The paper presents the experience of using optimization algorithms to automate the process of setting up petroelastic models of Xu - White and stiff-sand on the example of Achimov deposits of one of the fields of Western Siberia. The use of differential evolution and dual annealing methods enabled to obtain the parameters of petroelastic models with the smallest error within reasonable limits. Probability density function plots and logistic regression method are used to analyze the contrast and obtain decisive rules for rock class separation. This approach provides a statistically correct solution with a quantitative assessment of the contrast in the form of a metric. For the modeled elastic property curves, separation into reservoir and nonreservoir at the log scale and separation with significant or no overlap at the seismic scale is noted. Under the assumption that the wells did not penetrate the maximum possible thicknesses of the Achimov reservoirs in the area, the elastic properties were modeled for five scenarios of increased effective thicknesses relative to the baseline. The result of contrast analysis showed confident separation in the field of acoustic impedance and the ratio of primary and shear wave velocities at values of the ratio of effective and total thicknesses greater than 0,4. Such reservoir thicknesses are unlikely for prospective objects of the study area according to actual data.

References

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Carbonate reservoirs of Eastern Siberia have a number of specific features and difficulties in studying. This paper pays attention to ambiguity of the fluid saturation definition while working with photographs of a whole core in ultraviolet light. The presence of visual signs of hydrocarbon saturation of selected core samples not always indicates successful testing of exploration wells and obtaining high-flows. Previously using the examples of terrigenous deposits in Eastern Siberia a method was developed to decompose core photos in ultraviolet light into RGB channels, and the dependence of light intensity on the type of hydrocarbon saturation was proven. Using this method the author’s further research focused on the carbonate section. Since carbonate rocks have their own mineral glow, the features of the rock composition and the reasons for the occurrence of different glows are considered. Standard approaches to interpreting photographs of the carbonate core of Eastern Siberia are not applicable. It is necessary to consider multiple options, different shades of glow, in order to identify the prospects of the interlayers of interest. This article examines the carbonate deposits of the Byuks formation in Eastern Siberia. Carbonate rocks can exhibit various types of mineral glow (blue, green, orange) under the influence of ultraviolet radiation. The developed workflow enabled to define the light intensity range of values at which one or another hydrocarbon influx may be received: gas (gas-condensate), oil, mixed saturation in different combination. As a result, the saturation palettes catalog as an additional source of information was obtained.

References

1. Bembel' S.R., Geologiya i kartirovanie osobennostey stroeniya mestorozhdeniy nefti i gaza Zapadnoy Sibiri (Geology and mapping of structural features of oil and gas fields in Western Siberia), Tyumen: Publ. of TIU, 2016, 216 p.

2. Telkov A.P., Grachev S.I., Gidromekhanika plasta primenitel'no k prikladnym zadacham razrabotki neftyanykh i gazovykh mestorozhdeniy (Hydromechanics of the reservoir as applied to applied problems of oil and gas field development), Part II, Tyumen': Publ. of TyumSPTU, 2009, 269 p.

3. Yanukyan A.P., Osobennosti razrabotki mestorozhdeniy nefti gorizontal'nymi skvazhinami (Features of oil field development by horizontal wells), Surgut: Publ. of TIU, 2020, 13 p.

4. Il'ina E.Yu., Kondakova A.V., Pinigina E.M., Kayukov D.A., The fluid saturation palette development using modern core photo processing algorithms (In Russ.), Neftyanoe khozyaystvo, 2024, no. 7, pp. 75–77, DOI: https://doi.org/10.24887/0028-2448-2024-7-75-77

The article presents the results of a seismic stratigraphic analysis of geological and geophysical data from the northeastern periphery of the Caspian Depression. Based on these findings, the geological structure of the Novoalexeyevskiy area within the Caspian oil and gas province was examined in detail. The study identified two distinct types of crust in the basement of the region which differ in consolidation age: ancient Archean–Early Proterozoic crust and younger Late Proterozoic (Riphean) crust, which is crucial for understanding the geodynamic evolution of the area. Six regionally traceable seismic stratigraphic complexes were distinguished within the sedimentary cover, each characterized by unique structural and formation features. Of particular note is the Ordovician–Silurian complex, the existence of which was previously debated. The research clarified the tectonic affinity of the area and established correlations with large-scale geodynamic events and the evolutionary history of the entire Caspian region. Paleogeographic settings and sedimentation conditions for the Riphean–Early Permian interval of sedimentary cover formation were substantiated. The obtained data indicate significant hydrocarbon potential in the Novoalexeyevsk area, previously underestimated in this regard. As a result, priority directions for further research were identified, opening new opportunities for hydrocarbon exploration along the Russian border with Kazakhstan.

References

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2. Zhanserkeeva A.A., Prospects of oil and gas potential of the junction zone of the north-east of the Precaspian basin and the southern segment of the Ural fold system (Aktobe Uralian foredeep) (In Russ.), Neft’ i gaz, 2022, no. 5, pp. 26–39, DOI: https://doi.org/10.37878/2708-0080/2022-5.02

3. Volozh Yu.A., Abukova L.A., Antipov M.P. et al., Geology and hydrocarbon potential of the subsalt deposits of the Astrakhan arch in the Caspian petroleum province: Results of comprehensive study (In Russ.), Geotektonika, 2024, no. 5, pp. 114–119, DOI: https://doi.org/10.31857/S0016853X20193323

4. Nevolin N.V., Tectonics of the Caspian Basin (In Russ.), Geologiya nefti i gaza, 1958, no. 9, pp. 4–11.

5. Antipov M.P., Bykadorov V.A., Volozh Yu.A. et al., Orenburgskiy tektonicheskiy uzel: geologicheskoe stroenie i neftegazonosnost’ (Orenburg tectonic knot: geological structure and oil and gas potential): edited by Volozh Yu.A., Parasyn V.S., Moscow: Nauchnyy mir Publ., 2013, 264 p.

6. Abilkhasimov Kh.B., Hydrocarbon potential of the Kobylandy-Tamdy upfold of the northern edge of Pricaspian basin (In Russ.), Vestnik neftegazovoy otrasli Kazakhstana, 2020, no. 1, pp. 4–18, DOI: https://doi.org/10.54859/kjogi95559

7. Slepakova G.I., Buried graben-like structures of the Caspian Basin (In Russ.), Geotektonika, 1983, no. 3, pp. 60–65.

8. Krylov N.D., Avrov V.P., Golubeva Z.V., Geological model of the subsalt complex of the Caspian depression and oil and gas potential (In Russ.), Geologiya nefti i gaza, 1994, no. 6, pp. 35–39.

