¹07/2022 (âûïóñê 1185)
Cementing of liners in sidetrack wells is associated with two main constraints: narrowDOI: 10.24887/0028-2448-2022-7-6-9
casing string-borehole annular spaces and high buildup rates. These factors
have adverse effects on the efficiency of wellbore cleanout and hole
conditioning for running a casing string and on liner cementing quality itself.
Large-size drill cuttings, hole wall roughness, presence of filter cake and
drilling mud stagnation zones impede smooth running of the liner to the bottom
of the well. This usually results in stuck liner or failure to reach the target
depth, and forces a drilling team to pull out the liner and perform multiple
conditioning trips, thus increasing sidetrack drilling time up to 7 days.
Practice shows that drill string rotation during hole conditioning facilitates
passing through drill cuttings, i.e. it is sometimes enough to rotate the liner
to push it to the bottom of the well. However, the existing conventional device used to connect the drill
string to well liner does not allow for rotation. Liner deployment and
cementing tool developed in TatNIPIneft enables getting the liner to total
depth by means of liner rotation in setting intervals. Reamer shoe attachment
enables tool running while hole conditioning. Subsequent cementing operations
are conducted with liner rotation. Numerous bench tests proved that casing
rotation significantly increases degree of drill mud replacement by cement
slurry. Rotation provides additional cement flow turbulence and opens space to
flush fluid and cement slurry. This is particularly important in presence of
bottlenecks in sidetrack holes. However, casing rotation during well cementing
jobs remains the least applied technique. This is primarily due to the lack of
specialized wellhead equipment and threaded joints load limitation.
Casing-rotation-while-cementing technology has been widely used in Tatneft
PJSC. A versatile rotating cementing head has been designed and manufactured
for casing rotation during cementing jobs. Acoustic and gamma-gamma cement-bond
logs prove beneficial effect of casing rotation in obtaining a homogeneous
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Drilling through incompetent shales, loose sands, and dolomites can be a very troublesome process because of numerous sloughing, caving-ins, and collapse of wellbores’ walls. These troubles are addressed, as a rule, by numerous hole reaming jobs involving increase of drillstring rotational speed and injection of high-viscosity and heavy-weight drilling fluid. These operations can last for two weeks in some cases, increasing NPT and translating into high costs. Casing-while-drilling has been proved to lower drilling costs due to elimination of tripping events for hole reaming, for trouble zones are isolated immediately after drilling out. TatNIPIneft Institute in cooperation with Perekryvatel OOO, have designed a drillable PDC bit to be used in the casing-while-drilling process. Tests using the inhouse test jig have been successfully performed. In the test jig, the PDC bit was tested for drillability using a 142.9-mm PDC bit. Field tests using the PDC drillable bit with a cementing port were performed in Well No. 11378, Chernoozerskoye field. The 168-mm casing pipes with thread connections TMK UP CWB were used. After cementing, the bit was drilled out for 4.5 minutes. A similar 220.7-mm bit was run on expandable profile liner OLKSB-220.7. In this case, the bit was drilled out using a PDC SSP 142.9 DHD 513 bit. The process took 7 minutes. The successful tests of drillable alloy bits open up opportunities for further development of the casing-while-drilling process as an efficient drilling technology.
1. Malyukov V.P., Traore M.A., Application of casing while drilling technology for accessing hydrocarbon producing horizons (In Russ.), Vestnik RUDN. Seriya: Inzhenernye issledovaniya, 2017, V. 18, no. 4, pp. 472-479, https://doi.org/10.22363/2312-8143-2017-18-4-472-479
2. Fatkullin S.A., Gumich D.P., Zabuga S.V., Karimov D.V., Chutchev E.V., Second wind for drilling with casing technology of glory (In Russ.), Burenie i neft', 2019, no. 4, pp. 30-34.
