One of the conceptual and systems engineering objectives related to field development is to find the best solutions for surface facilities designed to gather, process and transport oil and gas. However, due to high uncertainty, complexity and labor-intensity associated with the objective and also due to the fact that there are a lot of factors that are hard to summarize, people tend to adopt “locally suitable” solutions incorporating the interests of certain stakeholders (such as geologists, drillers, engineers, constructors, economists, etc.) rather than “generally best” solutions. Issues related to such an approach, which takes into consideration multiple factors related to selection and approval of process equipment, are very urgent for the oil and gas industry. Capital expenditures take a significant part of expenses and their optimization contributes to the general cost-efficiency of field development. This article describes an ontology-based approach, which enables to select process equipment automatically, considering various stakeholders’ and regulatory requirements. The objective is to create architecture and an ontology-based knowledge model for an intelligent support system for oil and gas engineering based on the concept of augmented intelligence for oil and gas systems engineering Oil&Gas AugSE. The article suggests generalized system architecture, with the core being ontology of the facilities and processes related to field development; the authors also developed a multilayer structure for ontological models and databases. The architecture is the basis for the algorithm that enables to configure well pad infrastructure at an oil field automatically.  

References

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2. Efendiyev G., Karazhanova M., Akhmetov D., Piriverdiyev I., Evaluating the degree of complexity of tight oil recovery based on the classification of oils, Visnyk Taras Shevchenko Natl Univ Kyiv Geol., 2020, no. 1(88), pp. 76 – 81, DOI:10.17721/1728-2713.88.11

3. Madni A.M., Exploiting augmented intelligence in systems engineering and engineered systems, Insight, 2020, V. 23, no. 1, DOI:10.1002/inst.12282

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9. Engen S., Falk K., Muller G. The need for systems awareness to support early-phase decision-making—A study from the Norwegian Energy Industry, Systems, 2021, V. 9(3), 47, DOI:10.3390/systems9030047

10. Muller G., Falk K., What can (Systems of) systems engineering contribute to oil and gas? An illustration with case studies from subsea, In: 2018 13th System of Systems Engineering Conferenceb 2018, pp. 629–635, DOI:10.1109/SYSOSE.2018.8428724

11. Glukhikh I.N., MozhchilA.F., Pisarev M.O. et al., Evaluating the cost efficiency of systems engineering in oil and gas projects, Applied System Innovation, 2020, no. 3(3), DOI:10.3390/asi3030039

12. Khasanov M.M., Maksimov Yu.V., Skudar’ O.O. et al., Value-Driven Engineering in Gazprom Neft (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2019, no. 12, pp. 6–11, https://doi.org/10.24887/0028-2448-2019-12-6-11

13. Yakovlev V.V., Khasanov M.M., Sitnikov A.N. et al., The direction of cognitive technologies development in the Upstream Division of Gazprom Neft Company (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 6, pp. 6–9, https://doi.org/10.24887/0028-2448-2017-12-6-9

14. Shushakov A.A., Bilinchuk A.V., Pavlechko N.M. et al., ERA:Production – an integrated platform for increasing the efficiency of the operation of the artificial lift and oil fields (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 12, pp. 60–63, https://doi.org/10.24887/0028-2448-2017-12-60-63

15. Hagedorn T., Bone M., Kruse B., Grosse I., Blackburn M., Knowledge representation with ontologies and semantic web technologies to promote augmented and artificial intelligence in systems engineering, Insight, 2020, V. 23(1), pp. 15-20, DOI:10.1002/inst.12279

16. Baclawski K., Bennett M., Berg-Cross G. et al., Ontology summit 2020 communiqué: Knowledge graphs, Applied ontology, 2021, V. 16, no. 2, pp. 229-247, DOI:10.3233/AO-210249

The conceptual sedimentation model is important in the study of region geology. Working with actual geological and geophysical data, a specialist transforms abstract models taking into account the most probable scenario for the development of geological processes at a certain point in time within a specific study area. Adding a time factor to the model can significantly increase its informativeness. For example, a conceptual model can be represented through a description of the sequence of processes in their relationship within the formation of one or more clinocyclites and their sequential visualization in the style of "freeze frame" or the so-called "slicing" of frames. This option can be considered as one of the possibilities of approaching the dynamic model. Dynamic sedimentation modeling significantly contributes to the creation of dynamic conceptual models; it allows directly observe simulated geological events step by step.

The article present a new approach, which involves the creation of a conceptual sedimentological model based on core study, well logging and seismic data, and considers the results of sedimentation modeling, on the example of one of the clinocyclites of the Neocomian clinoform complex. The use of sedimentation modeling in support of the conceptual model development for the layers of the Pym clinocyclite at one of the sites in the Khanty-Mansiysk autonomous district made it possible to highlight a number of features in the slope formation processes, to clarify the direction of sedimentary material movement to the foot of the slope, considering the hypsometry of the paleosurface, and further into the deep-water zone, to localize sedimentation depots.

References

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4. Reshenie VI Mezhvedomstvennogo stratigraficheskogo soveshchaniya po rassmotreniyu i prinyatiyu utochnennykh stratigraficheskikh skhem mezozoyskikh otlozheniy Zapadnoy Sibiri (Decision VI of the interdepartmental stratigraphic meeting on the review and adoption of refined stratigraphic schemes of the mesozoic deposits of Western Siberia), Novosibirsk: Publ. of SNIIGGiMS, 2004, 113 p. 

5. Otoo D., Hodgetts D., Applying forward stratigraphic modeling approach to enhance facies characterization and fluid mobility prediction in geological models of basin floor fans, Basin Analysis and Petroleum Geoscience Group, School of Earth and Environmental Sciences, Williamson Building, Oxford Road, Manchester. M13 9PL. United Kingdom, 2018.

6. Ryseth A., Augustson J., Charnock M. et al., Cenozoic stratigraphy and evolution of the sørvestsnaget basin, southwestern Barents sea, Norwegian Journal of Geology, 2003, V. 83 (10), pp. 107–129.

7. Acevedo A., Madhoo H.A., Khramtsov A. et al., Techniques to understand reservoirs associated with deepwater sedimentological processes, from basin to field scale - A case study, IPTC-18016-MS, 2014, DOI:10.2523/IPTC-18016-MS

8. Anindita I., Reservoir prediction and controlling factors of the cenozoic deepmarine system at the Sørvestsnaget Basin, Southwest Barents Sea, August 2019 Norwegian University of Science and Technology Faculty of Engineering Department of Geoscience and Petroleum, URL: https://ntnuopen.ntnu.no/ntnu-xmlui/bitstream/handle/11250/2634445/no.ntnu%3Ainspera%3A39254300%3A21...

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10. Ol’neva T.V., Ovechkina V.Yu., Zhukovskaya E.A., Computer modeling of terrigenous sedimentation as a new tool for prediction of hydrocarbon reservoir architecture (In Russ.), PROneft’. Professional’no o nefti, 2020, no. 2, pp. 12–17, DOI: 10.7868/S2587739920020019

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The results of modified optimization algorithm for nonlinear AVAZ inversion are presented in the paper. Data of reflected compressional waves in anisotropic media is used. The algorithm based on exact formulas for reflection coefficients applied to processing and interpretation of 3D full-azimuth seismic data. Seismic survey was performed at one of the fields in the Orenburg area. The modified algorithm is differentiated on three stages. At the first stage, second-order Ruger approximation is used to estimate the symmetry axis direction of the anisotropic HTI medium. Using Ruger approximation allows to reduce the number of estimated parameters on the next stages, on which computationally expensive exact formulas are used. At the second stage, shear wave velocity is estimated from data in the isotropy plane. Anisotropy parameters are estimated at the last stage from reflection coefficient data for all offsets and azimuth. Differentiation on different stages allows to increase robustness of optimization, increase accuracy of estimated anisotropy parameters, and decrease computational time costs. The modified algorithm is compared with traditional approach with linearization of reflection coefficients by Ruger approximation. Results are presented in the form of vector maps of anisotropic parameters distribution: parameter for Ruge approximation Bani and Thomsen parameter γ for exact formulas. From comparison analysis it could be concluded that AVAZ inversion algorithm based on exact formulas provides higher resolution of parameters distribution. The areas with increased anisotropy highlighted on the vector maps could be interpreted as areas with more ordered reservoir fracturing. Comparison with attribute analysis shows correspondence of results. Spotting areas with increased fracturing from higher anisotropy in combination with other dynamic attributes allows to identify areas with better filtration characteristics of the reservoir, which are more favorable for drilling.

References

1. Rüger A., Reflection coefficients and azimuthal AVO analysis in anisotropic media, Society of Exploration Geophysics, 2001, 185 p., DOI:10.1190/1.9781560801764

2. Nefedkina T.V., Lykhin P.A., Applicability of the linearized approximation of the P-wave reflection coefficients for the azimuthal PP-reflection amplitude analysis in anisotropic media (In Russ.), Tekhnologii seysmorazvedki, 2016, no. 4, pp. 21–32, DOI: 10.18303/1813-4254-2016-4-21-32

3. Bakulin A., Grechka V., Tsvankin I., Estimation of fracture parameters from reflection seismic data – Part I: HTI model due to a single fracture set, Geophysics, 2000, V. 65, no. 6, pp. 1788–1802, DOI:10.1190/1.1444863

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5. Lykhin P.A., Nefedkina T.V., The potential of non-linear AVOA-inversion of PP-reflections for exploring fractured carbonate reservoirs (In Russ.), Tekhnologii seysmorazvedki, 2017, № 2, pp. 59–68, DOI: 10.18303/1813-4254-2017-2-59-68

6. Nefedkina T.V., Lykhin P.A., Dugarov G.A., Determination of azimuthal anisotropic media elastic parameters from multiwave AVOA data by nonlinear optimization method (In Russ.), Geofizicheskie tekhnologii, 2018, no. 2, pp. 14–26, DOI: 10.18303/2619-1563-2018-2-2

7. Dugarov G.A., Nefedkina T.V., Bogatyrev I.Yu. et al., Application of AVAZ inversion algorithm based on exact formulas to a wide-azimuth seismic survey data (In Russ.), PROneft’. Professional’no o nefti, 2021, V. 6, no. 2, pp. 12–19, DOI: 10.51890/2587-7399-2021-6-2-12-19

8. Tsvankin I., Reflection moveout and parameter estimation for horizontal transverse isotropy, Geophysics, 1997, V. 62, no. 2, pp. 614–629, DOI:10.1190/1.1444170

9. Luo M., Evans B.J., 3D fracture assessment using AVAz and a layer-stripping approach, Exploration Geophysics, 2003, V. 34, pp. 1–6, DOI:10.1071/EG03001

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11. Bayuk I.O., Ryzhkov V.I., Determination of parameters of fractures and pores in carbonate reservoirs according to wave acoustic logging data (In Russ.), Tekhnologii seysmorazvedki, 2010, no. 3, pp. 32–42.

12. Luo M., Arihara N., Wang S., Di B., Wei J., Abnormal transmission attenuation and its impact on seismic-fracture prediction – A physical modeling study, Geophysics, 2006, V. 71, no. 1, pp. D15–D22, DOI:10.1190/1.2159048

13. Gurevich B., Brajanovski M., Galvin R.J. et al., P-wave dispersion and attenuation in fractured and porous reservoirs – poroelasticity approach, Geophysical Prospecting, 2009, V. 57, pp. 225–237, DOI:10.1111/j.1365-2478.2009.00785.x

For field exploration planning with the purpose to achieve balance between investments and receiving information it is necessary to estimate geological risks and define zones of geological uncertainty. Obviously low data quantity and quality leads to higher uncertainty of parameters and reserves estimation. Moreover, geological objects with the same data density but different geneses have different range of uncertainty. This fact highlights the need to add one more variable to estimation – geological complexity, which represents integration of geological features for the studied object. The methodology, described in this article, allows mapping a geological confidence (analogue of variation map, but without multiple geological 3D realizations). The confidence map considers combination of data density maps (quantity and quality of investigation) and geological complexity maps (lateral and vertical heterogeneity) of the following volumetric parameters: porosity, net pay thickness, oil production area, oil saturation. The values of confidence range from 0 to 1, where 0 – minimum confidence (maximum of uncertainty), 1 – maximum confidence (minimum of uncertainty). Confidence equals to 1 characterizes full number of well and field investigations for particular parameter. One of the advantages of this approach is the possiblity to identify the source of uncertainty – lack of data or high complexity of geological characteristic that is required to be explored. Visualization volumetric parameters confidence in 2D allows appraise the areas with minimum and maximum uncertainty and risk on the particular target and plan actions to deal with them.