9. Volozh Yu.A., Antipov M.P., Khafizov S.F., On the conditions of the Precaspian depression formation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2024, no. 5, pp. 8–15, DOI: https://doi.org/10.24887/0028-2448-2024-5-8-15

10. Leonov Yu.G., Volozh Yu.A., Antipov M.P., Konsolidirovannaya kora Kaspiyskogo regiona: opyt rayonirovaniya (Consolidated crust of the Caspian region: zoning experience): edited by Leonov Yu.G., Moscow: GEOS Publ., 2010, 64 p.

11. Shlezinger A.E., Regional’naya seysmostratigrafiya (Regional seismic stratigraphy), Moscow: Nauchnyy mir Publ., 1998, 144 p.

12. Volozh Yu.A., Nekrasov G.E., Antipov M.P. et al., Novyy vzglyad na formirovanie konsolidirovannoy kory Prikaspiyskoy neftegazonosnoy provintsii (A new look at the formation of the consolidated crust of the Caspian oil and gas province), In: Tektonika i geodinamika Zemnoy kory i mantii: fundamental’nye problemy-2022 (Tectonics and geodynamics of the Earth’s crust and mantle: fundamental problems-2022), Materials of the LIII Tectonic Meeting, Moscow: GEOS Publ., 2022, pp. 114–119.

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pp. 2–4.

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15. Kan V.P., Deep structure of the Aktobe Urals and the adjacent zone of the Urals according to seismic data of the Common Point Method (In Russ.), Geologiya nefti i gaza, 1996, no. 7, pp. 39–44.

The article explores the change in the reservoir properties of the Shiranish formation in the Euphrates basin influenced by various geological processes. The Shiranish Formation is divided into two units: the Upper Shiranish and the Lower Shiranish. This article focuses on the Upper Shiranish Formation. It consists of clay-carbonate rocks of Upper Cretaceous age. Typically, it represents a source rock enriched with organic matter, possessing hydrocarbon generation potential. However, while drilling a well in the South Kishma field, oil inflow was obtained from the Upper Shiranish Formation. Consequently, the unit was studied in greater detail through comprehensive geological and geophysical investigations to thoroughly analyze the type of its pore space and reservoir properties. Patterns of fracture formation were examined, along with more active periods of tectonic restructuring during geological time. The results obtained during seismic surveys and geophysical studies in wells were interpreted. Core samples were analyzed using various rock study methods, including scanning electron microscopy. Geological models of the South Kishma field were created to establish different hydrodynamic scenarios that could be considered further during field development. Based on all the results of the work performed, the oil reserves of the Upper Shiranish Formation in the South Kishma field were calculated.

References

1. Aldahik A., Crude oil families in the Euphrates graben petroleum system: PhD thesis, Berlin Institute of Technology, 2010, DOI: http://doi.org/10.14279/depositonce-2678

2. Fu Yupu, Zheng Qiang, Pang Wen, Xia Dongling, Carbonate reservoir controls in the Shiranish Formation of O oil field, Syria, Petroleum Geology & Experiment, 2017, V. 39(3), pp. 355-361, DOI: https://doi.org/10.11781/sysydz201703355

3. Barrier E., Machhour L., Blaizot M., Petroleum systems of Syria, AAPG Memoir, 2014, V. 106. Petroleum systems of the Tethyan region, pp. 335–378.

4. Ismail S., Sedimentology and petroleum potential of the Late Cretaceous Shiranish formation in the Euphrates graben, Syria: PhD Thesis, Berlin Institute of Technology, 2011, DOI: http://doi.org/10.14279/depositonce-2735

5. Litak R. et al., Structure and evolution of the petroliferous Euphrates Graben system, Southeast Syria, AAPG Bulletin, 1998, V. 82, no. 6, pp. 1173–1190.

6. Brew G., Tectonic and geologic evolution of Syria, GeoArabia, 2001, V. 6, No. 4, pp. 573-616, DOI: http://doi.org/10.2113/geoarabia0604573a

7. Sawaf T., Al-Saad D., Gebran A. et al., Structure and stratigraphy of Eastern Syria across the Euphrates depression, Tectonophysics, 1993, V. 220, no. 1-4, pp. 267–281, DOI: http://doi.org/10.1016/0040-1951(93)90235-C

8. Brew G., Tectonic evolution of the NE Palmyride mountain belt, Syria ,the Bishri crustal block, Journal of the Geological Society, 2003, V. 160, pp. 677–685,

DOI: http://doi.org/10.1144/0016-764902-161

9. Brew G., Litak R., Barazangi M., Tectonic evolution of Northeast Syria: Regional implications and hydrocarbon prospects, GeoArabia, 1999, V. 4, no. 3, pp. 289 – 318, DOI: https://doi.org/10.2113/GEOARABIA0403289

10. De Ruiter R.S.C., Lovelock P.E.R., Nabulsi N., The Euphrates Graben of eastern Syria: A new petroleum province in the northern Middle East, Journal of the Middle East Petroleum Geosciences, 1995, No. 1, pp. 357–368.

The article presents the results of studying the rocks of the Shiranish formation using the Rock-Eval method. The hydrocarbon-generating potential of rocks and the origin of organic matter were assessed; the patterns of organic matter maturation were identified. Based on the obtained geochemical parameters, the Shiranish formation was divided into two subformations: the lower Shiranish formation (LSF) and the upper Shiranish formation (USF). USF in turn was subdivided into two submembers: USF-1 and USF-2. The analysis of rocks indicates the presence of oil source intervals in the lower part of the USF-1. The USF is characterized by a kerogen type from II to II-III, as well as constantly increasing contents of total organic carbon (TOC) and the hydrogen index (HI). In contrast, LSF is characterized by a kerogen type II-III and lower TOC and HI values. The oxygen index (OI) values in the rocks of the LSF are significantly higher than in the USF. All studied rock samples of the Shiranish formation, collected from seven wells located in the Euphrates fault trough, are oil source rocks. The degree of maturity varies from immature OM in the eastern and northeastern fault troughs to mature OM towards the central fault trough, which is located in the main oil generating zone.

References

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2. Peters K.E., Cassa M.R., Applied source rock geochemistry, In: The petroleum system-from source to trap, AAPG Memoir 60, 1994, pp. 93–120.

3. Peters K.E., Guidelines for evaluating petroleum source rock using programmed pyrolysis, AAPG Bulletin, 1986, V. 70, no. 3, pp. 318–329.