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|OIL FIELD DEVELOPMENT & EXPLOITATION|
622.337.2 + 622.276.63
The Republic of Tatarstan possesses considerable high- and ultra-high viscosity oil reserves. The latter are localized at relatively shallow depths (primarily up to 200 m), but fall under the category of hard-to-recover due to high viscosity reaching in-situ as high as 100 Pa·s and even higher. High-viscosity oil fields are developed under conventional natural drive utilizing the reservoir energy or under waterflood, that fail to provide high oil recovery factors. Ultra-viscous oil is recovered using thermal methods. Steam-assisted gravity drainage is the most extensively used method in Tatneft Company. Although this technology has already proven its efficiency, various factors affect ultra-viscous oil production in the Company: complex geological structure of the fields (small thicknesses, heterogeneous structure with low-permeability shale interlayers, vertical and horizontal variations in oil saturation and permeability, moving oil-water contact); vertical viscosity variations; substantial costs associated with steam generation and injection; considerable expenses on treatment of produced fluid. These factors are detrimental to the economics of ultra-viscous oil field development projects that often are rendered unprofitable without tax incentives. Chemical (thermal-chemical) treatments may improve economic efficiency of high- and ultra-high viscosity oil production, when heat and steam generation does not require considerable costs. In light of the above, assessment of applicability of chemical agents and compositions thereof to enhance the efficiency of high-viscosity field development becomes of utmost importance.
1. Wilson A., Pelican lake: First successful application of polymer flooding in a heavy-oil reservoir, Journal of Petroleum Technology, 2014, December, 31, URL: https://jpt.spe.org/pelican-lake-first-successful-application-polymer-flooding-heavy-oil-reservoir
2. Akhmetzyanov F.M., BeregovoyAnt. N., Knyazeva N.A. et al., Problemy razrabotki zalezhi sverkhvyazkoy nefti s perekhodnymi (vodoproyavlyayushchimi) zonami plasta (Problems of development of extra-viscous oil deposits with transitional (water-producing) formation zones), Proceedings of TatNIPIneft' / PAO Tatneft', 2021, V. 89, pp. 139–144.
3. Rakhimova Sh.G., Amerkhanov M.I., Andriyanova O.M., Latypov R.R., Fil'tratsionnye issledovaniya vliyaniya kompozitsiy neionogennykh poverkhnostno-aktivnykh veshchestv i rastvoriteley na effektivnost' vytesneniya vysokovyazkoy nefti (Filtration studies of the effect of compositions of nonionic surfactants and solvents on the efficiency of high-viscosity oil displacement), Proceedings of TatNIPIneft' / PAO Tatneft', 2012, V. 80, pp. 162–166.4. Massarweh O., Abushaikha A.S., The use of surfactants in enhanced oil recovery: A review of recent advances, Energy Reports, 2020, V. 6, pp. 3150–3178, DOI: https://doi.org/10.1016/j.egyr.2020.11.009
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Tracer studies for reservoir production management and monitoring of reservoir pressure maintenance systems have been widely used since the 1970s. Fluid flow distribution has been traced using radioactive tracer agents injected into wells. With the evolution of tracer technology, tracer study philosophy has been introduced to various aspects of field development to become a comprehensive diagnostic tool and a viable alternative to conventional research methods (well tests and production logging). Although based on a common tracing principle, tracer studies differ in terms of injected tracer agents, quantitative identification methods, flow directions, methods of interpretation, and application of the outcomes. These differences do not enable appropriate clustering of marker methods and addressing a variety of challenges using only one type of tracer, or single data recording or interpretation method, etc. Moreover, generally accepted classification and terminology are currently unavailable. These would allow for clear identification of marker study method applied and good decision-making while planning the operations. Consequently, classification of marker diagnostic methods, their description, determination of key features, structuring, implementation of relevant terms are important for the choice of appropriate research methodology and facilitate selection of best solutions to existing operational challenges.