References

1. Fofanova E.A., Pavel’eva Yu.N., Mel’nikova O.A. et al., Geological data density (In Russ.), PRONEFT’’. Professional’no o nefti, 2022, V. 7, no. 1, pp. 22–29, DOI: 10.51890/2587-7399-2022-7-1-22-29

2. Fofanova E.A., Pavel’eva Yu.N., Mel’nikova O.A. et al., Quantitative assessment of areal geological complexity (In Russ.), PRONEFT’’. Professional’no o nefti, 2021, V. 6, no. 4, pp. 54–61, DOI: 10.51890/2587-7399-2021-6-4-54-61

In the context of constant external economic changes, the relevant task in the development of oil and gas companies in effective solution of incoming business challenges, is to increase hydrocarbon production along with cost optimization. In this regard, the verification of residual oil reserves with the simultaneous search for ways to increase the profitability of business cases becomes an urgent task. Due to the presence of complicating factors, the energy state of the reservoir and the gathering system, a number of problems related to non-achievement of oil production objectives are arose. For this reason, it becomes extremely important to have an integrated approach to solving this problem.

The article considers a practical implementation of the recoverable production efficiency module on the example of the Gazprom Neft operating fields. The full cycle process involves both a high-level assessment of the current object/field development condition and the detection of possible geological, technological and infrastructure problems that affect the oil production profiles and the achievement of planned development indicators. The algorithm of the developed module makes it possible to analyze each section particularly based on various attributes, to assess the current object condition based on the calculation of two rates (the rate of complexity and the rate of development), which prove an opportunity to predict oil production both in the short and long terms. Automation of this module allows to make a decision for the development of an additional program of well interventions, as well as significantly save engineers time.

References

1. Sukhodanova S.S., Khaliullin F.F., Vorob'ev V.S. et al., Recoverable production efficiency of remaining reserves as an instrument of potential assessment of oil production (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 10, pp. 59–63, DOI: 10.24887/0028-2448-2021-10-59-63

2. Dake L.P., The practice of reservoir engineering, Elsevier Science, 2001, 570 p.

3. Lysenko V.D., Razrabotka neftyanykh mestorozhdeniy. Effektivnye metody (Development of oil fields. Effective methods), Moscow: Nedra-Biznestsentr, 2009, 552 p.

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

5. Yushkov I.R., Khizhnyak G.P., Ilyushin P.Yu., Razrabotka i ekspluatatsiya neftyanykh i gazovykh mestorozhdeniy (Development and operation of oil and gas fields), Perm: Publ. of PSTU, 2013, 177 p.

The development of oil and gas fields can be complicated by forming gas hydrates at the bottom, in the downhole zone, and in wellbores. It is reliably known that gas hydrate issues during production occur in many Eastern Siberian fields characterized by low reservoir temperatures. Current research in this direction is limited to predicting the gas hydrates formation depending on the thermobaric conditions of well operation. The influence of salt solutions injection into the reservoir under the Chayandinskoye oil-gas-condensate field conditions (pressure and temperature) is studied in order to establish the boundary level of water mineralization preventing the hydrate formation. The calculation of equilibrium conditions for the formation of gas hydrates of the model gas of the Chayandinskoye field and mineralized water from water wells and formation water of the Srednebotuobinskoye field is compared with experimental data in high-pressure autoclaves, which established "safe" in terms of complete prevention of hydrate formation threshold concentrations of 16 wt. % and 20.1 wt. % at reservoir temperature 9 °С and pressures 13 and 30 MPa, respectively. The modes and criteria for nucleation and formation of gas hydrates in the flow and in the static mode are determined using a slim-tube model of two-phase flow of model gas and water of varying salinity. The final result in this work was the determination of a threshold level of brine salinity guaranteeing the absence of hydrate complications of brines at the contact between the liquid phase and the gas-cap gas in the wellbore, ensuring a hydrate-free flow regime in the reservoir conditions of the Chayandinskoye field. The data obtained will form the basis of subsequent tests on core models to assess the risks of hydrate formation in the porous medium when salinity water is injected into the reservoir.

References

1. Sloan E.D., Koh C., Sum A.K., Natural gas hydrates in flow assurance, New York: Elsevier, 2010, 224 p.

2. Chong Z.R., Yang S.H.B., Babu P. et al., Review of natural gas hydrates as an energy resource: prospects and challenges, Appl. Energy, 2016, V. 162, pp. 1633–1652, DOI:10.1016/j.apenergy.2014.12.061

3. Cheng C., Zhao J., Zhu Z. et al., Evaluation of gas production from methane hydrates using depressurization, thermal stimulation and combined methods, Appl. Energy, 2015, V. 145, pp. 265–277, DOI:10.1016/j.apenergy.2015.02.040

4. Sloan E.D., A changing hydrate paradigm–from apprehension to avoidance to risk management, Fluid Phase Equilibria, 2005, V. 228, pp. 67–74, DOI:10.1016/j.fluid.2004.08.009

5. Sum A.K., Koh C.A., Sloan E.D., Developing a comprehensive understanding and model of hydrate in multiphase flow: from laboratory measurements to field applications, Energy Fuels, 2012, no. 26, pp. 4046–4052, DOI: 10.1021/ef300191e

6. Di Lorenzo M., Aman Z.M., Kozielski K. et al., Underinhibited hydrate formation and transport investigated using a single-pass gas-dominant flowloop, Energy Fuels, 2014, no. 28, pp. 7274–7284, DOI: 10.1021/ef501609m

7. Nicholas J.W., Dieker L.E., Sloan E.D., Koh C., Assessing the feasibility of hydrate deposition on pipeline walls – Adhesion force measurements of clathrate hydrate particles on carbon steel, J. Colloid Interface Sci., 2009, V. 331, pp. 322–328, DOI: 10.1016/j.jcis.2008.11.070

8. Kakkattu S.S., Ramachandran C.N., Natural gas evolution in a gas hydrate melt: Effect of thermodynamic hydrate inhibitors, J. Phys. Chem. B., 2017, V. 121, pp. 153–163, DOI: 10.1021/acs.jpcb.6b07782

9. Cha J.H., Ha C., Kang S.P., Thermodynamic inhibition of CO2 hydrate in the presence of morpholinium and piperidinium ionic liquids, Fluid Phase Equilibria, 2016, V. 413, pp. 75-79, DOI: 10.1016/j.fluid.2015.09.008

10. Sylva T.Y., Kinoshita C.K., Masutani S.M., Inhibiting effects of transition metal salts on methane hydrate stability, Chem. Eng. Sci., 2016, V. 155, pp. 10–15, DOI: 10.1016/j.ces.2016.06.028

11. Kratkaya entsiklopediya neftegazovoy geologii (Brief encyclopedia of petroleum geology): edited by Vyakhirev R.I., Moscow: Publ. of Academy of Mining Sciences, 1998, 576 p.

12. Ryzhov A.E., Krikunov A.I., Ryzhova L.A., Kanunnikova N.Yu., Refinement of the geological model of the Chayandinskoye oil and gas condensate field (In Russ.), Vesti gazovoy nauki, 2011, no. 1(6), pp. 132–145.

13. Kalacheva L.P., Rozhin I.I., Sivtsev A.I., Studying the possibility of hydrate formation and salt deposition in the bottom hole of wells of Chayanda oil-gas-condensate field (In Russ.), Neftegazovaya geologiya. Teoriya i praktika, 2018, no. 4, pp. 1-16, DOI: 10.17353/2070-5379/42_2018

14. Semenov A.P., Mendgaziev R.I., Tulegenov T.B., Analysis of the techniques for measuring the equilibrium conditions of gas hydrates formation (In Russ.), Khimiya i tekhnologiya topliv i masel, 2022, no. 4, pp. 50–56, DOI: 10.32935/0023-1169-2022-632-4-50-56

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16. Stoporev A.S., Ogienko A.G., Altunina L.K., Co-deposition of gas hydrate and oil wax from water-in-crude oil emulsion saturated with CO2, In: IOP Conference Series: Earth and Environmental Science, 2018, V. 193, DOI:10.1088/1755-1315/193/1/012042

The technology of the reservoir pressure maintaining is associated with a number of problems related with the development of waterflooding induced fractures formed due to a high injection pressure (waterflooding fractures). One of these problems is the possibility of a breakthrough of the injected fluid into an neighbor well through a waterflooding fracture, which leads to the necessity for shutting down the entire row of injection wells to in case of repair and, accordingly, reduces the effectiveness of the reservoir pressure maintenance. Thus, it is important to understand what factors influence on the fracture merging process.

The article considers the waterflooding fracturing in a sector of the development layout with an line-drive woterflooding system and estimation of the time needed for the merging of several fractures initiated from the adjacent injection wells via mathematical modeling. For the sector of the development layout, a complex analysis of field data was carried out using the well-known approaches (Hall plot, step-rate test, reservoir pressure analysis). Based on the conservation laws of continuum mechanics and the constitutive equations for a poroelastic medium, a numerical model for the propagation of waterflooding fractures is developed. As input data for the model, the characteristic parameters of the field, the location of the wells and the scheme for putting the wells into operation were taken. The numerical simulations show that the process of the waterflooding fracture growth is affected by a complex filtration process between injection and production wells in the sector of development layout. In this case, the relative location and distance between wells plays a significant role. Since the merging of waterflooding fractures impact on reservoir pressure maintenance, then to design this process it is necessary to simulate waterflooding fractures within the framework of a coupled geomechanical and hydrodynamical problem. Numerical simulation makes it possible to evaluate the trend of the dependence of the time needed for waterflooding fractures merging on the distance between wells for a specific well location.

References

1. Bazyrov I.Sh., Shel' E.V., Khasanov M.M., Efficiency evaluation of waterflooding of low-permeability reservoirs by horizontal wells with water-injection induced fractures (In Russ.), PRONEFT''. Professional'no o nefti = PROneft. Professionally about Oil, 2020, no. 2, pp. 52–60, DOI:10.7868/S258773992002007X

2. Shel' E.V., Kabanova P.K., Tkachenko D.R. et al., Modeling of a hydraulic fracture initiation and propagation on an injection well for non-fractured terrigenous rocks on the Priobskoye field (In Russ.), PRONEFT''. Professional'no o nefti = PROneft. Professionally about Oil, 2020, no. 2, pp. 36–42, DOI: 10.7868/S2587739920020056

3. Islamov A.I., Faskhutdinov R.R., Kolupaev D.Yu., Vereshchagin S.A., On the mechanisms of the formation of zones with abnormally high rock pressure and methods for predicting them in undeveloped rock systems, Priobskoye field case study (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2018, no. 7, pp. 54–59, https://doi.org/10.24887/0028-2448-2018-10-54-59

4. Baykov V.A., Davletbaev A.Ya., Usmanov T.S., Stepanova Z.Yu., Special well tests to fractured water injection wells (In Russ.), Neftegazovoe delo, 2011, no. 1, pp. 65-75, URL: http://ogbus.ru/files/ogbus/authors/Baikov/Baikov_1.pdf

5. 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.