DOI: http://doi.org/10.1306/94885688-1704-11D7-8645000102C1865D

4. Espitalie J., Derro G., Marquis F., Rock-Eval pyrolysis and its application, Revue de l Institut Français du Pétrole, 1985, V. 50, no. 5,

DOI: https://doi.org/10.2516/OGST%3A1985035

5. Dembicki H., Three common source rock evaluation errors made by geologists during prospect or play appraisals, AAPG Bulletin, 2008, V. 93, no. 3, pp. 341–356,

DOI: http://doi.org/10.1306/10230808076

6. Katz B., Limitations of Rock-Eval pyrolysis for typing organic matter, Organic Geochemistry, 1983, V.4, no. 3–4, pp. 195–199, DOI: http://doi.org/10.1016/0146-6380(83)90041-4

7. Daly A.R., Edman J. Loss of organic carbon from source rocks during thermal maturation, AAPG Bulletin, 1987, V. 71, no. 5,

DOI: http://doi.org/10.1306/42450Edman2019

8. Whelan J.K., Thompson-Rizer C.L., Chemical methods for assessing kerogen and protokerogen types and maturity, Organic Geochemistry, 1993, pp. 289–353,

DOI: https://doi.org/10.1007/978-1-4615-2890-6_14

The paper presents the first investigation results of the pore water content and chemical composition of the old/dry/archived core samples of the Achimov Formation (ACh). The studied materials include ACh rock samples from 12 fields, gathered more than 10 years ago at the geologic exploration stage. To study pore water composition and quantitative content, the previously proposed integrated approach with proven effectiveness in fresh low-permeability rocks was used. Despite the low permeability, the authors found that the ACh rock samples during storage lost almost all (up to 90 %) free water due to evaporation. Nevertheless, salts from formation water remained in the pore space, which enabled to estimate the range of the NaCl salinity (1,84–14,7 g/L). The obtained values set the lower limit of the possible pore water salinity of the studied ACh rock samples and match those from direct salinity measurements in the ACh depth intervals. The cation exchange capacity (CEC) range of the studied ACh rock samples is 3,13–3,95 meq/100 g of rock and is typical for sediments at the considered depths. It is shown that the old/dry/archived ACh core could be effectively used to assess the bound water content with subsequent determination of its genesis from isotopic composition data and CEC measurements. This is due to the high clay content (44,6–55,8 %) in the studied ACh rock samples. The obtained results show the fundamental capability of informative laboratory studies of rock samples from public and private core storage facilities.

References

1. Kazak E.S., Kazak A.V., An integrated experimental workflow for formation water characterization in shale reservoirs: A case study of the Bazhenov formation, SPE-205017-PA, 2021, DOI: http://doi.org/10.2118/205017-PA

2. Kazak E.S., Kazak A.V., A novel laboratory method for reliable water content determination of shale reservoir rocks, Journal of Petroleum Science and Engineering, 2019, V. 183, DOI: https://doi.org/10.1016/j.petrol.2019.106301

3. Kazak E.S., Kazak A.V., Comprehensive studies of formation water for Achimov and Bazhenov formations — Revitalizing archived and old cores, SPE-208415-MS, 2021, DOI: https://doi.org/10.2118/208415-MS

4. Kazak E.S., Kazak A.V., Experimental features of cation exchange capacity determination in organic-rich mudstones, Journal of Natural Gas Science and Engineering, 2020, V. 83, DOI: https://doi.org/10.1016/j.jngse.2020.103456

5. Kontorovich A.E., Kostyreva E.A., Melenevskiy V.N. et al., Geochemical criteria of Mesozoic oil and gas potential of south-east of West Siberia (by results of drilling wells Vostok-1, 3, 4) (In Russ.), Geologiya nefti i gaza, 2009, no. 1, pp. 4–12.

6. Dmitriev N.M., Kravchenko M.N., Dmitriev M.N. et al., Complex research of reservoir properties on cores from Achimov deposits, SPE-171259-MS, 2014,

DOI: https://doi.org/10.2118/171259-MS

7. Khitrenko A.V., Musikhin A.D., Groman K., Reservoirs characterization of deepwater sediments, Achimov formation, Western Siberia, Russia, Proceedings of SEG International Exposition and Annual Meeting, 2018, DOI: https://doi.org/10.1190/segam2018-2984486.1

8. Handwerger D.A., Keller J., Vaughn K., Improved petrophysical core measurements on tight shale reservoirs using retort and crushed samples, SPE-147456-MS, 2011, DOI: https://doi.org/10.2118/147456-MS

9. Saidian M., Godinez L.J., Prasad M., Effect of clay and organic matter on nitrogen adsorption specific surface area and cation exchange capacity in shales (mudrocks), Journal of Natural Gas Science and Engineering, 2016, V. 33, pp. 1095–1106, DOI:https://doi.org/10.1016/j.jngse.2016.05.064

10. Gall B.L., Volk L.J., Raible C.J., Semiautomated method for cation-exchange-capacity determination of reservoir rocks, SPE-9873-PA, 1983, pp. 231–237,

DOI: http://doi.org/10.2118/9873-PA

11. Derkowski A., Marynowski L., Reactivation of cation exchange properties in Black shales, International Journal of Coal Geology, 2016, V. 158, pp. 65–77,

DOI: https://doi.org/10.1016/j.coal.2016.03.002

12. Šliaupa S., Lozovskis S., Lazauskienė J. et al., Petrophysical and mechanical properties of the Lower Silurian perspective oil/gas shales of Lithuania, Journal of Natural Gas Science and Engineering, 2019, V. 79, DOI: https://doi.org/10.1016/j.jngse.2020.103336

13. Appelo C.A.J., Postma D., Geochemistry, groundwater and pollution, London: A.A. Balkema Publishers, 2005, DOI: https://doi.org/10.1201/9781439833544

14. Popov V.G., Abdrakhmanov R.F., Ionoobmennaya kontseptsiya v geneticheskoy gidrogeokhimii (The Ion Exchange Concept in Genetic Aqueous Geochemistry), Ufa: Gilem Publ., 2013, 356 p.

15. Zanin Yu.N., Pisareva G.M., Zamiraylova A.G. et al., Melanterite and szomolnokite as weathering products of pyrite from the Bazhenovo formation (In Russ.), Litologiya i poleznye iskopaemye = Lithology and Mineral Resources, 2009, no. 3, pp. 294–296.