In the article, the main clusters of the marker diagnostics method are formed to select the direction of research depending on the problem being solved, the boundaries of the possibilities of the methods used are constructed, and the details of the tasks to be solved within these boundaries are given. A variant of terminology is proposed to indicate the direction of research and problems solved by the marker method, as well as a classification of problems in the fields development that can be solved using marker diagnostic technologies.
1. Morozov O.N., Andriyanov M.A., Koloda A.V. et al., Use of intelligent tracer technology for inflow monitoring in horizontal producers of the Prirazlomnoye oilfield (In Russ.), Ekspozitsiya Neft' Gaz, 2017, no. 7 (60), pp. 24–29.
2. Gur'yanov A., Katashov A., Ovchinnikov K., Production logging using quantum dots tracers (In Russ.), Vremya koltyubinga. Vremya GRP, 2017, no. 2, pp. 42-51
3. Ovchinnikov K.N., Buzin P.V., Saprykina K.M., A new approach to well studies: horizontal well production logging using markers (In Russ.), Inzhenernaya praktika, 2017, no. 12, pp. 70-76.
4. Ovchinnikov K.N. et al., Simulation of marked propant propagation in hydraulic fracturing fracture (In Russ.), Burenie i neft', 2020, no. 10, pp. 20–26.
5. Kamyshnikov A.G., Zaripov A.T., Beregovoy A.N.et al., Carbon quantum dots used as tracers in ecological, hydrogeological monitoring and reservoir management (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 7, pp. 44-48, DOI: https://doi.org/10.24887/0028-2448-2021-7-44-48
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In reservoir engineering practice, decline curve analysis (DCA) techniques have been commonly used for recoverable reserves estimates. The benefits of the DCA-based production forecasting method include minimum requirements to reservoir characterization input data; processing of actual historical reservoir performance data; comprehensive accounting for reservoir characteristics and specific technological reservoir engineering aspects; and the simplicity of the method. Various decline curves are based on the statistical evaluation of reservoir performance curves for concrete reservoirs, so, they cannot be used universally. The study focused on the Carboniferous and the Devonian sandstone and carbonate reservoirs of all oil fields developed by Tatneft PJCS. Calculations showed that considering reservoir types and producing conditions, the most reliable are forecasting methods after A.M. Pirverdyan, I.G. Permyakov, A.V. Kopytov, S.N. Nazarov, G.S. Kambarov, and the method developed by TatNIPIneft. In the framework of the in-depth study of carbonate reservoirs, which involved ninety-nine accumulations in Tatarstan, additional forecasting techniques that account for waterflood performance, stage of reservoir development, and the extent of reserves’ depletion were analyzed. Eight forecasting techniques were used for each carbonate reservoir to estimate reserves. Reliability limits for the calculated data have been determined. Based on the specified criteria, the accuracy of the calculation results was checked, and the appropriate forecasting methods were selected. It was found that certain methods can only give reliable results on condition of steady watercut increase in the pre-forecast period. Furthermore, the accuracy of certain forecasting methods depends on the stage of development and the extent of reserves’ depletion. It was concluded that applicability of certain analytical methods is limited by reservoir geology, current development status, and waterflood performance. The most appropriate methods for Tatarstan carbonate reservoirs performance analysis have been identified, as well as the screening and applicability criteria. These methods provide an accurate and prompt analysis of the field development process and reservoir management decisions, so the operator makes no delay in taking necessary steps to improve reservoir performance.
1. 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 PNRPU, 2013, 177 p.
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4. P'yankov V.N., Algorithms for identifying parameters of the Buckley-Leverett model in oil production forecasting problems (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 1997, no. 10, pp. 62–65.