6. Davletbaev A., Baikov V., Bikbulatova G. et al., Field studies of spontaneous growth of induced fractures in injection wells, SPE-171232-MS, 2014, https://doi.org/10.2118/171232-MS

7. Hwang J., Zheng S., Sharma M. et al., Containment of water-injection-induced fractures: the role of heat conduction and thermal stresses, SPE-200400-RA, 2020, DOI: 10.2118/200400-PA

8. Bazyrov I.S., Shel E.V., Gimazov A.A. et al., Case study on waterflooding of low-permeability reservoirs by horizontal wells with water-injection induced fractures, American rock mechanics association, 54th US Rock Mechanics, Geomechanics Symposium, 2020, DOI:10.2118/ARMA-2020-1642

9. Gimazov A., Bazyrov I., The development method of low-permeability and ultra-low-permeability reservoirs by waterflooding, SPE-206416-MS, 2021, DOI: 10.2118/206416-MS

10. Coussy O., Poromechanics, John Wiley & Sons Ltd., 2004, DOI:10.1002/0470092718

11. Izgec B., Kabir C.S., Real-time performance analysis of water-injection wells, SPE 109876-RA, 2009, DOI: 10.2118/109876-PA

12. Golovin S.V., Baykin A.N., Influence of pore pressure on the development of a hydraulic fracture in poroelastic medium, Int. J. Rock Mech. Mining Sci., 2018, V. 108, pp. 198–208, DOI: 10.1016/j.ijrmms.2018.04.055

13. Vandamme L.M., Roegiers J.-C., Poroelasticity in hydraulic fracturing simulators, Journal of Petroleum Technology, 1990, V. 42(9), pp. 1199–1203, DOI: 10.2118/16911-PA

14. Dontsov E.V., Peirce A.P., Comparison of toughness propagation criteria for blade-like and pseudo-3D hydraulic fractures, Engineering Fracture Mechanics, 2016, V. 160, pp. 238–247, DOI: https://doi.org/10.1016/j.engfracmech.2016.04.023

The Eastern area of the Orenburg oil and gas condensate field is a troublesome a target for field development due to low reservoir properties and a gas cap presence. The field is characterized by block structure. Blocks 2 and 3 have system of more extensional and permeable fractures, for this reason water injection at these objects is low efficiency. Therefore, Block 1 with a more uniform and much less dense system of microcracks was chosen as the main area for considering the enhanced oil recovery technology application. To increase the sweep and displacement efficiency, it is necessary to apply non-standard technologies, such as radial drilling and carbon dioxide injection. To evaluate the effectiveness of these technologies at the initial stage of project development in a fairly short time with the possibility of multivariate calculations, an approach was developed that consists of three stages. The first stage is selection of a sector from a full-scale hydrodynamic model, its history matching and base case calculation. The second stage is performing calculations for carbon dioxide injection, obtaining a one average well profile. At the third stage obtained profile is replicated for all wells according to the developed methodology. The article describes an approach to modeling carbon dioxide injection, which makes it possible to quickly evaluate the technology effectiveness for a single well and not use a full-scale hydrodynamic model, as well as a method for the calculation result replication using the developed calculation module in Excel, which allows to accelerate, optimize and automate the replication process.

References

1. Antoniadi D.G., Uvelichenie nefteotdachi plastov gazovymi i parogazovymi metodami (Increased oil recovery by gas and combined-cycle methods), Moscow: Nedra Publ., 1998, 304 p.

2. Nekrasov A.V., Maksakov K.I., Usachev G.A. et al., Optimization of the technological efficiency of CO2 injection in extra-viscous oil deposits using laboratory studies and numerical modeling (In Russ.), Geologiya, geofizika i razrabotka neftyanykh i gazovykh mestorozhdeniy, 2019, no. 8, pp. 81–86, DOI: 10.30713/2413-5011-2019-8(332)-81-86

3. Kyzyma K.Yu., Khoryushin V.Yu., Semenenko A.F. et al., Potential of acid tunneling technology on the fields "Gazpromneft Orenburg" (In Russ.), PRONEFT''. Professional'no o nefti, 2021, no. 1 (19), pp. 47–53, DOI: 10.51890/2587-7399-2021-6-1-47-53

4. Sukhodanova S.S., Fayzullin R.R., Gerasimenko P.N. et al., Technologies of radial drilling in the conditions of carbonate reservoirs as a way to increase oil production. From theory to large-scale pilot projects (In Russ.), PRONEFT''. Professional'no o nefti, 2022, no. 1 (23), pp. 52–63, DOI: 10.51890/2587-7399-2022-7-3-52-62

Chemical methods for enhanced oil recovery in general and surfactant-polymer (SP) flooding in particular are considered as a promising technology for developing mature oil fields in Western Siberia, with the potential to increase oil recovery to 60-70% of the initial geological reserves. The selection of an effective mixture of surfactants and polymer for SP flooding is a complex and multi-stage process. Usually, the choice of chemical composition and modeling on the hydrodynamic model is carried out under isothermal condition. However, recently some authors have been paying attention to the temperature aspects of SP flooding. According to these studies, the change in reservoir temperature because of long-term injection of unheated water can play a decisive role in the choice of chemical composition and hydrodynamic simulation of SP flooding. Firstly, temperature significantly affects oil-water interfacial tension (IFT), on which the oil displacement coefficient of the SP composition depends. Secondly, the viscosity of the polymer solution and, consequently, the sweeping efficiency during SP flooding depends on the temperature.

In this article, the temperature profile was evaluated in the SP flooding pilot site, where flooding with unheated water was carried out for 12 years. Initially, the downhole temperature in the injection well was calculated based on analytical functions, which was then confirmed by field studies. As it turned out, the downhole temperature in the injection well is 42°C, which is 45°C less than the initial reservoir temperature. At the second stage, with the help of analytical functions and hydrodynamic simulation, the temperature profile in the SP flooding pilot site was estimated. Calculations have shown that the injection of unheated water over a 12-year period significantly cooled the reservoir in the pilot area. The temperature around the well designed for injection of the SP composition is 70°C, which is 17°C less than the initial reservoir temperature and with further injection of the unheated SP composition, the temperature around this well will fall. This circumstance must be considered when choosing surfactants and polymers that must have effective oil-displacing properties over a wide temperature range.

References

1. Bondar M., Osipov A., Koltsov I. et al., Evaluating efficiency of surfactant-polymer flooding with single well chemical tracer tests at Kholmogorskoye field, SPE-207314-MS, 2021, DOI:10.2118/207314-MS

2. Volokitin Y., Shuster M., Karpan V. et al., Results of alkaline-surfactant-polymer flooding pilot at West Salym field, SPE -190382-MS, 2018, DOI:10.2118/190382-MS

3. Sheng J.J., Enhanced oil recovery field case studies, 1st Edition, 2013, DOI:10.1016/C2010-0-67974-0

4. Soltani A., Decroux B., Negre A. et al., Evaluating the impact of reservoir cooling on the surfactant flood efficiency, IPTC-21351-MS, 2021, DOI:10.2523/IPTC-21351-MS

5. Malofeev G.E., Mirsaetov O.M., Cholovskaya I.D., Nagnetanie v plast teplonositeley dlya intensifikatsii dobychi nefti i uvelicheniya nefteotdachi (Injection of heat carriers into the reservoir to stimulate oil production and increase oil recovery), Moscow–Izhevsk: Publ. of Institute for Computer Science, 2008, 224 p.

6. Marx J.W., Langenheim R.H., Reservoir heating by hot fluid injection, Petroleum Transactions AIME, 1959, V. 216, pp. 312–315, DOI:10.2118/1266-G

7. Quintero L., Jones T.A., Pietrangeli G.A., Proper design criteria of microemulsion treatment fluids for enhancing well production, SPE-154451-MS, 2012, DOI: https://doi.org/10.2118/154451-MS

8. Karnanda W., Benzagouta M.S., Quraishi A.Al. et al., Effect of temperature, pressure, salinity, and surfactant concentration on IFT for surfactant flooding optimization, Arabian Journal of Geosciences, 2013, V. 6, pp. 3535-3544, DOI: https://doi.org/10.1007/s12517-012-0605-7

9. Douarche F., Rousseau D., Bazin B. et al., Modeling chemical EOR processes: Some illustrations from lab to reservoir scale, Oil & Gas Science and Technology – Rev. IFP Energies nouvelles, 2012, V. 67, no. 6, pp. 983–997, DOI: https://doi.org/10.2516/ogst/2012059

10. Hirasaki G., Miller C.A., Puerto M., Recent advances in surfactant EOR, SPE-115386-PA, 2011, DOI: https://doi.org/10.2118/115386-PA

11. Turnaeva E.A., Sidorovskaya E.A., Adakhovskiy D.S. et al., Oil emulsion characteristics as significance in efficiency forecast of oil-displacing formulations based on surfactants (In Russ.), Izvestiya vuzov. Neft' i gaz, 2021, no. 3, pp. 91–107, DOI: https://doi.org/10.31660/0445-0108-2021-3-91-107

The article discusses the theoretical foundations, world experience, as well as the key results of laboratory studies of the enzyme composition used to stimulate oil production and as a enhanced oil recovery method. Currently, there are some of the problems at fields with low temperature, high oil viscosity and high reservoir properties such as the impossibility to create a high drawdown on the reservoir (in conditions of shallow reservoirs), the migration of reservoir particles and, as a result, clogging of the liner filter, which in turn causes decrease in production rate for many wells, especially for sand-bearing wells working for objects with high-viscosity oil. The formation of a filter cake on the filter part of the liner consisting of a mixture of high-viscosity oil and sandstone particles, as well as the low phase permeability for oil of a hydrophobic reservoir, can partially or completely block the flow of fluid into the well and act as a local skin factor in the bottomhole formation zone. The solution to this problem can be methods that reduce the viscosity of oil: thermal and chemical, one of which is the use of an enzyme composition to destroy high-molecular compounds of hydrocarbons and to change the wettability of the reservoir to hydrophilic. To confirm these effects, laboratory filtration studies were carried out on core from the Vostochno-Messoyakhskoye field. Two groups of tests were carried out with enzyme concentrations of 2.5 and 10%, respectively, as a result, an increase in displacement ratio from 2.4 to 6.9% (depending on the concentration of the solution) was obtained and the recovery of phase permeability after enzyme filtration was 15% greater, than after water filtration.

References

1. Rahayyem M., Mostaghimi P., Alzahid Y.A. et al., Enzyme enhanced oil recovery EEOR: A microfluidics approach, SPE-195116-MS, 2019, DOI:10.2118/195116-MS

2. Tarang J., Dehradun A.S., New frontiers in EOR methodologies by application of enzymes, SPE-154690-MS, 2012, DOI: https://doi.org/10.2118/154690-MS

3. Liu He, Zhang Zhonghong, Biology enzyme EOR for low permeability reservoirs, SPE-144281-MS, 2011, DOI: https://doi.org/10.2118/144281-MS

4. Mukhametshin V.V., Shchetnikov V.I., Velieva O.V., Study of the efficiency of using enzyme solutions on oil reservoir models (In Russ.), Bashkirskiy khimicheskiy zhurnal, 2020, V. 27, no. 2, pp. 74–78, DOI: 10.17122/bcj-2020-3-74-76

5. Ott W.K., Thu Nyo, Win Nyunt Aung, Aung Thet Khaing, EEOR success in Mann Field, Myanmar, SPE-144231-MS, 2011, DOI: https://doi.org/10.2118/144231-MS

The article presents the basic principles and provisions of oilfield chemistry at Gazprom Neft. The definition of the concept of "Petroleum chemistry", the place and role of this functional area in the production chain and the standardization system are given. The purpose of chemicalization is formulated - ensuring the stability and safety of the technological process involving the use of a chemical reagent, minimizing risks and reducing unit costs. Achievement of the goal is ensured by solving a whole range of tasks, among which are: analysis of objects and environments, targeted selection, control and accounting of consumption, analysis of the effectiveness of the use of reagents, increasing the level of personnel competencies, R&D and involvement in cross-functional projects. The basic principles on which the work on oilfield chemistry is based are given: safety, risk minimization, comprehensive assessment, targeting, efficiency, alternativeness and validity of the use of reagents. The components of the system for the use of chemical reagents in the Company are shown, including technological processes, equipment, personnel. General and specific requirements for chemical reagents are discussed. The process of selecting and admitting reagents for industrial use is discussed in detail, starting from the stage of analysis of a production facility, through laboratory and pilot tests. Approaches to carrying out laboratory tests with different initial conditions are outlined. The procedure of "controlled operation" is described - conducting pilot tests according to a simplified scheme. In the final part, some key indicators for evaluating the effectiveness of the chemicalization system are presented, grouped by production areas: downhole operations, artificial lift, collection, transportation, preparation of hydrocarbons and water.