The article discusses methods for improving the efficiency of well drilling and reconstruction using digital monitoring and statistical tools provided by an automated complex of geotechnical study station that does not require human intervention, as well as a module for determining hidden losses used in Rosneft Oil Company. These tools help to eliminate the human element from the creation of accounting documents, recognize and record operations on the wellsite, identify trends by increasing transparency in work, provide high-quality information for all participants of the process, and take over routine registration, compilation, initial analysis of work done, and notification of any discrepancies. The automated complex of geotechnical study station works by monitoring the progress of well construction autonomously using modern software and self-diagnostic equipment. Specialized software enables users to quickly compare actual time spent against standard time; record operations performed, and track deviations in work performance over a specified period. The Hidden Loss Detection module analyzes data from complex of geotechnical study station’s sensors and visualizes each operation using needle diagrams. It calculates the standard duration of each operation for each drilling rig based on the results achieved, regional characteristics, and the type of equipment used. This enables the module to identify potential opportunities to optimize time costs, such as excess and hidden unproductive time.

References

1. Patorov A.A., Lunin E.A., Modul' “Normativ” IS “Burenie” kak instrument analiza effektivnosti provodimykh rabot (The “Normative” module of the “Drilling” IS as a tool for analyzing the efficiency of the work performed), Collected papers “Aktual'nye voprosy i innovatsionnye resheniya v neftegazovoy otrasli” (Current issues and innovative solutions in the oil and gas industry), Proceedings of All-Russian scientific and practical conference, Samara, 26–27 August 2020, Samara: Pero Publ., 2020, pp. 43-48.

2. Kozhin V.N., Patorov A.A., Lunin E.A., Davletov K.R., Analytical resources of digital procedures in monitoring and controlling the processes in drilling the wells,

SPE-206464-MS, 2021, DOI: https://doi.org/10.2118/206464-MS

3. Patorov A.A., Lunin E.A., Optimizatsiya srokov stroitel'stva skvazhin putem primeneniya informatsionno-analiticheskikh instrumentov dlya opredeleniya skrytykh poter' vremeni v burenii (Optimization of well construction time by using information and analytical tools to identify hidden time losses in drilling), Collected papers “Ratsional'naya razrabotka mestorozhdenii nefti i gaza: opyt, tendentsii razvitiya, potentsial” (Rational development of oil and gas fields: experience, development trends, potential), Pro-ceedings of International scientific and practical online conference, Samara, 25–27 April 2022, Samara: Portal Innovatsiy Publ., 2022, pp. 10–11.

4. Davletov K.R., Lunin E.A., Patorov A.A., Kapitonov V.A., Experience in applying "KIUSS" IS module to evaluate hidden losses (In Russ.), Neft'. Gaz. Novatsii, 2023,

no. 10(275), pp. 22–25.

Currently, the achievement of efficient multistage hydraulic fracturing (MSHF) in horizontal wells is a crucial task. The production of liquid hydrocarbons at gas condensate fields depends on a number of parameters, such as the volume of injected proppant, the number of hydraulic fracturing stages, and hydraulic fracture orientation relative to the azimuth of the regional stress. Due to possible interference processes during MSHF in horizontal wells with an increase in the number of hydraulic fracturing stages, there is no incremental hydrocarbon production. Therefore, to determine the optimal hydraulic fracturing design and the efficient hydraulic fracture spacing, the cumulative gas and condensate production indicators obtained by multiple-option runs of composite sector models using the local grid refining (LGR) tool should be analyzed. The following parameters are used as variable indicators: horizontal well length, hydraulic fracture spacing, fracture propagation azimuth, and volume of the injected proppant. Effective fracture parameters such as fracture permeability, fracture height, average fracture width, and fracture half-length are determined through the hydraulic fracture design based on the estimated volume of injected proppant. For a more accurate description of the hydraulic fracture propagation, the 1D and 3D/4D geomechanical models of the field were previously built and calibrated to the actual fracturing data and measurements of the fracture height.

References

1. Vorob’ev I.V., Khoroshman P.Yu., Chikina M.I. et al., Justifying the development strategy for Jurassic reservoirs of Urengoi field (In Russ.), Nauchnyy zhurnal Rossiyskogo gazovogo obshchestva, 2023, no. 6(42), pp. 36–43.

2. Miroshnichenko A.V., Korotovskikh V.A., Musabirov T.R. et al., Investigation of horizontal wells with multi-stage hydraulic fracturing technological efficiency in the development of low-permeability oil reservoirs, SPE-206412-MS, 2021, DOI: http://doi.org/10.2118/206412-MS

3. Miroshnichenko A.V., Korotovskikh V.A., Musabirov T.R. et al., Methodology for analyzing the actual ratio of horizontal and directional wells performance indicators (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 11, pp. 42–47, DOI: http://doi.org/10.24887/0028-2448-2021-11-42-47

4. Kuleshov V., Pavlov V., Pavlyukov N. et al., Geomechanical modeling and multi–stage hydraulic fracturing dolomite reservoir of the Verkhnechonskoye oil and gas condensate field, Proceedings of the ARMA/DGS/SEG 2nd International Geomechanics Symposium, Virtual, November 2021, URL: https://onepetro.org/armaigs/proceedings–abstract/IGS21/All–IGS21/ARMA–IGS–21–088/473082

5. Metelkin D.A., Snokhin A.A., Tikhomirov I.A. et al., Borehole acoustics as a key to perfect hydraulic fracturing in Achimov formation, SPE-187758-MS, 2017,

DOI: http://doi.org/10.2118/187758–MS

6. Davletova A.R., Kireev V.V., Knutova S.R. et al., Development of corporate geomechanics simulator for wellbore stability modeling (In Russ.), Neftyanoe

khozyaystvo = Oil Industry, 2018, no. 6, pp. 88–92, DOI: http://doi.org/10.24887/0028–2448–2018–6–88–92

7. Ardislamova D.R., Davletova A.R., Zakirzyanov Sh.I. et al., Calculation of the stress state at the Severo-Komsomolskoye field using the new corporate 3D simulator RN-SIGMA (In Russ.), Ekspozitsiya Neft’ Gaz, 2023, no. 3, pp. 38–43, DOI: 10.24412/2076-6785-2023-3-38-43

8. Aksakov A.V., Borshchuk O.S., Zheltova I.S. et al., Corporate fracturing simulator: from a mathematical model to the software development (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2016, no. 11, pp. 35–40.

9. Pestrikov A.V., Peshcherenko A.B., Grebel’nik M.S., Yamilev I.M., Validation of the Planar3D hydraulic fracture model implemented in the corporate simulator RN-GRID (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2018, no. 11, pp. 46–50, DOI: http://doi.org/10.24887/0028-2448-2018-11-46-50

10. Moreva V.A., Kuleshov V.S., Pavlov V.A., Samoylov M.I., A hydrofrac fracture height measurement as a method for geomechanical model verification (In Russ.),

Karotazhnik, 2021, no.8 (314), pp. 93–109.