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The paper presents the results of studies of the effects of geomechanical factors on development of reservoirs confined to poorly cemented Tulskian sandstones. The study aims to assess the risks of irreversible reservoir changes in the interwell space due to deformations resulting from stresses beyond the elastic limit when reservoir pressure changes, provide recommendations on optimal bottomhole pressures for injection wells to ensure maximum injectivity, and determine critical drawdowns which result in carryover of solids into the wellbore for production wells. The results are based on 1D and 3D/4D geomechanical modeling. Input data used to build a geomechanical model included laboratory core study data and well logging data. Determination of elastic and strength properties, their dependence on other reservoir parameters and well logging data for each production target is a unique challenge. The paper presents the findings of geomechanical research efforts. The results of hydraulic fracturing processes analysis, downhole equipment maintenance data, reservoir pressure history, and well log interpretations were also used as input data. Laboratory core studies yielded the dependences on the parameters of radioactive logging methods (normalized gamma-ray logging, gamma-ray neutron logging) for estimation of geomechanical properties. Changes of the minimum horizontal stress with reservoir pressure variations were determined, recommended injection well overbalance ranges were obtained, analysis of solids carryover was conducted as well as calculations of critical drawdowns for production wells. Probability of irreversible reservoir changes in the interwell space for poorly cemented rocks was analyzed. Geomechanical modeling was conducted in GMS corporate software package of Tatneft PJSC.
1. Lutfullin A.A., Girfanov I.I., UsmanovI.T., Sotnikov O.S., Software for geomechanical simulation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 7, pp. 49-52, DOI: https://doi.org/10.24887/0028-2448-2021-7-49-52.
2. Girfanov I.I., Usmanov I.T., Relationships for determination of geomechanical properties for Romashkinskoye oil field conditions (In Russ.), Neftyanaya provintsiya, 2021, no. 3, pp. 57-66, DOI: https://doi.org/10.25689/NP.2021.3.57-66.
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The article presents an overview of geological conditions, technological parameters, and field results of the largest international and Russian polymer flooding projects including its variations, surfactant-polymer and alkali-surfactant-polymer flooding. It is shown that development of new types of polymers, including those resistant to thermal-oxidative and chemical degradation, can increase the number of candidate reservoirs for polymer flooding. The dependence of the selected polymer mass fraction in the slug on the viscosity of oil in reservoir conditions is presented. It is noteworthy that most polymer projects have been implemented in reservoirs with in-situ oil viscosities ranging from 10 to 100 mPa·s; as for the Canadian projects, they were effective in reservoirs with oil viscosities up to 1800 mPa·s. The formulas given for viscosity of a polymer solution vs. viscosity of in-situ oil can be used for design of polymer flooding in various geological and reservoir conditions. A literature review showed that polymer flooding and its variations allow increasing oil recovery factor by 15-30%, given reasoned choice of polymer, surfactants, and alkali, optimal values of mass fraction of components in slug, and the size of the slug. It is noted that to improve polymer flooding performance in fractured and abnormally high perm formations, it shall be preceded by injection of blocking crosslinked polymers or encapsulated microgel compositions. For a large-scale implementation of polymer flooding projects to accelerate oil production rates and to increase recovery factors, production of state-of-the-art equipment for injection of polymer systems, high-performance polymers and surfactants to meet various geological and reservoir conditions shall be arranged in Russia, which calls for measures of State support for large polymer projects.
1. Thomas A., Essentials of polymer flooding technique, John Wiley and Sons Ltd., 2019, 328 p.
2. Galeev R.G., Opyt primeneniya polimernogo zavodneniya i ego raznovidnostey na neftyanykh mestorozhdeniyakh (Experience in the application of polymer flooding and its varieties in oil fields), Al'met'evsk, 1998, 34 p.
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5. Musin M.M., Muslimov R.Kh., Sayfullin Z.G., Fatkullin A.Kh., Issledovanie mekhanizma zavodneniya neodnorodnykh plastov (Study of the mechanism of waterflooding in heterogeneous reservoirs), Kazan' : Otechestvo Publ., 2001, 252 p.
6. Shvetsov I.A., Kukin V.V., Gorbatova A.N. et al., Efficiency of polymer treatment at the Orlyanskoye field (In Russ.), Neftyanoe khozyaystvo, 1986, no. 3, pp. 38-40.