Regardless of the current geopolitical situation, the leaders of the oil and gas industry do not remove the principles and approaches for implementing ESG (Environmental, Social, and Corporate Governance) from the agenda and, in this regard, the development of CCUS (Carbon Capture, Use and Storage) is defined as a promising technology for reduce carbon dioxide emissions and contribute to the achievement of global climate goals. The main goal of the current study was a design a pilot project CCUS using the example of Salym Petroleum Development LLC. During the process the screening of sources and technologies for capturing carbon dioxide, the selection and justification of geological objects for storage, the calculation of the volume and operation mode of storage facilities on simulation models were carried out. The possibility of engaging third-party industrial carbon dioxide emitters was considered. As part of the project, the world experience in the field of carbon dioxide utilization was considered, including an analysis of the relevant world scientific and technical literature. Based on the results of the work, six possible scenarios were considered with different phasing of the project in terms of time and stages of putting objects into operation. The estimation of economic effect was made, the criteria for the project value formation were developed, and the main factors affecting the environmental safety of the project were identified. As a result, it is important to highlight that the decision on the further project development largely depends on external economic incentives, government subsidies and the imposition of a price on emissions above the established quotas, as well as progress in the field of import substitution of equipment for carbon dioxide capture technologies.

References

1. Kearns D., Liu H., Consoli Ch., Technology readiness and costs of CCS, Global CCS Institute, 2021, no. 3, URL: https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-of-CCS-...

2. Brinkerhoff P., CO2 capture at gas fired power plants, IEA, 2012, URL: https://www.globalccsinstitute.com/archive/hub/publications/103211/co2-capture-gas-fired-power-plant...

3. Commercial scale carbon capture for the storage in the deep underground and enchanced oil recovery (EOR), GeoResourses Journal, 2020, no. 4.

4. Carbon capture and storage. Progress and next steps, IEA/OECD, 2010, URL: https://www.regjeringen.no/contentassets/2c83ff97a35e408c86b1078486112eea/g8_2010_paper_june_2010.pd...

5. Miroshnichenko (Dymochkina) M.G., Metod poiska i vybor ob"ekta dlya zakhoroneniya kislykh gazov v nedrakh Astrakhanskogo svoda (The method of search and selection of an object for the disposal of acid gases in the depths of the Astrakhan arch), Moscow: Publ. of Gazprom VNIIGAZ, 2011.

The organization of an underground gas storage facility (UGS) at the Zapadno-Messoyakhsky area of the Vostochno-Messoyakhskoye field has been proposed in order to minimize economic costs and to significantly reduce environmentally harmful emissions into the atmosphere during the utilization of associated petroleum gas (APG). A feature of this UGS facility is the gas injection into a productive formation containing an oil rim and a gas cap. In this regard, it is necessary to prevent the dilution of oil reserves during the exploitation of the gas storage and ensure the inclusion of oil reserves in the development. As part of the project implementation, a cluster of injection gas wells was built, and control of changes in the gas cap of the PK1-3 formation associated with APG injection was organized.

The article considers the evaluation of a number of projected risks of the facility: dropout of hydrates in the reservoir, hydrate formation in the wells of the active fund, as well as clarification of the hydrodynamic connection of the facility blocks and the possible volume of gas injection before its breakthrough under the water-oil contact. The main tool is hydrodynamic reservoir model, which allow take into account the specifics of the geological structure, the history of the exploitation of the facility, and the decisions made to organize and control the underground storage facilities at the Zapadno-Messoyakhsky area. Recommendations were made on well operation modes to minimize risk of hydrate dropout. A tool was created to evaluate the dynamics of hydrate formation risks based on well operation data, measurements in control well and the results of hydrodynamic modeling. The volume of gas injection before breakthroughs into the oil rim and under the oil rim has been estimated. A number of recommendations were issued for the exploitation of underground storage facilities. The obtained results, tools and approaches to modeling can be used in the future to control the exploitation of underground storage facilities at Zapadno-Messoyakhsky area, as well as be applied to analogue facilities.

References

1. PB 08-621-03. Pravila sozdaniya i ekspluatatsii podzemnykh khranilishch gaza v poristykh plastakh (Rules for the creation and operation of underground gas storage facilities in porous reservoirs), approved by the Decree of the Gosgortekhnadzor of Russia No. 57 of 06/05/03, registered by the Ministry of Justice of the Russian Federation on 06/18/03 (No. 4715).

2. Makogon Yu.F., Gazovye gidraty, preduprezhdenie ikh obrazovaniya i ispol'zovanie (Gas hydrates, prevention of their formation and use), Moscow: Nedra Publ., 1985, 232 p.

3. Istomin V.A., Yakushev V.S., Gazovye gidraty v prirodnykh usloviyakh (Gas hydrates in natural conditions), Moscow: Nedra Publ., 1992, 237 p.

4. Brill J.P., Mukherjee H., Multiphase flow in wells, SPE Monograph, Henry L. Dogherty Series, V.17, 1999.

Over the past decade the share of hard-to-recover reserves in the structure of oil reserves of Russian Federation has increased by 20%, wherein the production has increased by 15%. Development of conventional reservoirs often requires finding non-standard solutions due to the high level of uncertainty. Particularly in order to decrease petrophysical uncertainty level the hi-tech methods of well logging and the advanced data interpretation approaches are required. In Russian oil and gas industry to accomplish with the challenging petrophysical tasks mostly the foreign technologies have been used. Under the sanctions restrictions conditions the foreign technologies implementation causes certain difficulties associated with evaluation of petrophysical properties of complex reservoirs.

To acquire the technological independence in the area of hi-tech well logging methods Rosneft Oil Company starting from 2017 is actively involved in the process of domestic technologies development by providing sites and facilities for pilot field trials and by planning further equipment development concept. Company subsidiaries and design institutes have analyzed over 400 well logging appliances (design specifications and calibration, methodology and bench test data availability), and over 100 pilot field trials results of hi-tech well logging appliances performed on the Company sites. In the course of work the Rosneft experts have been actively communicating with the well logging appliances manufacturers for improving methodology and getting better results. Intensive collaboration between Rosneft Oil Company and the equipment manufacturers pushed on the domestic well survey service to the next level.

References

1. Nefteservisnyy rynok Rossii: fokus na diversifikatsiyu (Oilfield services market in Russia: focus on diversification), URL: https://vygon.consulting/upload/iblock/b7d/l6ufuw6fwcjkavfffecnconjbbmn1t03/vygon_consulting_OFS_.pd...

2. Obzor nefteservisnogo rynka Rossii – 2018 (Overview of the Russian oilfield services market - 2018), URL: https://www.rogtecmagazine.com/wp-content/uploads/2019/07/02-Deloitte-Overview-of-the-Russian-Oil-Se...

3. International Energy Agency, URL: https://www.iea.org/

4. Kasatkin D., Geophysics market in Russia. Trends, structure, prospects (In Russ.), Oil&Gas Journal, 2018, no. 8(128).

5. Geologorazvedka i vospolnenie zapasov Kompanii (Geological exploration and replenishment of the Company’s reserves), URL: https://www.rosneft.ru/docs/report/2017/ru/results.html

6. Zelenov A.S., Soshin S.S., Tarasov S.Yu., Metrological support for nuclear magnetic logging in an artificial magnetic field (In Russ.), Karotazhnik, 2019, no. 2 (296), pp. 45–57.

7. Coates G.R., Lizhi Xiao, Prammer M.G., NMR logging principles and applications, Elsevier Science, 1999, 234 p.

8. Kimball C.V., Marzetta T.L., Semblance processing of borehole acoustic array data, Geophysics, 1984, V. 49, Issue 3, pp. 274-281, DOI:10.1190/1.1441659

The results of petrophysical and geochemical studies of limestones of the Lower Carbon age sampled from productive and water-bearing intervals are considered. Based on the integration of capillarometry data and the determination of relative phase permeabilities, the forecast of the nature of saturation along the height of the reservoir from the free water level (OWC1) to transition zone (OWC2) was carried out. Reservoir models using samples taken from productive and water-bearing intervals, and the thickness of the transition zone in each of these models was determined. The studies made it possible to establish that the residual oil in the pore space of the aquifer is oil bitumen rich in asphalt-resinous components. On the contrary, the residual oil in the pore space of samples taken from producing intervals is similar in composition and properties to the oil produced from these deposits. Samples from aquifers have lower reservoir properties than samples obtained from productive intervals. All boundaries distinguished by the height of the reservoir (from OWC1 to OWC2) in the reservoir model built using samples from the aquifers are located higher than the same boundaries obtained on the model of the same reservoir, built from samples taken from productive interval. There is a high content of residual oil (oil bitumen) in the limestones under consideration, especially those taken from the aquifer near the OWC2 boundary, which necessitates the development of methods for enhancing oil recovery from these rocks.

References

1. Zubkov M.Yu., The idea of "residual water saturation" and how to evaluate it in laboratory conditions (In Russ.), Karotazhnik, 2015, no. 7 (253), pp. 63–78.

2. Knutsen C.F., Definition of water table: GEOLOGICAL NOTES, Am. Assoc. Petrol. Geologists, 1954, V. 38, DOI:10.1306/5CEAE064-16BB-11D7-8645000102C1865D

The article describes a case history of geomechanical modeling for drilling wells in a zone with active geodynamics. Two vertical wells have been drilled in the site by the time of work performing. While drilling, there were complications connected with subsurface geology. The field is located in the Arabia-Eurasia continental collision zone. To evaluate the risks of potential horizontal well drilling, it was decided to perform an in-depth complex analysis of the well log using 1D geomechanical modeling. Analysis of drilling events has shown that work area is characterized by high probability of borehole wall collapse and fluid loss, especially in Upper Cretactous formations. The main difficulty in building 1D geomechanical models is a limited range of source data. Modeling is made on the base of taken from literature dependency reports for the calculation of stress-related properties with additional model ratio adjustments. Range of studied well log is about 3000 m. The well log is represented by interlayering of various carbonaceous and terrigenous sublayers significantly differing in the values of stress-related properties. Corresponding dependencies of longitudinal and transverse wave slowness and density recovery have been selected and justified for each interval. Stress-related properties have been calculated with consideration of lithological column for each well. Due to the absence of specialized studies concerning hydraulic fracturing of formation closure pressure, calibration of minimal horizontal stress has been made using FIT data. Calibration of minimum horizontal stress and ratios in dependencies for the calculation of stress-related properties is made in such a way that lets the final model to credibly describe drilling events and destruction intervals registered by data calipers simultaneously at all wells. Using modeling results, safe drilling windows for the estimated horizontal well path are calculated and recommendations for the following trouble-free drilling are formed. Obtained modeling results may be used in preparation of project documentation for the construction of horizontal well sat this field.

References

1. Zoback M.D., Reservoir geomechanics, Stanford University, California, 2007, DOI: https://doi.org/10.1017/CBO9780511586477

2. Morales R.H., Marcinew R.P., Fracturing of high-permeability formations: mechanical properties correlations, SPE-26561-MS, 1993, DOI: https://doi.org/10.2118/26561-MS

3. Khaksar A., Taylor P.G., Fang Z. et al., Rock strength from core and logs: where we stand and ways to go, SPE-121972-MS, 2009, DOI: https://doi.org/10.2118/121972-MS

4. Santos E.S.R., Ferreira F.H., Mechanical behavior of a Brazilian off-shore carbonate reservoir, Proceedings of 44th US Rock Mechanics Symposium and 5th US-Canada Rock Mechanics Symposium, Salt Lake City, Utah, June 2010, ARMA-10-199.