11. Lohrenz J., Bray B.G., Clark C.R., Calculating viscosities of reservoir fluids from their compositions, Journal of Petroleum Technology, 1964, V. 16, pp. 1171–1176,

DOI: http://doi.org/10.2118/915–PA

The injection of carbon dioxide (CO2) into oil reservoirs is a well-known method of oil flow stimulation and enhanced oil recovery. The technology of CO2 injecting into producing wells, known as Huff and Puff (HnPCO2), has become a prevalent method of flow stimulation. This technology involves the injection of CO2 into an oil well, followed by a 10-50 days idle stage of the well. It can also be reapplied with a high degree of effectiveness after 8-12 months. A comprehensive analysis of the global experience of HnPCO2 technology implementation, along with findings from laboratory studies of cores and fluids, demonstrated its efficacy for both high and low permeability formations saturated with both heavy high-viscosity and light low-viscosity oils. The technological efficiency of CO2 injection into wells, as well as the contribution of the main factors to additional oil production, can be calculated using hydrodynamic models (HDM). However, direct reproduction of some significant physical effects in digital HDMs is not feasible. The necessary estimates of the contribution of such factors can be obtained from the analysis of the results of known field experience. This article delineates the principles of preparing digital models for calculating the technological efficiency of CO2 injection using HnPCO2 technology. The results of a model of CO2 injection in one of the oil fields of Western Siberia with low-permeability reservoir and low-viscosity oil are presented.

References

1. Monger T.G., Coma J.M., A laboratory and field evaluation of the CO2 Huff ‘n’ puff process for light-oil recovery, SPE-15501-PA, 1988,

DOI: https://doi.org/10.2118/15501-PA

2. Mohammed-Singh L., Singhal A.K., Sim S., Screening criteria for carbon dioxide Huff ‘n’ Puff operations, SPE-100044-MS, 2006,

DOI: http://doi.org/10.2523/100044-MS

3. Xiang Zhou, Qingwang Yuan, Xiaolong Peng et al., A critical review of the CO2 Huff ‘n’ Puff process for enhanced heavy oil recovery, Fuel, 2018, V. 215, pp. 813–824, DOI: https://doi.org/10.1016/j.fuel.2017.11.092

4. Rui Wang, Chengyuan Lv, Shuxia Zhao et al., Experiments on three-phase relative permeability in CO2 flooding for low permeability reservoirs, SPE-174590-MS, 2015, DOI: https://doi.org/10.2118/174590-MS

5. Thomas G.A., Monger-McClure T.G., Feasibility of cyclic CO2 injection for light-oil recovery, SPE-20208-PA, 1991, DOI: https://doi.org/10.2118/20208-PA

6. Darishchev V.I., Kharlanov S.A., Babinets Yu.I. et al., Implementation of CO2 injection technology Huff & Puff as a method of intensifying the production of high-viscosity oil (In Russ.), Burenie i neft’, 2023, no. 3, pp. 18–23.

7. Afonin D.G., Gracheva S.K., Ruchkin A.A. et al., The key stages of injecting carbon dioxide into oil reservoirs in order to enhance oil recovery and stimulate oil production (In Russ.), Izvestiya vysshikh uchebnykh zavedeniy. Neft’ i gaz = Oil and Gas Studies, 2024, no. 4, pp. 119–135,

DOI: https://doi.org/10.31660/0445-0108-2024-4-119-135

8. Morozyuk O.A. et al., Laboratory support of a project on CO2 injection into a low-permeability reservoir (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2024, no. 10, pp. 103–109, DOI: https://doi.org/10.24887/0028-2448-2024-10-103-109

9. Coats K.H., An equation of state compositional model, SPE-8284-PA, 1980, DOI: https://doi.org/10.2118/8284-PA

10. Tkacheva V.E., Brikov A.V., Lunin D.A., Markin A.N., Lokal’naya CO2-korroziya neftepromyslovogo oborudovaniya (Localized CO2 corrosion of oilfield equipment), Ufa: Publ. of RN-BashNIPIneft’, 2021, 168 p.

11. Zlobin A.A., Yushkov I.R., About the mechanism of hydrophobization of surface of rock in oil and gas reservoirs (In Russ.), Vestnik Permskogo universiteta. Geologiya, 2014, V. 3(24), pp. 68-79.

12. Peyman Zanganeh, Shahab Ayatollahi, Abdolmohammad Alamdari et al., Asphaltene deposition during CO2 injection and pressure depletion: A Visual Study, Energy & Fuels, 2012, V. 26, pp. 1412–1419, DOI: https://doi.org/10.1021/ef2012744

The article presents general information about the object of research, describes the main stages of its development history. An assessment was made to understand the development efficiency of a deposit confined to fractured basement reservoirs at a reservoir pressure below the saturation pressure. Calculations were performed on a sector dynamic model using the tNavigator 22.4 simulator. The filtration model represents a macro-fracture with micro-fractures connected to it. High-resolution X-ray tomography of real core samples was used to set the geometry of the model and the main properties of micro- and macro-fractures. The selection of the optimal pressure reduction strategy for the residual oil recovery was performed in two stages. At first, the initial state of the system, washed macro-fracture and trapped oil in micro-fractures, were modeled. Secondly, the duration of the injection and depletion periods was varied to maximize oil recovery factor (ORF). The sensitivity analysis of the calculations to changes in the main parameters of the dynamic model was performed. The ranges of parameter changes were adopted according to the results of X-ray tomography of real core samples, as well as logging and well tests. Based on the result of the work, it was concluded that the highest ORF is achieved by alternating injection and depletion regimes. The main effect on the ORF value is made by the permeability of micro-fractures, as well as the value of capillary pressure.

References

1. Nelson R.A., Geologic analysis of naturally fractured reservoirs, Cambridge: Gulf Professional Publishing, 2001, 323 р.

2. Aguilera R., Naturally fractured reservoirs, Tulsa, Oklahoma: PennWell, 1995, 521 р.

3. Cosentino L., Integrated reservoir studies, Paris: TECHNIP ed., 2001, 400 p.

4. Lebedinets N.P., Vesvalo A.N., Approximate evaluation of the granitoid rocks compressibility (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2013, no. 8, pp. 30–31.

