relative indicators, taking into account the unique properties of highly mineralized reservoir waters and the heterogeneous hydrocarbon composition of the oil itself. On the basis of the introduced characteristics, the classification of oil dehydration of a number of fields in the Orenburg, Samara regions and Siberia is considered. A comparative assessment of the quality of wastewater treatment was carried out taking into account two calculation methods based on the properties of the separated phases, taking into account the mentioned characteristics, as well as the oil density and the specific load on the interface of the apparatuses for the combined preparation of oil and water.
Karmushin, S. R. (Gazpromneft STC LLC) | Lezhnev, K. E. (Gazpromneft-Digital Solutions) | Gumerov, R. R. (Gazpromneft STC LLC) | Bazyrov, I. Sh. (Gazpromneft STC LLC) | Gunkin, A. S. (Saint-Petersburg Mining University) | Gvritishvili, T. T. (Gazpromneft-Orenburg LLC)
The purpose of this work is to increase the efficiency of well killing operations for carbonate fractured porous reservoirs with high gas factor, the presence of hydrogen sulphide, and abnormally low formation pressure. Well killing in such conditions is complicated by large losses of technological well killing fluid, which provokes gas kick. In this regard, the calculation of a sufficient well killing fluid volume for operations with a high gas factor in conditions of abnormally low formation pressure is an urgent task, which, along with technological and economic efficiency, should increase the safety of repair work on wells. To solve this problem, a model of filtration of non-Newtonian fluid in the borehole zone was proposed. In the course of this work, the Herschel–Bulkley fluid flow was simulated in a porous medium and in a fracture, and a statistical analysis of field data was performed for comparison with the results obtained by the model. The physical and mathematical model used in this work was built based on continuity equation of the flow and the law of conservation of momentum. As a result, the dependence of the injected well killing fluid volume on the repression applied to the reservoir during the well killing operation was derived. Based on the constructed model, key parameters were obtained which allow us to estimate a fluid volume for successful well killing operation. Then the field data was selected, and statistical analysis was carried out using the parameters identified in the initial model. The retrospective analysis showed good convergence of filed data with the results obtained on the basis of the proposed methodology, which confirmed its validity. As a result, a method for well killing fluid volume estimation was proposed for the conditions of fractured porous reservoirs. It is fair to consider the ratio of the volume of the technological fluid that went into the formation during a successful well killing operation to the repression created during the operation as a criterion for the effectiveness of the use of well killing fluid. This parameter depends on the rheology of the fluid and on the rock filtration-volumetric characteristics. Thus, the proposed analytical model with a simple method for well killing fluid volume estimation allows to predict the parameters for each well killing operation. This methodology can be scaled to other porous and fractured-porous reservoirs.
The overwhelming majority of natural gas fields are at the final stage of development, which, along with other features, is characterized by selective watering of productive deposits and production wells. The difficulty of extracting residual gas reserves under such development conditions is associated with depletion of productive reservoirs, accumulation of fluid at the bottom of wells, corrosion of downhole equipment and the inability to reduce wellhead pressures due to restrictions on the supply and preparation of hydrocarbon products with the existing surface infrastructure. Production wells in conditions of formation water inflow into productive deposits are decommissioned after relatively small gas withdrawals. This is due both to the insufficient implementation of methods for intensifying the removal of fluid from the bottom of the wells, and to the peculiarities of the arrangement of fields, which are usually not designed for the collection and preparation of hydrocarbon products with a high liquid content. In order to remove the gas-liquid mixture from the bottom of the wells, many techniques and inventions have been developed that are widely used in production. The developed technologies are characterized by different efficiency and have a number of technological limitations, mainly due to the peculiarities of the geological structure of hydrocarbon deposits. Considering the above, there is a need for additional research in order to improve the existing and develop new technologies for the operation of water cut wells. Using the special software package, studies were carried out to optimize the operating conditions for a water cut well under conditions of active formation water inflow into gas-saturated horizons. The study was carried out for various depths of gas-lift valves (3500 m; 3000 m; 2500 m; 2000 m; 1500 m; 1000 m) and liquid flow rates (22.5 m/day; 33.75 m/day and 45 m/day). Based on the research results, graphical dependences of gas flow rates and bottomhole pressure on the amount of gas-lift gas were built; the maximum gas flow rate and the required amount of gas-lift gas from the liquid flow rate; maximum gas flow rate versus liquid flow rate at different depths of gas-lift valve installation. Based on the results of statistical processing of the calculated data for each value of the liquid flow rate, the optimal value of the depth of the gas-lift valve was established. According to the results of the studies performed, to ensure the stable operation of high-water cut gas wells, it is effective to locate the gas-lift valve at a distance of 55-58 % from the wellhead of the tubing (2033-2137 m).