5. Odunlami T., Soroush H. et al., Log-based rock property evaluation – a new capability in a specialized log data management platform, SPE-149050-MS, 2011, DOI: https://doi.org/10.2118/149050-MS

6. Holt Erling Fjar R.M., Raaen A.M., Horsrud P., Petroleum related rock mechanics, Great Britain: Elsevier, 2008, 514 p.

7. Skiena S.S., The data science design manual, Springer, 2017, 446 p.

8. World Stress Map, 2009-2022, URL: http://www.world-stress-map.org

The selection of drilling fluid model has a significant impact on the efficiency of the initial opening of productive formations by drilling. There are two main models described in the literature. The first model is a drilling fluid that qualitatively seal formation pores, decreasing the area of degraded reservoir properties. The second model is characterized by deeper penetration into the reservoir without causing significant degradation of its properties. In the development and testing of drilling fluids, the criterion for maintaining the reservoir properties is the coefficient, obtained by comparing cores permeability measurements before and after the flooding experiments. Calcium carbonate is often used to prevent penetration of drilling fluid and its filtrate into the reservoir. However, in the case of application in emulsion drilling fluid when drilling wells where perforation is not provided, additional work is often required to restore hydrodynamic communication with the formation. Therefore, research on sealing properties of emulsion drilling fluid, including necessity of bridging agent, is relevant. On that purpose, a laboratory study on the sealing pores ability of the emulsion drilling fluid formulation developed for drilling wells in Eastern Siberia, and its effect on the core permeability coefficient was carried out. The results of the study showed that the characteristic high sealing pores ability is provided by the composition of the mud, taking into account the composition and properties of the reservoir and a solid phase, and the use of calcium carbonate in the developed drilling fluid is not advisable.

References

1. Ryabokon’ S.A., Balovskaya V.I., Shafranik S.K., Kosilov A.F., Small diameter wells (In Russ.), Interval, 2002, no. 8, pp. 51–59.

2. Zhivaeva V.V., Nechaeva O.A., Nikitin V.I., Application of calculated criteria to select reservoir penetrating fluid (In Russ.), Neft’. Gaz. Novatsii, 2018, no. 6, pp. 48–50.

3. Nekrasova I.L., Improvement of the criteria for assessing the quality of hydrocarbon-based muds in terms of geological conditions of their use (In Russ.), Vestnik Permskogo natsional’nogo issledovatel’skogo politekhnicheskogo universiteta. Geologiya. Neftegazovoe i gornoe delo, 2018, V.18, no. 2, pp. 129–138, DOI: https://doi.org/10.15593/2224-9923/2018.4.3

4. Yanuzakov U.N., Gorbunova A.A., Gabdrafikov R.V., Komkova L.P., Assessment of core permeability restoration factor effect upon well rate during the initial penetration into productive horizons at the fields of republic of Bashkortostan (In Russ.), Neft’. Gaz. Novatsii, 2021, no. 8, pp. 41–43.

5. Nutskova M.V., Sidorov D.A., Tsikplonu D.E. et al., Investigations of oil based muds to primary opening of productive formations (In Russ.), Vestnik Permskogo natsional’nogo issledovatel’skogo politekhnicheskogo universiteta. Geologiya. Neftegazovoe i gornoe delo, 2019, V. 19, no. 2, pp. 138–149, DOI: 10.15593/2224-9923/2019.2.4

6. Shishov A.M., Ulyashev P.M., Iz»yurov V.S., Mikheev M.A., To the problem of control of a well bottom zone colmatation (In Russ.), Stroitel’stvo neftyanykh i gazovykh skvazhin na sushe i na more, 2020, no. 12, pp. 28–31, DOI: 10.33285/0130-3872-2020-12(336)-28-31

7. Al Jaberi J., Bageri B.S., Adebayo A.R. et al., Evaluation of formation damages during filter cake deposition and removal process: The effect of primary damage on secondary damage, Petroleum Science, 2021, V. 18, pp. 1153–1162, DOI:10.1016/j.petsci.2021.07.004

8. Nekrasova I.L., Development of terrigenous reservoirs drilling and completion technology (In Russ.), Neft’. Gaz. Novatsii, 2019, no. 1, pp. 6–10.

9. Akhmetshin M.A., Issledovanie vliyaniya poverkhnostno-aktivnykh veshchestv na obrazovanie i razrushenie vodoneftyanoy emul’sii v poristoy srede (Investigation of the influence of surfactants on the formation and destruction of water-oil emulsion in a porous medium), Collected papers “Burenie skvazhin, razrabotka i ekspluatatsiya neftyanykh mestorozhdeniy Turkmenii” (Well drilling, development and operation of oil fields in Turkmenistan), Moscow: Nedra, 1965 Publ., V. VIII, pp. 84–95.

10. Bennon D.B., Thomas F.B., Bennon D.W., Bietz R.F., Fluid design to minimize invasive damage in horizontal wells, Journal of Canadian petroleum technology, 1996, no 9, pp. 45–52, DOI:10.2118/96-09-02

11. Akhmetzyanov R.R., Kostenevich K.A., Zhernakov V.N., Zakharov A.D., Research on the solid contents of mineralized drilling mud for production wells in Eastern Siberia (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 2, pp. 62–66, DOI: https://doi.org/10.24887/0028-2448-2021-2-62-66

12. Etalonnye materialy VNIIM. Standartnye obraztsy. Katalog (Reference materials VNIIM. Standard samples. Catalog), 2019, URL: https://www.vniim.ru/files/co-katalog-2019.pdf

The article presents a methodology for managing of base oil production at current production capacity. A novel approach to operational monitoring of field development system is described. A reservoir model based on waterflooding blocks and a method for prediction of the main oil-field performance indicators are outlined. Newton's method is detailed in matrix form for a single-phase filtration model. The proposed method was tested on synthetic data and the comparison of the obtained results with the hydrodynamic simulation is performed to validate the method. An analysis of medium-range prediction is illustrated by an example of several test calculations. A software tool based on the suggested method was developed and commissioned. The paper provides the description of the proposed tool main modules: an automated processing of the input data and the model history matching at the beginning, prediction models initialization at the next step and the analysis of the obtained results as a final part of the workflow. An addition module of the tool is a pro-active factorial analysis. It gives a possibility to estimate oil production loss of wells and reservoir blocks during the forecast period. Based on this information a user can plan some compensatory measures in advance to increase an ultimate oil recovery. An evaluation of the presented method was carried out on the wells stock of real field. A module for automated search for wells to be transferred to water injection stock or shutdown was utilized. This is an integer optimization problem. The module solves it using simulated annealing method. The result of the calculation is an optimal set of wells transferring or shutting down. The efficiency of the solution is evaluated based on economic model which takes into account operating costs and tax deductions.

References

1. Tarek A., Paul D. McK., Advanced reservoir engineering, Elsevier Inc., 2005, 422 p.

2. Beal C., Viscosity of air, water, natural gas, crude oil and its associated gases at oil field temperature and pressures, SPE-946094-G, 1946, DOI: https://doi.org/10.2118/946094-G.

3. Standing M.B., A pressure-volume-temperature correlation for mixtures of California oils and gases, American Petroleum Institute, 1947.

4. Arps J.J., Analysis of decline curves, SPE-945228-G, 1945, DOI: https://doi.org/10.2118/945228-G

5. Vogel J.V., Inflow performance relationships for solution-gas drive wells, Journal of Petroleum Technology, 1968, no. 1, pp. 83–92, DOI:10.2118/1476-PA

6. Berezkin V., Sharifov A., Khatmullina E. et al., A tool and mathematical model for estimation of wells initial water-cut and residual oil reserves on large-sized oil fields,

SPE-207076-MS, 2021, DOI: https://doi.org/10.2118/207076-MS

7. Yudin E.V., Vorob'ev D.S., Slabetskiy A.A. et al., New approaches to the assessment of production potential (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 11, pp. 114–119, DOI: https://doi.org/10.24887/0028-2448-2021-11-114-119

Rosneft Oil Company pays significant attention to involvement in the active development of hard-to-recover oil reserves. This article has been prepared for publication as part of the implementation of the strategic program of the low-permeability reservoirs hard-to-recovery reserves development and the research activities of Rosneft Oil Company. It discusses developed innovative technologies for the development of low-permeability terrigenous oil reservoirs of the Achimov deposits and their analogues, which determine the strategy for their rational development, and new challenges associated with drilling into the zones with ultra-low-permeability reservoirs and an increase in infill drilling. In the context of a constant increase in the share of hard-to-recover reserves and the need to achieve the target oil recovery factor, 8 development technologies have been created and more than 2.5 thousand wells have been drilled using optimized development systems in reservoirs with a permeability more than (0.5-1) m2. At the same time, each of the existing development systems has the potential for optimization, which allows expanding the scope of its application and increasing the economic effect. In order to study the possibility of increasing the oil recovery factor in the ultra-low-permeability reservoirs development the Rosneft plans to conduct unique laboratory core studies to select new stimulation methods that increase the oil displacement efficiency. The deterioration of the reservoir properties poses new challenges for specialists and leads to the evolution of approaches to the development of hard-to-recover reserves and the selection of targeted technologies for specific geological conditions.

References

1. Ryazantsev M.V. et al., Mestorozhdenie idey (Ideenfeld), Novosibirsk: Dom Mira Publ., 2022, 294 p.

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 (In Russ.), SPE-206412-RU, 2021, DOI: https://doi.org/10.2118/206412-MS

3. Galeev R.R., Zorin A.M., Kolonskikh A.V. et al., Optimal waterflood pattern selection with use of multiple fractured horizontal wells for development of the low-permeability formations (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2013, no. 10, pp. 62–65.

4. Latypov I.D., Borisov G.A., Khaydar A.M. et al., Reorientation refracturing on RN-Yuganskneftegaz LLC oilfields (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2011, no. 6, pp. 34–38.

5. Toropov K.V., Sergeychev A.V., Murtazin R.R. et al., Experience in microseismic monitoring of multi-stage fracturing by RN-Yuganskneftegas LLC (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2016, no. 11, pp. 23-26.

6. 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: 10.24887/0028-2448-2021-11-42-47

7. Kolonskikh A.V., Toropov K.V., Sergeychev A.V. et al., Scientific and methodological approaches to improve the development of low-permeability oil reservoirs using horizontal wells with multiple hydraulic fracturing on the territory of LLC RN-Yuganskneftegaz activity (In Russ.), SPE-196755-RU, 2019, DOI: https://doi.org/10.2118/196755-MS

8. Murtazin R.R., Fedorov A.I., Savchenko P.D., Mulyukov D.R., Modification of the unconventional reserves’ exploitation approach based on the reservoir’s stress-deformed state management (In Russ.), SPE-196998-MS, 2019, DOI: https://doi.org/10.2118/196998-MS

9. Davletova A.R., Kolonskikh A.V., Fedorov A.I., Fracture reorientation of secondary hydraulic fracturing operation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 11, pp. 110–113, DOI: 10.24887/0028-2448-2017-11-110-113

10. Davletova A.R., Bikbulatova G.R., Fedorov A.I., Davletbaev A.YA., Geomechanical simulation of hydraulic fractures growth direction and trajectory in the low permeability reservoirs development (in Russ.), Nauchno-tekhnicheskiy vestnik “NK “Rosneftʹ”, 2014, no. 1, pp. 40–43.