5. Wolcott D., Applied waterflood field development, Publ. of Schlumberger, 2001, 142 p.

The article observes a problem of reduced well productivity index for field N for which a multistage hydraulic fracturing technology is used. Results of well testing and performance analysis showed that the reason of this effect is impaired connectivity between the well and the formation. Several reasons were considered as a part of productivity decline, one of them is scale deposition CaCO3 in process of chemical reaction between killing fluid CaCl2 used in completion process and formation water, later this hypothesis was confirmed by the results of electrical submersible pump dismounting. As a solution for the problem the authors considered optimization of killing fluid composition or use of temporary blocking agents (pills) to reduce the contact of completion fluid with formation water. As a result of physical-chemical and filtration tests, several compositions and blocking agents stable at formation temperature up to 120 °C were selected, aiming to reduce the risks in future well interventions in the field. As additives to killing fluids, it is recommended to use polymer chemicals that increase the viscosity of solutions and reduce water loss, surfactants to compensate for the negative impact of the killing fluid on the formation, and flow assurance chemicals (in particular, corrosion and scale inhibitors).

References

1. Kremenetskiy M.I., Ipatov A.I., Primenenie promyslovo-geofizicheskogo kontrolya dlya optimizatsii razrabotki mestorozhdeniy nefti i gaza (Application of field geophysical control to optimize the development of oil and gas fields), Part I. Osnovy gidrodinamiko-geofizicheskogo kontrolya razrabotki i monitoringa dobychi (Fundamentals of hydrodynamic-geophysical control of development and production monitoring), Moscow - Izhevsk: Publ. of Institute of Computer Science, 2020, 676 p.

2. Kolesnikov M.V., Panarina E.P., Kremenetskiy M.I., Pakhomov E.S., The possibilities of field geophysical surveys for the diagnosis of horizontal wells with different types of completion (In Russ.), Aktual'nye problemy nefti i gaza, 2024, V. 15, no. 3, pp. 296–311, DOI: https://doi.org/10.29222/ipng.2078-5712.2024-15-3.art7

3. Ryabokon' S.A., Tekhnologicheskie zhidkosti dlya zakanchivaniya i remonta skvazhin (Process fluids for completion and repair of wells), Krasnodar, 2016, 382 p.

4. Caenn R., Darley H.C., Gray G., Composition and properties of drilling and completion fluids, Amsterdam: Gulf professional publishing, 2011, 720 p.,

DOI: https://doi.org/10.1016/C2009-0-64504-9

5. RD 39-2-645-81. Metodika kontrolya parametrov burovykh rastvorov (Methodology for monitoring parameters of drilling fluids), Krasnodar: VNIIKRneft', 1981.

Due to the depletion of hydrocarbon reserves in traditional formations with good reservoir properties, interest in hard-to-recover reserves is currently increasing. And the main difficulty in the development of such reservoirs is the efficiency of waterflooding systems. The transition to the development of fields with a complex geological structure, low filtration characteristics of the formation, the existence of geological bodies with different properties, requires not only thoroughness in the formation of a conceptual understanding of the oilfield, but also the creation of detailed digital facial maps taking into account the existence of zones with different sedimentation, as a consequence, creating zones with different filtration-capacitance properties, requiring different approaches to development. The purpose of this work is to analyze the efficiency of the reservoir pressure maintenance system in low-permeability reservoirs of the Achimov formation and optimize its operation taking into account the facies model. An analysis of the current state of the facility's energetic was conducted, based on the results of which the field was divided into sections with different well operation patterns, related to sedimentation features. For each section, an analysis of well operation was conducted, inefficient injection zones were localized, the causes of inefficiency were determined, and proposals for pilot projects aimed at increasing the efficiency of flooding of the Achimov facility were prepared and implemented.

References

1. Bikkulov M.M., Kolupaev D.Yu., Yanin A.N., Yanin K.E., Improving the development system of a thick low-permeability reservoir on the example of the central section of the Priobskoye field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2023, no. 1, pp. 16–22, DOI: https://doi.org/10.24887/0028-2448-2023-1-16-22

2. Baykov V.A., Zhdanov R.M., Mullagaliev T.I., Usmanov T.S., Selecting the optimal system design for the fields with low-permeability reservoirs (In Russ.), Neftegazovoe delo, 2011, no. 1, pp. 84–98.

3. Davletbaev A.Ya., Baykov V.A., Bikbulatova G.R. et al., Field studies of spontaneous growth of induced fractures in injection wells (In Russ.), SPE-171232-MS, 2014, DOI: https://doi.org/10.2118/171232-MS

4. Zorin A.M., Usmanov T.S., Kolonskikh A.V. Et al., Operational efficiency improvement in horizontal wells though optimizing the design of multistage hydraulic fracturing at Priobskoye Northern territory (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 11, pp. 122–125, DOI: https://doi.org/10.24887/0028-2448-2017-12-122-125

5. Muromtsev V.S., Elektrometricheskaya geologiya peschanykh tel – litologicheskikh lovushek nefti i gaza (Electrometric geology of sand bodies - lithological traps of oil and gas), Leningrad: Nedra Publ., 1984, 260 p.

6. Lapitskiy D.R., Fattakhova K.V., Khidiyatov M.M. et al., Avtomatizirovannoe sozdanie fatsial’noy geologo-tekhnologicheskoy modeli na osnove algoritmov ML (Automated creation of a facies geological and technological model based on ML algorithms), Proceedings of V International Geological and Geophysical Conference “GeoEvraziya-2022. Geologorazvedochnye tekhnologii: nauka i biznes” (GeoEurasia-2022. Geological exploration technologies: science and business), V. I(III), Tver: PoliPRESS Publ., 2022, pp. 90–93.

7. Lapitskiy D.R., Fattakhova K.V., Khidiyatov M.M. et al., Sistema zapolneniya mezhskvazhinnykh intervalov posredstvom primeneniya Markovskogo protsessa k modelirovaniyu osadkonakopleniya (A system for filling interwell intervals by applying a Markov process to sedimentation modeling), Proceedings of VI Baltic Scientific and Practical Conference “BalticPetroModel-2022. Petrofizicheskoe modelirovanie osadochnykh porod” (BalticPetroModel-2022. Petrophysical modeling of sedimentary rocks), Tver: PoliPRESS Publ., 2022, pp. 33–35.

8. Lapitskiy D.R., Mullagalin I.Z., Emchenko O.V. et al., Raspoznavanie elektrofatsiy glubokovodnykh osadochnykh sistem metodami mashinnogo obucheniya (Recognition of electrofacies in deep-marine sedimentary systems using machine learning methods), Proceedings of X International scientific and practical conference “GeoKaliningrad-2021. Neftegazovaya, rudnaya geologiya i geofizika” (GeoKaliningrad-2021. Oil and Gas, Ore Geology and Geophysics), Tver: PoliPRESS Publ., 2021, pp. 104–106.