7. Kudinov V.I., Suchkov B.M., Novye tekhnologii povysheniya dobychi nefti (New technologies for increasing oil production), Samara: Samara book publishing house, 1998, 368 p.
8. Bondarenko A.V., Sevryugina A.V., KovalevskiyA.I., Kirillov D.A., Results of pilot works on polymer flooding at the Moskudinskoe field (In Russ.), Geologiya, geofizika i razrabotka neftyanykh i gazovykh mestorozhdeniy, 2019, no. 6, pp. 61-65, DOI: https://doi.org/10.30713/2413-5011-2019-6(330)-61-65
9. Delamaid E., Using horizontal wells for chemical EOR: Field cases (In Russ.), Georesursy, 2017, no. 3, pp. 166-175, DOI: https://doi.org/10.18599/grs.19.3.3
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11. Thomas S., Chemical EOR: The past - Does it have a future, Paper SPE 108828 based on a speech presented as an SPE Distinguished Lecture during the 2005–2006 season, URL: https://www.spe.org/media/filer_public/47/4b/474b460c-4621-4fdb-aaca-72fd1b10f619/spe-108828-dl.pdf
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13. Taber J.J., Martin F.D., Seright R.S., EOR screening criteria revisited – Part 1: Introduction to screening criteria and enhanced recovery field projects, SPE–35385-PA, 1997, DOI: https://doi.org/10.2118/35385-PA.
14. Saboorian-Jooybari H., Dejam M., Chen Z., Half-century of heavy oil polymer flooding from laboratory core floods to pilot tests and field applications, SPE-174402-MS, 2015, DOI: https://doi.org/10.2118/174402-MS
15. Cheng J., Wang D., Sui X. et al., Combining small well spacing with polymer flooding to improve oil recovery of marginal reservoirs, SPE-96946-MS, 2006, DOI: https://doi.org/10.2118/96946-MS.
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18. Wang J., Dong M., Optimum effective viscosity of polymer solution for improving heavy oil recovery, Journal of Petroleum Science and Engineering, 2009, V. 67, pp. 155-158, DOI: https://doi.org/10.1016/j.petrol.2009.05.007
19. Toma A., Sayuk B., Abirov Zh., Mazbaev E., Polymer flooding to increase oil recovery at light and heavy oil fields (In Russ.), Territoriya NEFTEGAZ, 2017. – ¹ 7–8. – S. 58–68.
20. Guo H., Ma R., Kong D., Success and lessons learned from ASP flooding field tests in China, SPE-186931-MS, 2017, DOI: https://doi.org/10.2118/186931-MS
21. Sun C., Guo H., Li Y., Song K., Recent advances of surfactant-polymer (sp) flooding enhanced oil recovery field tests in China, Geofluids, 2020, DOI: https://doi.org/10.1155/2020/8286706.
22. Volokitin Y., Shuster M., Karpan V. et al., Results of alkaline-surfactant-polymer flooding pilot at West Salym field, SPE-190382-MS, 2018, DOI: https://doi.org/10.2118/190382-MS
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For dynamic modeling, a block of the Bureikinskoye high-viscosity oil field was selected. The producing Bobrikovskian formation comprises high-permeability sandstone characterized by non-uniform lithological and physical properties, multilayering, widely-changing crude oil properties. The paper presents description of geological setting and averaged poroperm properties, as well as the analysis of the production performance. The FlowER propriety program package was used for model building and automatic production history matching. The history match results demonstrate adequate quality of the simulation model and its applicability for prediction calculations of surfactant-polymer flooding and optimization of the ongoing project. Simulation flooding optimization experiment is described at length. Operation modes of producing and injection wells for the 10-years’ forecast period were selected using the FlowER module of automatic synthesis of optimal control. As a target function for optimization of the surfactant-polymer flooding, maximization of oil production at minimum injection volumes of chemical agents and water was used. Two strategies of surfactant-polymer flooding, with “low” and “high” saving of chemical agents, and two sets of injection wells were considered. In the course of synthesis, the best set of injection wells, optimal injection period, and optimal injection volumes were selected based on production and economic performance analysis. It is critical to perform laboratory studies using actual field samples prior to field application of surfactant-polymer flooding. The authors give practical recommendations on laboratory experiments and integration of their results into modeling.