11. Fedorov A.E., Dil'mukhametov I.R., Povalyaev A.A. et al., Multivariate optimization of the development systems for low–permeability reservoirs of oil fields of the Achimov formation (In Russ.), SPE-201811-RU, 2020, DOI: https://doi.org/10.2118/201811-MS

The article presents the path that the Zarubezhneft Company has taken to introduce multistage hydraulic fracturing technology at its fields, starting from pilot operations in vertical wells to conventional multistage workovers. The advancements in multistage hydraulic fracturing technology takes place in 2 general directions: proppant hydraulic fracturing in mixed lithology reservoirs and acid-proppant hydraulic fracturing in carbonate reservoirs. Carbonate reservoir D3-III is characterized by high stresses. Therefore, the general issue was to reduce the pressures and risks associated with this. Large diameter tubings and swellable packers with extended length were used to reduce the risk of leaks and damage of the completion system. The second challenge during hydraulic fracturing in the D3-III formation was to create a sufficient fracture width. It was resolved by modifying fracturing injection schedule. In Artinskian reservoir, hydraulic fracturing was associated with the risk of fracture propagation toward water-bearing layer. Low-tonnage hydraulic fracturing injections were used due to small thickness of barrier between the oil-bearing and water-bearing formations. Additional attention was paid for choosing the perforation system. Slotted perforation allowed to reduce the risk of cement breaking and behind casing flow. In addition, all hydraulic fracturing operations were monitored in real time. Basing on pressure-rate behavior, proppant injection stages were modified or even completely rejected. A pragmatic approach was used while implementation of hydraulic fracturing. The main solutions were verified on single-stage operations in vertical wells, and then customized for horizontal wells. For the purpose of fracturing operations improvement, it was supported by a set of surveys and studies. The described approach allows to achieve planned targets at all the wells and to start oil production from the objects that previously were considered as unprofitable.

In-situ conversion of carbon dioxide into the light n-alkanes is based on the hydrogenation of carbon dioxide on the surface of heterogeneous catalysts. The catalysts based on transition metals such as Fe, Ni, Co, etc., which are widely applied in aquathermolysis of heavy oil can be active for carbon dioxide hydrogenation as well if the composition is modified by adding alkali metals. In this study, we used sodium as the most available reagent for industrial-scale application. The mineral surface of reservoir rocks plays the function of catalyst supports in case of using such catalysts in-situ. The active forms of the catalyst precursors – nanosized particles are adsorbed and retained on the surface of the reservoir minerals. The composition of the catalyst determines the reaction path and intensity of chemical reactions. The successful implementation of carbon dioxide hydrogenation requires the promotion of various reactions. Therefore, the presence of various active centers in the structure of the catalysts is an important factor. The increase of hydrocarbon chains is carried out primarily on the surface of carbide active centers, while hydrogenation of olefins and reversed water gas shift reaction preferably on the surface of metal oxides. Even less amount of newly formed n-alkanes can significantly reduce the viscosity of heavy oil and increases oil recovery factor. Along with conversion of carbon dioxide, the aquathermolytic upgrading of heavy oil is carried out that provides significant reduction of resins and asphaltenes. The proposed enhanced oil recovery method based on the technology of catalytic aquathermolysis has been successfully tested in oil fields. The modified nanoparticles expand the application of catalysis for the development of unconventional reservoirs. The multifunctional catalysts during the co-injection of steam and carbon dioxide promote not only in-situ generation of light n-alkanes, but also contribute to the partial utilization of injected carbon dioxide.

Acknowledgment. This paper has been supported by the Kazan (Volga Region) Federal University Strategic Academic Leadership Program (PRIORITY-2030) and LUKOIL PJSC.

References

1. Tumanyan B.P., Petrukhina N.N., Kayukova G.P. et al., Aquathermolysis of crude oils and natural bitumen: chemistry, catalysts and prospects for industrial implementation (In Russ.), Uspekhi khimii = Russian Chemical Reviews, 2015, V. 84(11), pp. 1145–1175.

2. Maity S.K., Ancheyta J., Marroquin G., Catalytic aquathermolysis used for viscosity reduction of heavy crude oils: A review, Energy Fuels, 2010, V. 24, pp. 2809–2816, DOI: 10.1021/ef100230k

3. Li Chen, Weicheng Huang, Chenggang Zhou, Yanling Chen, Advances on the transition-metal based catalysts for aquathermolysis upgrading of heavy crude oil, Fuel, 2019, V. 257, pp. 115779, DOI: 10.1016/j.fuel.2019.115779

4. Qu Xiao, Zhou Guangqian, Lu Yukun et al., Catalytic aquathermolysis of Mackay River bitumen with different types of Mo-based catalysts, Fuel, 2022, V. 326, Article No. 125134, DOI: 10.1016/j.fuel.2022.125134.

5. Betiha M.A., Elmetwally A.E., Al-Sabagh A.M., Mahmoud T., Catalytic Aquathermolysis for altering the rheology of asphaltic crude oil using ionic liquid modified magnetic MWCNT, Energy and Fuels, 2020, V. 34(9), pp. 11353–11364, DOI:10.1021/acs.energyfuels.0c02062

6. Vakhin A.V., Aliev F.A., Mukhamatdinov I.I. et al., Extra-heavy oil aquathermolysis using nickel-based catalyst: Some aspects of in-situ transformation of catalyst precursor, Catalysts, 2021, V. 11(2), no. 189, pp. 1–22, DOI: 10.3390/catal11020189.

7. Aliev F., Akhunov A.A., Mirzaev O., Vakhin A., Development of new amphiphilic catalytic steam additives for hydrothermal enhanced oil recovery techniques, Catalysts, 2022, V. 12 (8), DOI: 10.3390/catal12080921.

8. Kudryashov S.I., Afanas'ev I.S., Petrashov O.V. et al., Catalytic heavy oil upgrading by steam injection with using of transition metals catalysts (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 8, pp. 30–34, DOI:10.24887/0028-2448-2017-8-30-34

9. Vakhin A.V., Mukhamatdinov I.I., Aliev F.A. et al., Industrial application of nickel tallate catalyst during cyclic steam stimulation in Boca De Jaruco reservoir, SPE-206419-MS, 2021, DOI: 10.2118/206419-MS.

10. Chao K., Chen Y., Liu H. et al., Laboratory experiments and field test of a difunctional catalyst for catalytic aquathermolysis of heavy oil, Energy &Fuels, 2012, V. 26 (2), pp. 1152–1159, DOI: 10.1021/ef2018385.

11. Gunasekar G.H., Park K., Jung K.D., Yoon S., Recent developments in the catalytic hydrogenation of CO2 to formic acid/formate using heterogeneous catalysts, Inorg. Chem. Front., 2016, V. 3, pp. 882–895, DOI:10.1039/C5QI00231A

12. Pérez L.P., Baibars F., Sache E.L. et al., CO2 valorisation via reverse water-gas shift reaction using advanced Cs doped Fe-Cu Al2O3 catalysts, Qual. Assur. Util. Rev., 2017, V. 21, pp. 423–428, DOI:10.1016/j.jcou.2017.08.009

13. S.A. Sitnov, M.A. Khelkhal, I.I. Mukhamatdinov et al., Iron oxide nanoparticles impact on improving reservoir rock minerals catalytic effect on heavy oil aquathermolysis, Fuel, 2022, V. 327, DOI: 10.1016/j.fuel.2022.124956.

14. Vakhin A.V., Mukhamatdinov I.I., Sitnov S.A. et l., Catalytic activity of nickel and iron sulfides in the degradation of resins and asphaltenes of high-viscosity oil in the presence of carbonate rock under hydrothermal conditions (In Russ.), Kinetika i kataliza = Kinetics and Catalysis, 2022, V. 63, no. 5, DOI: 10.1134/S0023158422050135

15. Ganeeva Yu.M., Yusupova T.N., Romanov G.V., Asphaltene nano-aggregates: structure, phase transitions and effect on petroleum systems (In Russ.), Uspekhi khimii = Russian Chemical Reviews, 2011, V. 80, no. 10, pp. 1034–1050, DOI:10.1070/RC2011v080n10ABEH004174

A major problem in the modern oil and gas industry is to increase efficiency in the development of high-viscosity oil fields. Specifically, steam injection technology is most commonly used for the production of high viscosity oil. In previous research, it was shown that injection of catalysts for aquathermolysis of high viscosity oil can be used together with steam injection. These catalysts, together with steam injection, can reduce oil viscosity, increase the proportion of light fractions, and reduce the content of resins and asphaltenes.

In the current stage of work, problems related to researching the use of various starting reagents for catalyst production, selecting the optimal equipment for synthesizing a pilot batch, testing the technology under industrial conditions, and comparing the properties of the pilot sample with the laboratory sample were also established. The results of field tests on the creation and application of a new technology of catalytic aquathermolysis to improve the development efficiency of high-viscosity petroleum deposits using the Strelovskoye field as an example were presented. Steam injection technology is used at the Strelovskoye field. In addition, the main stages of the work were considered: from laboratory studies to determine the changes in the properties of the oil in the presence of catalytic aquathermolysis to the selection of optimal injection conditions and analysis of the results of field tests at the pilot site. The technology of thermal steam treatment of wells together with injection of a catalytic composition based on iron and nickel carboxylates in cyclic mode was developed. The company also produced 4.5 tons of the catalyst. The field tests showed that the average well flow rate increased compared to the previous steam treatment cycle without catalyst. Oil viscosity was also reduced by more than 4 times. In addition, the obtained results confirm the prospects of using the developed technology to improve the efficiency of heavy oil production. Currently, further scaling is planned at other wells of the Strelovskoye field.

Acknowledgment. This paper has been supported by the Kazan (Volga Region) Federal University Strategic Academic Leadership Program (PRIORITY-2030) and LUKOIL PJSC.

References

1. Maity S.K., Ancheyta J., Marroquín G., Catalytic aquathermolysis used for viscosity reduction of heavy crude oils: a review, Energy & Fuels, 2010, V. 24, pp. 2809–2816, DOI:10.1021/ef100230k

2. Pevneva G.S., Voronetskaya N.G., Sviridenko N.N., Cracking of maltenes of naphthenic petroleum in the presence of WC/Ni–Cr, Pet. Chem., 2020, V. 60, pp. 373–379, DOI:10.1134/S0965544120030160

3. Vakhin A.V. , Sitnov S.A., Mukhamatdinov I.I. et al., Procedure of thermal catalyst effect for "RITEK" LLC hard-to-recover oil fields development in Samara region (In Russ.), Neft'. Gaz. Novatsii, 2019, V. 224, no. 7, pp. 75-78.

4. Vakhin A.V., Sitnov S.A., Mukhamatdinov I.I. et al., Perspectives in applying nano-dispersed catalysts at the basis of transition metals to enhance oil recovery at the stage of hard-to-recover oil fields commissioning at "RITEK" LLC (In Russ.), Neft'. Gaz. Novatsii, 2019, V. 224, no. 8, pp. 42–46.

5. Khaydarova A.R., Gogalyuk T.V., Mukhamatdinov I.I. et al., The role of magnetite in conversion of resins and asphaltenes during hydrothermal upgrading of heavy oil (In Russ.), Neft'. Gaz. Novatsii, 2020, V. 233, no. 4, pp. 78–82.

6. Mukhamatdinov I.I., Giniyatullina E.E., Mukhamatdinova R.E. et al., Effect of aqua thermolysis catalyst on in-situ transformation of high-viscous oil from Strelovskoye field in Samara region (In Russ.), Neft'. Gaz. Novatsii, 2021, no. 3, pp. 38–42.

7. Mukhamatdinov I.I., Giniyatullina E.E., Mukhamatdinova R.E. et al., Evaluation of the aquathermolysis catalysts effect on the composition and properties of high-viscosity oil from the Strelovskoe field, SOCAR Proceedings, 2021, Special Issue 2, pp. 90–96.