9. Salimgareeva E.M., Emchenko O.V., Mullagalin I.Z. et al., Vyyavlenie mekhanizmov raboty sistemy PPD dlya nizkopronitsaemogo kollektora na baze kompleksnogo analiza dannykh razrabotki, GDI i litologo-fatsial’nogo analiza (Identification of the mechanisms of operation of the reservoir pressure maintenance system for a low-permeability reservoir based on a comprehensive analysis of development data, hydrodynamic studies and lithological-facies analysis), Proceedings of X International scientific and practical conference “GeoKaliningrad-2021. Neftegazovaya, rudnaya geologiya i geofizika” (GeoKaliningrad-2021. Oil and Gas, Ore Geology and Geophysics), Tver: PoliPRESS Publ., 2021, pp. 107–111.

The article covers the issues of evaluation of the efficiency of innovative high-temperature reagent HIMMASTER 500 under steam-heat effect in different injection regimes. As a part of the work a complex of researches on physical modeling of oil displacement process at steam-heat influence was carried out with the use of a unique scientific unit for physical and chemical modeling of in-situ combustion and steam-gravity drainage. By means of physical modeling of steam-thermal influence on the core reservoir model the oil displacement coefficients were determined during the following experiments: at steam injection (basic experiment), at pre-injection of additive rim and further steam injection, at injection of additive solution and steam. On the basis of the obtained data the optimal mode of steam injection with the developed additive was selected and the efficiency of this agent was proved. In addition it was established that the reagent helps to reduce the contact angle of wettability, increasing the water wettability of the rock. It was also determined that the reagent has high thermal stability at temperatures up to 220 °C, and provides an increase in the oil displacement coefficient by 4,7 % when injected together with steam. At the same time, the need to optimize the conditions for using the reagent during its separate injection was revealed, which requires further study. The effectiveness of the chemical reagent was proven, the optimal steam injection mode with the innovative additive was selected, and its applicability for increasing oil recovery at fields developed using thermal methods was substantiated.

References

1. Nikolaeva M.V., Atlasov R.A., Review of technologies for the development of heavy oils and natural bitumens in conditions of permafrost (In Russ.), Neftegazovoye Delo, 2015, V. 13 4, pp. 126–131, EDN: VTKTBJ

2. Derevyanko V.K. et al., Selection of optimal EOR for extra-heavy crude oil displacement from low-permeability reservoirs, AIP Conference Proceedings, 2023,

V. 2929, no. 1, DOI: https://doi.org/10.1063/5.0180385

3. Zeidani K., Gupta S.C., Surfactant-steam process: an innovative enhanced heavy oil recovery method for thermal applications, SPE-165545-MS, 2013,

DOI: https://doi.org/10.2118/165545-MS

4. Derevyanko V.K. et al., Feasibility of foam-enhanced water-gas flooding for a low-permeability high-fractured carbonate reservoir. screening of foaming agent and flooding simulation, SPE-217637-MS, 2023, DOI: https://doi.org/10.2118/217637-MS

5. Al-Khafaji A.H. et al., Steam surfactant systems at reservoir conditions, SPE-10777-MS, 1982, DOI: https://doi.org/10.2118/10777-MS

6. Suncor Energy. Application for Chemical (Alkali and/or surfactant) Pad 22 co-injection test, Suncor Mackay River oil sands project, Energy Resources Conservative Board application, 2011, no. 1690728.

7. Connacher Oil and Gas Limited. Application to amend approval №. 10587E to add surfactant to the steam injected into well pairs 102W-04 & 102W-05 at Connacher’s Pod One SAGD facility, Energy Resources Conservative Board application, 2011, no. 1707322.

8. Duy Nguyen et al., Adhesion and surface energy of shale rocks, Colloids and Surfaces A: Physicochemical and Engineering Aspects, 2017, V. 520, pp. 712–721,

DOI: https://doi.org/10.1016/j.colsurfa.2017.02.029

9. Minkhanov I.F. et al., Experimental study on the improving the efficiency of oil displacement by co-using of the steam-solvent catalyst (In Russ.), Neftyanoe khozyaystvo = Oil Industry Journal, 2021, no. 6, pp. 54–57, DOI: https://doi.org/10.24887/0028-2448-2021-6-54-57

10. Minkhanov I.F. et al., The influence of the content of clay minerals on the efficiency of steam treatment injection for the bitumen oils recovery, SOCAR Proceedings, 2021, Special Issue 2, pp. 65–75, DOI: https://doi.org/10.5510/OGP2021SI200569

The article provides a detailed analysis of modern automation technologies which are implemented in oil and gas fields and aimed at enhancing the efficiency of hydrocarbon production processes, reducing operating costs, and minimizing the need for human involvement in routine operations. Particular attention is given to the adoption of innovative solutions, including automated multi-measurement installations, flow sensors, and highly efficient thermal loss compensation systems, which ensure the stable operation of infrastructure under challenging conditions. As part of the research, pilot industrial trials were conducted to evaluate the effectiveness of the proposed technologies in real operational conditions. The results of these trials demonstrated not only their high reliability and accuracy but also revealed opportunities for further adaptation of these solutions to the unique characteristics of various operational sites. Specifically, automated multi-measurement installations proved to be effective tools for improving the accuracy of production volume accounting, while thermal loss compensation systems significantly reduced energy costs in low-temperature environments. The data presented in the article confirm that these technologies hold significant potential for widespread implementation in domestic oil and gas fields. The use of such technologies contributes not only to increased production efficiency but also to enhanced industrial safety, which is particularly relevant nowadays.

References

1. Grekhov I.V., Kuzmin M.I., Muzychuk P.S., Gerasimov R.V., Concept of autonomous well pad at the fields of Gazprom Neft (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 12, pp. 69–73, DOI: https://doi.org/10.24887/0028-2448-2021-12-69-73

2. Muzychuk P.S., Umnov A.N., Aksenov A.G., Tsifrovaya transformatsiya protsessa mekhanizirovannoy dobychi nefti v PAO “Gazprom neft'” (Digital transformation of the process of mechanized oil production at Gazprom Neft), Collected papers “Tekhnika i tekhnologiya neftekhimicheskogo i neftegazovogo proizvodstva” (Equipment and technology of petrochemical and oil and gas production), Proceedings of 11th International scientific and technical conference, Omsk, 24–27 February 2021, Omsk: Publ. of OSTU, 2021, pp. 170–173.

3. Kuz'min M.I., Grekhov I.V., Gerasimov R.V., Autonomous asset: Concept and solutions (In Russ.), PRONEFT. Professional'no o nefti = PROneft. Professionally about Oil, 2023, no. 8(1), pp. 129–137, DOI: https://doi.org/10.51890/2587-7399-2023-8-1-129-137

4. Kuz'min M.I., Grekhov I.V., Gerasimov R.V., Autonomous asset. Individual elements and development prospects (In Russ.), Inzhenernaya praktika, 2022, no. 4,

pp. 62–65.