1. Muslimov R.Kh., Abdulmazitov R.G., Khisamov R.B. et al., Neftegazonosnost' Respubliki Tatarstan. Geologiya i razrabotka neftyanykh mestorozhdeniy (Oil and gas bearing of the Republic of Tatarstan. Geology and development of oil fields), Part 2, Kazan': FEN Publ., 2007, 524 p.
2. Zolotukhin A.B., Modelirovanie protsessov izvlecheniya nefti iz plastov s ispol'zovaniem metodov uvelicheniya nefteotdachi (Modeling of oil recovery processes using enhanced oil recovery techniques), Moscow: Publ. of Gubkin University, 1990, 267 p.
3. Nikiforov A.I. Nizaev R.Kh., Khisamov R.S., Modelirovanie potokootklonyayushchikh tekhnologiy v neftedobyche (Modeling of flow diverting technologies in oil production), Kazan: Fen Publ., 2011, 223 p.
4. Garipova L., Persova M., Soloveichik Y. et al., Optimization of high-viscosity oil field development using thermo-hydrodynamic modeling, Proceedings of 19th International Multidisciplinary Scientific GeoConference SGEM, 30 June - 6 July 2019, Sofia, 2019, V. 19, pp. 473-480, DOI: https://doi.org/10.5593/sgem2019/1.3/S03.060
5. Persova M.G., Soloveichik Y.G., Ovchinnikova A.S. et al., Numerical 3D simulation of enhanced oil recovery methods for high-viscosity oil field, Proceedings of 14th International Forum on Strategic Technology (IFOST 2019), 14th-17th October 2019, Tomsk: IOP Conference Series: Materials Science and Engineering, 2021, V. 1019, Art. 012050, DOI: https://doi.org/10.1088/1757-899X/1019/1/012050
6. Soloveichik Yu.G., Persova M.G., Grif A.M. et al., A method of FE modeling multiphase compressible flow in hydrocarbon reservoirs, Computer Methods in Applied Mechanics and Engineering, 2022, V. 390, Art. 114468 (49 p.), DOI: https://doi.org/10.1016/j.cma.2021.114468.
7. Persova M.G., Soloveichik Y.G., Vagin D.V. et al., The design of high-viscosity oil reservoir model based on the inverse problem solution, Journal of Petroleum Science and Engineering, 2021, V. 199, Art. 108245, DOI: https://doi.org/10.1016/j.petrol.2020.108245
8. Nasybullin A.V., Persova M.G., OrekhovE.V. et al., Modeling of surfactant-polymer flooding using a novel FlowER software program (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 7, pp. 40–43, DOI: https://doi.org/10.24887/0028-2448-2021-7-40-43.