8. Vakhin A.V., Khelkhal M-A., Mukhamatdinov I.I. et al., Changes in heavy oil saturates and aromatics in the presence of microwave radiation and iron-based nanoparticles, Catalysts, 2022, V. 12, p. 514, DOI:10.3390/catal12050514

9. Mukhamatdinov I.I., Lapin A.V., Mukhamatdinova R.E. et al., Study of the hydrothermal-catalytic influence on the oil-bearing rocks of the Usinskoye oil field, Catalysts, 2022, V. 12 (10), p. 1268, DOI:10.3390/catal12101268

10. Fan H., Liu Y., Downhole catalyst upgrades heavy oil, Oil Gas J., 2002, V. 100, pp. 60–62.

11. Wei LI, Zhu J, Qi J., Application of nano-nickel catalyst in the viscosity reduction of Liaohe extra-heavy oil by aqua-thermolysis, J. Fuel Chem Technol., 2007, V. 35, pp. 176–180, DOI:10.1016/S1872-5813(07)60016-4

12. Lin D., Zhu H., Wu Y. et al., Morphological insights into the catalytic aquathermolysis of crude oil with an easily prepared high-efficiency Fe3O4-containing catalyst, Fuel, 2019, V. 245, pp. 420–428, DOI:10.1016/j.fuel.2019.02.063

The purpose of carrying out various types of well interventions is to increase the share of profitable interventions and improving the economic efficiency of the interventions program as a whole. Changing the number of interventions has an impact on the share of profitable wells. In general, an increase in the number of well interventions leads to a decrease in the share of profitable wells, an increase in additional oil production and the total net present value (NPV) of the entire program. A decrease in the number of well interventions will lead to an increase in the share of wells that pay off, a decrease in additional oil production and the total NPV of the entire program. The share of profitable wells depends on the total number of interventions since when the number of well interventions is increased, candidate wells with lower planned initial incremental oil rates get accepted into the program. For such wells, the probability of obtaining lower additional oil production in the evaluation period increases, as well as the risk of the intervention becoming unprofitable increases. At the same time, normally a detailed program with the exact candidate wells is not available in long-term and medium-term planning. Therefore, changing the number of well interventions performed leads to difficulties in assessing the efficiency of these activities.

In this paper, an approach is proposed allowing to estimate the potential impact of reducing or increasing the number of well interventions on its success rate and economic efficiency without any information on specific candidate wells planned for the interventions, based on statistical data from previous years, such as the number of actual performed interventions by type, planned initial incremental oil rates for each well before the interventions, projected additional oil production and projected NPV figures for the period of evaluation for each well. The proposed approach is based on data from economic effectiveness reports on actual well interventions and historical data on the planned initial incremental oil rates from wells for various types of interventions, allowing to make informed decisions aimed at improving the efficiency of the implementation of the well intervention program, including redistribution of additional interventions between various assets with different projected intervention efficiency profiles.

References

1. Timonov A.V., Sergeychev A.V., Sudeev I.V. et al., A systematic approach to design of well intervention for the oil reservoir development optimization (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2010, no. 8, pp. 46–49.

2. Kharlamova D.I., Kharlamov K.A., Ganiev Sh.R. et al., Development of a smart tool for operational assessment of oil field development system effectiveness (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2022, no. 7, pp. 116–120, DOI: https://doi.org/10.24887/0028-2448-2022-7-116-120

3. Ramazanov R.R., Kharlamov K.A., Letko I.I., Martsenyuk R.A., Efficiency analysis of geological and technical measures (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2019, no. 6, pp. 62–65, DOI: https://doi.org/10.24887/0028-2448-2019-6-62-65

Understanding the importance of the task to develop automation and digitalization of the oil and gas production process through artificial lift methods, Rosneft Oil Company has created a number of effective tools that make it possible to quickly analyze bulk data during the operation of the world's largest well stock. One of the corporate IT systems that include key artificial lift functions is the information system (IS) Mekhfond that was designed to combine many disparate databases and computer programs used in various oil production processes. In automatic mode, IS Mekhfond collects almost all process information for each artificial lift well. IS Mekhfond has become an indispensable tool both in day-to-day work and in the analysis of data arrays and process management. In 2018, the key functionality of the IS was successfully implemented and put into commercial operation enabling to develop online an energy-efficient design of downhole pumping equipment and automatic simulation of the ESP operation mode for all artificial lift wells, including the assessment of the current operation mode simultaneously for all existing ESP-assisted artificial lift wells (batch calculation) in 30 Subsidiaries of the Rosneft Group. Thereafter the resources of the corporate R&D institutes were concentrated on the derived functions development. The batch calculation made it possible to discover several new areas for optimizing the performance of the ESP well stock. The most demanded function is the possibility of qualitative and quantitative assessment of external factors affecting the ESP operation. For example, assessing the degradation of the pumps head-capacity curve in downhole conditions allows solving a number of problems in real time, such as improvement of the downhole equipment run life, efficiency improvement in the production well stock, choosing the optimal protection for downhole equipment, etc. Accurate modeling of the ESP operation actual mode together with the reference design of equipment in the IS Mekhfond allows to assess the potential for energy saving on a well-by-well basis, with the possibility of ranking by types of activity or models of equipment used, as well as to improve the accuracy in planning the product range and design of ESPs to be purchased, taking into account the effect of in situ conditions on ESP properties. In the future, it will be probably possible to identify many more important patterns.

References

1. Kosilov, D.A. Mironov, D.V. Naumov I.V., Mekhfond corporate system: achieved results, medium-term and long-term perspectives (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2018, no. 11, pp. 70–73, DOI: https://doi.org/10.24887/0028-2448-2018-11-70-73

2. Ivanovskiy V.N., Pekin S.S., Yangulov P.L., Influence of a viscous liquid on the performance of submersible electric centrifugal pumps (In Russ.), Territoriya Neftegaz, 2012, no. 9, pp. 49–55.

3. Tarasov V.P., Kuryaev S.V., Golubʹ I.M., Use of specialized software for calculating energy consumption in a mechanized well stock (In Russ.), Inzhenernaya praktika, 2016, no. 3, pp. 22–25.

4. Degovtsov A.V., Sokolov N.N., Ivanovskiy A.V. et al., On the influence of the pumped liquid viscosity on the complex characteristics of small-sized stages of electric submersible pumps with open impellers (In Russ.), Territoriya Neftegaz, 2018, no. 1–2, pp. 54–60.

5. Shevchenko N.G., Shudrik A.L., Bondarenko E.Yu., Investigation of the flow of gas-liquid mixture in the flow part of the stage of the submersible pump for oil production (In Russ.), Bulletin of NTU "KhPI". Series: Hydraulic machines and hydrounits, 2017, no. 22 (1244), pp. 31–37.

The problem of providing repair and insulation works with technical means for the preparation of small volumes of grouting solutions is relevant due to the annual expansion of repair work carried out on the old fund of wells of gas and oil fields that are at the final stage of development. In the Krasnodar Territory alone, more than 1,000 borehole operations with the preparation of grouting solution are performed annually at oil and gas fields. A characteristic feature of repair and insulation works at the gas and oil fields of the region is the high density of agricultural land and objects of the resort and recreational territory, which place particularly high demands on the environmental safety of work, quality and equipment of specialized enterprises. In such conditions, the issues of improving the technical base of the repair and maintenance of local oil and gas industry enterprises become very relevant, including this applies to the technical means of preparing grouting solutions. The authors have developed new equipment: a mobile complete block for the preparation of grouting solutions with a volume of up to 3 m3, including a hydro-ejector mixer, a cement supply system for mixing, a built-in averaging tank, a dispersant. Tests were performed on a mixer with a mixing chamber made in the form of a confuser and a hydraulic mixer having a cylindrical mixing chamber. Calculations of the main parameters of the block were performed: hydro-ejector mixer, grouting solution supply line, mechanical agitator. Full-scale tests of flow cavitation dispersants and rotary pulsation ones developed by the authors were carried out. Comparative results of strength measurements of cement stone obtained by traditional and new technology using dispersants are presented. According to the analysis of the results of all field and laboratory tests, the use of dispersants allowed to increase the homogeneity of the solution and its spreadability; to reduce the water separation of the grouting solution, to increase the strength limit of the cement stone for bending and compression. The decrease in water separation causes a decrease in the number and geometric characteristics of channels in cement stone, which are the cause of many complications both during construction and during well operation: the presence of intercolonial pressures, interplastic flows; the formation of secondary technogenic deposits, griffins, etc.

References

1. Bulatov A.I., Makarenko P.P., Proselkov Yu.M., Burovye promyvochnye i tamponazhnye rastvory (Drill mud and cement slurry), Moscow: Nedra Publ., 1999, 424 p.

2. Robertson J.O., Chilingarian G.V., Kumar S., Surface operations in petroleum production, New York: Elsevier Science, 1989, 562 p.

3. Patent no. 4158510A US, Cementing skid with recirculating mixer, Inventors: Smith L.G., Knoll J.N.

4. Patent no. 4838701 US, Mixer, Inventors: Smith D.W., Kennedy R.D., Garcia E.C.

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6. CBS-955, Cement batch mixer skid, URL: https://www.slb.com/-/media/files/ce/product-sheet/cbs-955-ps

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9. Arevalo R., Zuriguel I., Clogging of granular materials in silos: effect of gravity and outlet size, Soft Matter, 2016, V.12, pp. 123-130, DOI: https://doi.org/10.1039/C5SM01599E

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Theoretical study and simulation of the operation processes of plunger units with linear electric submersible pump (LESP), presented by Rosneft Oil Company, showed that there is a maximum permissible value of the plunger speed, above which the pump cylinder filling factor (CFF) decreases due to increase of the released gas volume, which should be considered when choosing LESP operation mode to enable effective operation of the unit at low-yield wells. Rosneft Oil Company have developed a method to calculate the optimum plunger speed in the suction stroke that can be applied to develop an algorithm for linear drive control, which will improve the efficiency of submersible linear drive plunger units, as well as increase fluid flow rate when equipping low production wells with the following units. An important advantage of applying the optimization of the plunger movement algorithm based on the developed method is the reduction of costs related to complications in the unit operation. There were obtained the characteristics of LESP operation on the basis of analytical solution of presented equations for determination of CFF, pressure at the pump inlet and speed of LESP plunger. On the basis of the analytical solution of the equations it has been established that the pump cylinder filling efficiency depends on the plunger speed as well as on the volume of gas entering the pump. The performed analytical analysis of the dynamics of changes in the cylinder filling factor at different plunger speeds and the share of gas entering the cylinder has confirmed the expediency of the optimization of the linear drive control algorithm. The presented method for calculating the actual flow rate of the LESP is based on determining the extremum of the parabolic function of the dependence of the flow rate on the plunger velocity.

References

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4. Urazakov K.R., Topol'nikov A.S., Azizov A.M., Davletshin F.F., Dependence of filling coefficient of rod pump from volume of dead space (In Russ.), Neftegazovoe delo, 2017, no. 4, pp. 6-25.

5. Timashev E.O., Modeling of complications in the operation of plunger installations with electrical submersible reciprocating pump (In Russ.), Neftegazovoe delo, 2021, V.19, no. 1, pp. 142-148, DOI: 10.17122/ngdelo-2021-1-142-148

6. Pirverdyan A.M., Gidromekhanika glubinnonasosnoy ekspluatatsii (Hydromechanics of deep pumping operation), Moscow: Nedra Publ., 1965, 191 p.

7. Virnovskiy A.C., Teoriya i praktika glubinnonasosnoy dobychi nefti (Theory and practice of downhole pumping oil production), Proceedings of VNII, 1971, V. 57, 184 p.

8. Adonin A.N., Dobycha nefti shtangovymi nasosami (Oil production with rod pumps), Moscow: Nedra Publ., 1979, 213 p.

9. Murav'ev I.M., Mishchenko I.T., Nasosnaya ekspluatatsiya skvazhin za rubezhom (Pumping operation of wells abroad), Moscow: Nedra Publ., 1967, 239 p.

10. Shcherba V.E., Grigor'ev A.V., Vinichenko V.S., Ul'yanov D.A., Mathematical modeling of working processes of volumetric action pump (In Russ.), Omskiy nauchnyy vestnik, 2010, V. 93, no. 3 (93), pp. 77-81.