Belyakov, Alexander Alexandrovich (Orenburgneft) | Gulyaev, Danila Nikolayevich (Sofoil) | Krichevskiy, Vladimir Markovich (Sofoil) | Nikonorova, Anastasia Nikolaevna (Sofoil) | Iskibaev, Roman Edisonovich (Sofoil)
Abstract The analyzed oi- gas field is based around Orenburg region, located 40 km away from the Buzuluk city, Russia. This multi-layered field has a number of domes. 11 productive layers lie within its cross-section. In total, 21 oil and two gas deposits have been identified at this field. The study layer A4 is confined to the top of the Bashkir layer and has a wide extension. Permeable rocks at this layer include limestone and dolomite, separated by impermeable sublayers. The effective oil-saturated well thicknesses vary between 1.1-38.4 m, and is 11.8 m on average. The caprock of the formation A4 consists of the Vereiskan clay-siltstone sequence.
Rogov, Yuri (LLC Gazpromneft-Oreburg) | Rymarenko, Konstantin (MF-Tehnology) | Mironositskii, Alexei (Institute of Automation and Electrometry SBRAS, SIANT) | Grishenko, Sergey (SIANT) | Golubtsov, Alexsandr (SIANT) | Kabanov, Vasilii (SIANT) | Gusachenko, Tatyana (SIANT) | Nukhaev, Marat (Siberian Federal University, Institute of Automation and Electrometry SBRAS)
Abstract Environmental stability and safety are becoming increasingly important in the world. Used to be mainly until recently under state control, the release and distribution of hazardous substances, wastes, and by-products is now monitored and regulated everywhere by enterprises, forced to establish special services that record and transmit information in the dispatch centers of the MES and other regulatory authorities of the Russian Federation. All the measures taken in this respect focus on safety improvement, ensuring occupational safety and accident prevention at enterprises, and safety of people, animals, and natural environmental location, which can be exposed to harmful and dangerous anthropogenic and natural factors. Aiming to provide a comprehensive solution to the problem, the authors proposed the concept of environmental monitoring and control over oil and gas wells using automated control and regulation systems and presented the concept on the example of the Orenburgskoe oil and gas condensate field
Sarapulov, Nikolai Pavlovich (LLC Gazpromneft STC) | Vasin, Maxim Valerevich (LLC Gazpromneft STC) | Palandzhyants, Andranik Sedrakovich (LLC Gazpromneft-Orenburg) | Tambovstev, Evgeni Alexandrovich (LLC Gazpromneft-Orenburg) | Khabibullin, Rinat Alfredovich (LLC Gazpromneft STC)
Abstract The article is devoted to the selection of a specialized configuration of submersible equipment to minimize downhole pressure in order to intensify the flow of fluid to the wells of Gazpromneft-Orenburg. The depth of the wells and the design features of the well do not allow sufficient depth of the pumping equipment (top of the perforation interval 3800-4200 m). In addition, the operation of the fund is complicated by abnormally low reservoir pressures (60-120 at), low filtration-capacity properties and high linear pressures of single-standing wells (20-30 at). To increase the productivity of wells, the ESP layout was used with a two-way engine, two submersible pumps and a shank. The layout is chosen in such a way as to reduce the density of the liquid column under the pump due to the circulation of the liquid by the lower pump. A special feature of the design was the selection of the length and the limit of the descent of the shank, the ratio of performance and pressure of the upper and lower pumps and a number of pre-connected devices as part of the layout. Pilot tests were conducted at three wells of the Gazpromneft-Orenburg field. After the installation and commissioning work in the process of bringing the wells to the established mode, the features of the ESP that differ from the standard operation, leading to an increase in the period of stable well production, were revealed. According to the results of the tests, an increase in the oil flow rate of an average of 16 tons per day was obtained. The study of the characteristics of a complete installation directly on the test wells allowed us to determine the technical capabilities of the equipment, the volume-flow characteristics of the fluid under the pump and PVT. The aspects of natural separation and free gas content at the inlet of both pumps are studied, which is also a boundary condition for well intensification. The tests allowed us to assess the technological limit of the layout with two ESP in the conditions of the Gazpromneft-Orenburg field. In contrast to other options for the operation of hard-to-recover wells, the proposed layout has a number of advantages, such as a minimum increase in the cost of construction, simplicity of construction, which ensures high operating time of equipment and low specific energy consumption. Based on the results of testing the pilot installations, a decision was made to replicate this approach in the Company.