5. URL: https://www.slb.ru/services/testing/multiphase_well_testing/surface_multiphase_flowmeters/spectra

6. Shumilin V.N., Shumilin S.V., Vibroacoustic multiphase flow meter (In Russ.), Inzhenernaya praktika, 2017, no. 11.

The Verkhnechonskoye oil and gas condensate field is one of the largest fields in Eastern Siberia owned by Rosneft Oil Company. Complex logistics and significant distance from large industrial clusters regularly create complex engineering challenges to the project. One of such challenges was the task to ensure the utilization of at least 95 % of associated petroleum gas (APG) in the absence of developed gas transportation infrastructure in the region. Since the development of the main terrigenous reservoir Vch is complicated by the presence of a gas cap and, therefore, higher gas production, the most reasonable option of APG utilization was to arrange temporary underground gas storage (TUGS) in 2018 for subsequent gas extraction. This technology for injecting APG into a TUGS was used for the first time in Eastern Siberia. Further development of the project is accompanied by increasing gas production and requires expansion of the TUGS. The gas injection into the gas cap and water alternation gas generally complicate the TUGS control. As part of the TUGS project expansion, it became necessary to increase the capacity of the existing gas compressor station (GCS) and expand the network of high-pressure in-field gas pipelines. To ensure efficient management of gas injection (3 reservoirs), an integrated TUGS model was required. Integrated flow simulation models take into account all input data in a reservoir-well-surface infrastructure system and are widely used in gas production projects, but there is very little experience in building such complex models for gas injection.

References

1. Chirgun A., Livanov A., Gordeev Ya. et al., A case study of the Verkhnechonskoye field: Theory and practice of Eastern Siberia complex reservoirs development (In Russ.), SPE-189301-RU, 2017, DOI: http://doi.org/10.2118/189301-MS

2. Ignat'ev N.A., Shvets V.S., Levanov A.N. et al., Organizing, monitoring, and operating a temporary underground gas storage at Verkhnechonskoye field in Eastern Siberia (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 8, pp. 84–88, DOI: https://doi.org/10.24887/0028-2448-2021-8-84-88

3. Tekhnologicheskiy proekt sozdaniya vremennogo podzemnogo khranilishcha poputnogo neftyanogo gaza na Verkhnechonskom neftegazokondensatnom mestorozhdenii (Technological project for the creation of a temporary underground storage facility for associated petroleum gas at the Verkhnechonskoye oil and gas condensate field), Moscow: Publ. of Gazprom VNIIGAZ, 2011.

4. Mel'nikov N.V., Vend-kembriyskiy solenosnyy basseyn Sibirskoy platformy (Stratigrafiya, istoriya razvitiya) (Vendian-Cambrian salt basin of the Siberian Platform (Stratigraphy, development history)), Novosibirsk: Publ. of SB RAS, 2009, 148 p.

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(A practical guide to integrated modeling of gas and gas condensate fields), Tyumen: Ekspress Publ., 2023, 174 p.

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As the oil and gas, petrochemical and chemical industries develop, they face the following problems: multiple stages, complexity and low controllability of processes, high consumption of reagents. Microencapsulation is nowadays being considered as an alternative option that can improve process efficiency by reducing stages, losses and providing targeted delivery of reagents. This technology is already being actively developed in different areas such as medicine, food and cosmetics industries for controlled release of reagents. The Intersectoral Expert Analytical Center (MEAC) in cooperation with their partners is implementing the Smart Microcontainers (SMC) project, transferring the technology to the oil and gas, petrochemical and chemical industries. The SMC project has already gained significant development in the areas such as drilling, cement squeeze job, and chemical methods of enhanced oil recovery. In addition, it is worth mentioning that SMC have great potential in hydraulic fracturing, acid treatments, encapsulation of reagents used in production. This paper presents the latest results of the project development related to material selection, production of SMC, motion control, opening and polymerization, as well as an overview of the applications and implementation options of the technology, which shows the potential of this project and provides a basis for future research and development.

References

1. Orlov M.V., Materials microencapsulation applications in oil drilling and production, Journal of Physics: Conference Series, 2021, V. 1942, no. 1,

DOI: https://doi.org/10.1088/1742-6596/1942/1/012004

2. Jingyi Zhu et al., Recent progress in microencapsulation technology and its applications in petroleum industry, Journal of Molecular Liquids, 2024, V. 407,

DOI: https://doi.org/10.1016/j.molliq.2024.125162

3. Maksimov A.L. et al., Microencapsulation: an overview of concepts, methods and prospects for use in the processes of the oil and gas and chemical industries (In Russ.), Burenie i neft’, 2023, no. 1, pp. 11–25, EDN: VIZUKK

4. Maksimov A.L. et al., Microencapsulation: Evaluation of the application of physical and physicochemical methods for the production of capsules for use in oil and gas and chemical industry processes (In Russ.), Neftegaz.RU, 2024, no. 8, pp. 48–52, EDN: QGRVGY

5. Chen P.W., Erb R.M., Studart A.R., Designer polymer-based microcapsules made using microfluidics, Langmuir, 2012, V. 28, no. 1, pp. 144–152,

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9. Petrov A.V. et al., Impact of high intensity focused ultrasound on biofabric model phantoms and composite microcapsules with nanoscale shells (In Russ.), Vestnik Tambovskogo gosudarstvennogo tekhnicheskogo universiteta, 2018, V. 24, no. 3, pp. 539–549, DOI: https://doi.org/10.17277/vestnik.2018.03.pp.539-549

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The article discusses prospects of use of canned motor pump units in main pipeline transport systems. Presently, oil and product main pipeline transport systems utilize pumping equipment that fails to provide complete impermeability of the transported fluid due to inherent design limitations. Achieving complete impermeability during oil and petroleum product transportation requires additional systems such as dual mechanical sealings or even comprehensive pump redesign. This paper assesses the feasibility of using pump units operating directly in the pumped fluid, which are capable of ensuring complete impermeability due to their installation directly inside the pipeline. The article presents a comprehensive analysis of benefits and drawbacks of this pump unit design and also a critical assessment of their performance in main pipeline operating conditions. The use of such hermetic pumps shall increase transportation safety thereby preventing the risk of leaks considering, however, the restrictions associated with the structural features of these hydraulic machines and of the equipment operating conditions. The operational characteristics of canned motor pumps are thoroughly discussed, along with an evaluation of their potential application in main pipeline transport systems. The study outlines prerequisites for addressing technical challenges in hermetic pump unit development and defines research directions for their future engineering design.

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