The article describes the software system of geotechnical control (SSGC) developed in Rosneft Oil Company with use of import-substituting technologies as well as provides information on the system functionality and applications. The SSGC provides the means for automating geotechnical monitoring processes carried out in order to improve environmental safety of oil and gas facilities located in areas of permafrost. The authors consider the general structure and features of the developed system modules as well as sources and techniques of data entry. The visualization functionality of SSGC enables a user to interact with the data stored in the system database, including working with a map of infrastructure facilities. The calculation modules of SSGC have been developed in accordance with building regulations and designed for modeling the thermal state of permafrost in a given area and calculating the pile foundation loads. The analytical module of the SSGC comes with a set of standard reports. The innovative part of the system is the module of geotechnical reports, which helps an expert to make control decisions using a neural network algorithm. The paper reveals the estimation of common efficiency of the proposed neural network algorithm, provides the basic perspectives of future development and further implementation of the created SSGC in Rosneft subsidiaries.

References

1. URL: http://my.krskstate.ru/docs/climate/vechnaya-merzlota/

2. Konovalova V.M., Norilsk spill (In Russ.), Molodoy uchenyy, 2020, no. 46(336), pp. 71–72, URL: https://moluch.ru/archive/336/75202/

3. Napryushkin A.A., Kliment'ev D.S., Khristolyubov I.A. et al., Geodata systematization and harmonization of approaches to spatial information management in the corporate geoinformation system of Rosneft Oil Company (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2022, no. 6, pp. 66–71, DOI: 10.24887/0028-2448-2022-6-66-71

4. Yarotskaya E.V., Patov A.M., Development of domestic geographical information systems in the conditions of import substitution (In Russ.), Politematicheskiy setevoy elektronnyy nauchnyy zhurnal Kubanskogo gosudarstvennogo agrarnogo universiteta, 2016, no. 117, pp. 175-188.

5. Nazarkin D.S., Filimonov A. A., Lipikhin D.V., Napryushkin A.A., The use of a neural network for geotechnical monitoring at oil and gas facilities located in the Far North (In Russ.), Neft'. Gaz. Novatsii, 2020, no. 10, pp. 78–82.

In the pipeline transport of high-viscosity and congealing oil the issue of determining the safe shutdown time, as well as calculating the starting pressure required to resume pumping and bring the main oil pipeline into operation, is of particular relevance. In the process of shutting down the underground laying of an oil pipeline, paraffinic oil cools and crystallizes. At the same time, its rheological properties change, with a temperature decrease viscosity and shear stress increase. The oil temperature and the pressure required to bring the oil pipeline into operation depend on the duration of pumping stop. The pressure value required for start-up may turn out to be higher than the allowable one in a given section of the pipeline. In this regard, it is necessary to monitor the temperature of the oil during the shutdown process. The cooling of oil occurs unevenly both along the cross section and along the length of the pipeline. And the value of the start-up pressure depends on the position of the shear surface, which may be less than the radius of the pipeline. To take into account the temperature non-uniformity over the cross section, this paper solves the problem of conjugate heat transfer between the oil pipeline and the soil surrounding it. The article considers the case of using seasonally operating cooling devices for underground oil pipeline in permafrost soils and these devices influence on the distribution of oil temperature depending on shutdown duration. The results of a numerical study of the change in oil temperature over time under the conditions of installation of seasonally operating cooling devices and in their absence are presented. Using the results of the study, we can set the required pressure to resume pumping.

References

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5. Cherentsov D.A., Yakupov A.U., Voronin K.S. et al., Application of machine learning models for intelligent management of oil transportation efficiency (In Russ.) Neftyanoe khozyaystvo. – 2021, no. 12, pp. 136-139, DOI: https://doi.org/10.24887/0028-2448-2019-12-136-139

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9. Gorelik Ya.B., Seleznev A.A., About efficiency of the condenser finning of the short vertical thermostabilizer for building on permafrost (In Russ.), Kriosfera Zemli, 2016, V. 20, no. 2, pp. 78-89.

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11. Bakhtizin R.N., Shutov A.A., Shtukaturov K.Yu., Simulation of pipeline operating modes using the NIPAL 3.0 (Non Isothermal Pipeline for Abnormal Liquids) software package (In Russ.), Neftegazovoe delo, 2004, no. 1, pp. 7, URL: http://ogbus.ru/files/ogbus/authors/Bahtizin/Bahtizin_1.pdf

12. Vakulin A.A., Shabarov A.B., Vakulin A.A., Cooling down of oil when the pipeline stops in frozen soil (In Russ.), Vestnik Tyumenskogo gosudarstvennogo universiteta. Fiziko-matematicheskoe modelirovanie. Neft’, gaz, energetika = Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy, 2021, V. 7, no. 4(28), pp. 27–45, DOI: https://doi.org/10.21684/2411-7978-2021-7-4-27-45

The article concentrated on the relevant issue of ensuring the reliability of turbine flow transducers (TFT), used to determine the volumetric flow rate as part of crude quality control systems (CQCS). As the author notes, the reliability, especially its numerical indicators, shall be considered separately for each homogeneous group of equipment, including measuring instruments, which have their own functional and technological features. Separate attention is given to crucial factors that must be considered when determining the metrological reliability of not only TFT but also of any other measuring instruments that are subject to the measurement of metrological performances over time and methods for monitoring the metrologically sound order of TFT. The research included an analysis of the application of the predictive analytics method in mechanical engineering for monitoring of the technical and metrological state of equipment. Software has been developed using Python and an algorithm for determining the volumetric flow rate in the system for collecting and processing information in the CQCS depending on the values of the Reynolds number, which makes it possible to early detect the occurrence of a metrological failure of the TFT. The data on the results of verification and metrological performances control of 60 TFT running on oil with different rheological properties over the past 5 years were analyzed. The conducted research showed that the application of the algorithm will allow to: reduce the risk of emergency situations and termination of accounting operations in the CQCS; reduce the duration of forced downtime of the CQCS or reduce them completely to zero; obtain reliable data on the performance of the TFT, which makes it possible to predict the residual life of parts and assemblies (the operating time before the limit state), etc.

References

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2. Otkhman N.Z., Polukhin V.I., Improvement of metrological reliability in design of data-measuring systems (In Russ.), Vestnik TGTU, 2011, no. 2, pp. 365-370.

3. Efremov L.V., Estimation of instrument metrological reliability from group testing data (In Russ.), Priborostroenie, 2012, no. 6.

4. Gusenitsa Ya.N., Sherstobitov S.A., Malakhov A.V., Method of substantiation of calibration intervals of measuring instruments (In Russ.), Naukoemkie tekhnologii v kosmicheskikh issledovaniyakh Zemli, 2016, no. S1.

5. Avci C., Tekinerdogan B., Athanasiadis I.N., Software architectures for big data: a systematic literature review, Big Data Analytics, 2020, V. 5, no. 5, DOI:10.1186/s41044-020-00045-1

6. Chun-Wei Tsai, Chin-Feng Lai, Han-Chieh Chao, Vasilakos A.V., Big data analytics: a survey, Journal of Big Data 2, 2015, no. 1, DOI:10.1186/s40537-015-0030-3

7. Hasan M., Genetic algorithm and its application to big data analysis, International Journal of Scientific & Engineering Research, 2014, V. 5, no. 1, pp. 1991–1996.

8. Tolk A., The next generation of modeling & simulation: Integrating big data and deep learning, Proceedings of Summer Simulation Multiconference, 2015 At: Chicago, IL. 2015.

9. Ribeiro A., Silva A., da Silva A., Data modeling and data analytics: A survey from a big data perspective, Journal of Software Engineering and Applications, 2015, no. 8, pp. 617–634, DOI:10.4236/jsea.2015.812058

10. Khasanov A.R., Impact of predictive analytics on the activities of companies (In Russ.), SRRM, 2018, no. 3 (108), DOI:10.17747/2078-8886-2018-3-108-113

11. Dobrynin S.L., Burkovskiy V.L., Monitoring and predictive analytics of technological equipment on the based of industrial internet of things (In Russ.), Voronezhskiy gosudarstvennyy tekhnicheskiy universitet, 2020, V. 16, no. 5, pp. 7–12, DOI 10.36622/VSTU.2020.16.5.001.

12. D'yakov N.A., Golunova A.S., Process control systems based on predictive analytics: Design (In Russ.), Elektrotekhnicheskie sistemy i kompleksy, 2021, no. 1 (50), pp. 58–64, DOI: https://doi.org/10.18503/2311-8318-2021-1(50)-58-64

13. Livanov M., Russia's first complex of predictive analytics for power and industrial equipment (In Russ.), Ekspozitsiya neft' i gaz, 2016, no. 3 (49), pp. 82–83.

14. Gorelik A., The enterprise big data lake: Delivering the promise of big data and data science, O’Reilly Media, 2019, 224 p.

15. Aralov O.V., Buyanov I.V., Savanin A.S., Iordanskiy E.I., Research of methods for oil kinematic viscosity calculation in the oil-trunk pipeline (In Russ.), Nauka i tekhnologii truboprovodnogo transporta nefti i nefteproduktov = Science & Technologies: Oil and Oil Products Pipeline Transportation, 2017, V. 7, no. 5, pp. 97–105.

The article presents the experience of Rosneft Oil Company in improving the regulatory framework in the field of marking, packing, transportation and storage of petroleum and petroleum products in the context of the revision of interstate standard GOST 1510-84 «Petroleum and petroleum products. Marking, packing, transportation and storage». Problems and contradictions caused by the application of outdated norms and rules established in this standard, which necessitated its revision, are considered. As part of a set of measures to improve the efficiency of research and development and innovation activities and taking into account the extreme interest in establishing new requirements for marking, packing, transportation and storage of petroleum and petroleum products, Rosneft Oil Company initiated a revision of GOST 1510-84. At this, All-Russian Research Institute for Oil Refining .was chosen as the developer of the standard, as the leading research organization in the field of oil refining with relevant competencies and significant experience in developing interstate standards. The development of the draft revision of GOST 1510-84 was carried out in strict accordance with requirements established in GOST 1.2-2015 «Interstate system for standardization. Interstate standards, rules and recommendations on interstate standardization. Rules for development, taking over, renovation and cancellation» and GOST 1.5-2001 «Interstate System for Standardization. Interstate standards, rules and recommendations on interstate standardization. General requirements for structure, drafting, presentation, content and indication». Approved GOST 1510-2022 «Petroleum and petroleum products. Approved GOST 1510-2022 «Petroleum and petroleum products. Marking, packing, transportation and storage», which was developed to replace GOST 1510-84, will eliminate most of contradictions and problems associated with marking, packing, transportation and storage of petroleum and petroleum products, minimize risks of violation of petroleum and petroleum products supply and failure to meet contractual obligations, and thus it will be the basis for further improvement of regulatory framework in these important areas of activity.

The search for solutions for the development of the Russian economy in the conditions of the crisis consequences of the sanctions pressure of Western countries is impossible without a historical analysis of the Soviet experience of the development of industrial potential. Generalization of the most effective management practices of Soviet enterprises can serve as a basis for choosing the most popular ways of industrial development in the conditions of economic crisis. The Soviet innovation system is characterized by a high level of organizational and material capabilities, which made it possible to concentrate significant scientific, technical and intellectual resources in priority areas in a short time.

The article considers the issues of the general strategy of progressive and competitive development of the country's economy, both taking into account the need to maintain mutually beneficial trade relations with foreign countries, and the policy of import substitution aimed at timely identification (prevention) of potential threats and ensuring technological sovereignty. The authors substantiates the thesis about the significant impact of foreign policy processes on import substitution, the priority nature of anti-crisis measures; it is concluded that the study of the experience of technical (industrial) development involves a detailed consideration of domestic characteristics, various subjective factors, as well as the factor of historical randomness. The key factor in the industrial development of the USSR were: long-term and purposeful activity of party and state bodies, the use of administrative and command management methods, state planning and financing of the scientific and technical complex. The features and positive features of the Soviet innovation system are highlighted. The characteristic of the organizational and material capabilities of the state to concentrate significant scientific, technical and intellectual resources in priority areas in a fairly short time is given. The implementation of specific import substitution measures varies for different industries and is determined by the level of technological development of the industry, the state of sales markets, the nature of intersectoral cooperation, as well as the specifics of the territorial location of production.

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