Abstract Well construction in the Volga-Ural Region faces different sorts of complications, the most common ones being the loss of drilling fluids and rockslides. Such complications may cause considerable financial losses due to non-productive time (NPT) and longer well construction periods. Moreover, there are complications, which might occur both during well construction and during its exploitation. The commonest complications are sustained casing pressure (SCP) and annular flow. The complications, which occur when operating a well, also have a negative effect on the economic efficiency of well operation and call for additional actions, for example, repair and insulation works, which require well shutdown and killing, though a desired outcome still cannot be guaranteed; moreover, it is possible that several different operations may have to be carried out. In addition, the occurrence of SCP during well life is one of the most crucial problems that may cause well abandonment due to high risks posed by its operation. It is known that the main reasons for SCP are as follows: Channels in cement stone Casing leaks Leaks in wellhead connections To resolve the problem of cement stone channeling, several measures were taken, such as revising cement slurry designs, cutting time for setting strings on slips, applying two-stage cementing, etc. These measures were not successful, besides, they caused additional expenses for extra equipment (for example, a cementer). In order to reduce the risk of cement stone channeling, a cementing method is required that will allow to apply excess pressure on cement slurry during the period of transition and early strength development. To achieve this goal, a well-known method of controlled pressure cementing may be applied. Its main drawback, however, is that it requires much extra equipment, thus increasing operation expenses. In addition, the abovementioned method allows affecting the cement stone only during the operation process and / or during the waiting on cement (WOC) time. Upon receiving the results of the implemented measures and considering the existing technologies and evaluating the economic efficiency, the need was flagged for developing a combined cementing method. The goal of this method is to modify the production string cementing method with a view to applying excess pressure on cement stone during strength development and throughout the well lifecycle. The introduction of this lining method does not lead to an increase in well construction costs and considerably reduces the risks of losing a well from the production well stock.
The article discusses the features of an integrated approach to the study of single reef deposits on the example of the Dfr2 reservoir of the Frasnian single reefs of the Volostnovsky license area of the Orenburg region. It is shown that the use of an integrated approach makes it possible to increase the efficiency of the single reefs development. According to numerous studies, the facies structure of reef reservoirs has been established, as well as the complex structure of the void space, which affects the choice of a rational method for exploration and development of oil deposits in these reservoirs. Already at the drilling stage, there are complications associated with the complex structure of the pore space of the productive deposit Dfr2 and the mixed type of a single reef reservoir. Various methods of eliminating complications did not lead to positive results, probably due to structural features. Also, at the stage of assessing oil reserves in reef reservoirs, a number of problems arise related to the calculation methods. The standard technique for assessing the geological reserves of Frasnian deposits of single reefs leads to an underestimation of the initial geological oil reserves, to an underestimation of the reservoir characteristics of reservoirs by geophysical studies of wells. This is confirmed by additional studies involving laboratory core tomography data for a productive formation, as well as experimental field data. The article also provides an assessment of the lithological - facies heterogeneity of the pay zone of a single reef reservoir. An array of well data was processed, where the criteria for geological and production characteristics were identified for the Dfr2 reservoir by facies reef zones. The influence of facies zoning on the development indicators for the wells of the Volostnovsky license area has been established. The results of the research can be applied to other similar fields (deposits) for a more efficient development of reef reservoirs.
Recording of the build-up curve (BC) is one of the main and most common types of well testing. However, the implementation and interpretation of the BC in low permeability reservoirs faces a number of difficulties, primarily related to the insufficient duration of well shutting-in, as well as requirement for a stable rate before well test. This paper is devoted to the development of an approach to the interpretation of reservoir pressure based on BC in low permeability reservoirs, devoid of mentioned disadvantages. The proposed method is based on the general form of solving the single-phase flow equation (diffusion equation) in a heterogeneous reservoir. The desired pressure distribution in the reservoir can be described through a series of the diffusion equation eigenfunctions. The eigen functions can change depending on the distribution of reservoir pressure at the time of well shutting-in, but the eigenvalues are constant and characterize the reservoir properties only. Earlier works have already described some possibilities for the restoration of the BC based on this principle, but our calculations shows that this approach is poorly applicable to low permeability reservoirs due to the need for a long well shutting time to calculate the eigenvalues. In this paper, the authors modified the method so that after evaluation the eigen functions and eigen values in one long-term study, it was possible to use them for short-term BCs interpretation. This allows us to carry out the so-called "accumulated interpretation", improving reservoir pressure estimation in each study. Paper provides an example of application of the proposed approach to improve reservoir pressure estimation in low permeability reservoirs during short well stops using the information from long-term well shutting-in. In contrast to traditional approaches of build-up interpretation, the proposed technique is applicable to a well of arbitrary completion in a heterogeneous reservoir. The proposed approach is verified both for synthetic examples and for field cases. The use of the method in real wells is demonstrated by the low-permeability reservoirs in the Orenburg region and Yamalo-Nenets autonomous district. It is shown that the proposed approaches allow to carry out short BCs for monitoring reservoir pressure.