9. Persova M.G., SoloveichikY.G., Vagin D.V. et al., Oil production optimization based on the finite-element simulation of the multi-phase flow in porous media and inverse problem solution, Proceedings of GeoBaikal 2020, Irkutsk: Publ. of EAGE, 2020, URL: https://www.earthdoc.org/content/papers/10.3997/2214-4609.202052021, DOI: https://doi.org/10.3997/2214-4609.202052021.10. Skripkin A.G., Kol'tsov I.N., Mil'chakov S.V., Experimental studies of the capillary desaturation curve in polymer-surfactant flooding (In Russ.), ProNeft'. Professional'no o nefti, 2021, V. 6, no. 1, pp. 40–46, DOI: https://doi.org/10.51890/2587-7399-2021-6-1-40-46
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|OIL RECOVERY TECHNIQUES & TECHNOLOGY|
The paper presents results of comprehensive studies aimed at development of a unified approach to engineering of acidizing designs. The studies involved laboratory analysis of acid compositions and synthetic formation water, physical modeling of bottomhole treatment process, generalization of dependencies. Series of core flooding experiments included flushing of core samples with different acid compositions at different velocities, and made it possible to determine parameters of carbonate dissolution kinetics and formation of wormholes. These parameters were further used to populate acidizing simulator with data. To get better insight into the process of wormhole formation, seventy-two core flooding tests using carbonate samples from five development targets of the Volga-Ural petroleum play were used. Three acid systems used for flooding of core samples differed in concentration and reaction velocity control agents. In the process of interpretation of experiments results, necessary data for matching of mathematic models were obtained including initial data on acid injection rate and characteristics of wormholes formation, i.e., amount of injected acid pore volumes vs. onset of wormhole. For each development target, minimum values of acid pore volumes were obtained, which characterize the rate of wormhole formation. Laboratory analysis of physicochemical properties allowed to prioritize acid compositions considering specific reservoir conditions. The obtained quantitative and qualitative data will be interpreted for further use in physical and mathematical models of the processes of bottomhole treatments and acid fracturing of carbonate reservoirs.
1. Ibragimov N.G., Musabirov M.Kh., Yartiev A.F., Tatneft’s experience in commercialization of import-substituting well stimulation technologies (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2015, no. 8, pp. 86–89.
2. Nasr-El-Din H.A., van Domelen M.S., Sierra L., Welton T.D., Optimization of surfactant-based fluids for acid diversion, SPE-107687-MS, 2007, DOI: https://doi.org/10.2118/107687-MS.
3. Gomari K.A.R, Karoussi O., Hamouda A.A., Mechanistic study of interaction between water and carbonate rocks for enhancing oil recovery, SPE-99628-MS, 2006, DOI: https://doi.org/10.2118/99628-MS
4. Yartiev A.F., Tufetulov A.M., Musabirov M.H., Grigoryeva L.L., Enhancement of horizontal well oil recovery by means of chemical stimulation, Asian Social Science, 2015, V. 11, no. 11, pp. 346-356, DOI: https://doi.org/10.5539/ass.v11n11p346.
5. Khisamov R.S., Musabirov M.Kh., Yartiev A.F., Uvelichenie produktivnosti karbonatnykh kollektorov neftyanykh mestorozhdeniy (Increase in productivity of carbonate reservoirs of oil fields), Kazan': Ikhlas Publ., 2015, 192 p.
6. Zakirov I.S., Zakharova E.F., Musabirov M.Kh., Ganiev D.I., Approaches to assessing the effectiveness of chemicals on core material of Domanic deposits (In Russ.), Neftyanaya provintsiya, 2019, no. 3(19), pp. 141–155, DOI: https://doi.org/10.25689/NP.2019.3.141-155
7. Musabirov M.Kh., Dmitrieva A.Yu., Podbor kislotnykh kompozitsiy dlya obrabotki prizaboynoy zony plastov mestorozhdeniy NGDU “Bavlyneft'” (Selection of acid compositions for treatment of bottomhole formation zones of oil and gas production department "Bavlyneft"), Proceedings of TatNIPIneft' / PAO “Tatneft'”, Naberezhnye Chelny: Ekspozitsiya Neft' Gaz Publ., 2017, V. 85, pp. 217–228.8. Dmitrieva A.Yu., Musabirov M.Kh., Baturin N.I. et al., Digitized ranking of physical and chemical parameters of acid systems as a new approach to selection of optimal agents for targeted well acidizing in carbonate reservoirs (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 7, pp. 36-39, DOI: https://doi.org/10.24887/0028-2448-2021-7-36-39
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|OIL AND GAS ENGINEERING|
Petroleum reservoir management involves generation of multiple field development scenarios and portfolio of the best production enhancement technologies of an oil company given production and capital cost restrictions. Decision support systems based on fuzzy set methods and expert systems have gained wide acceptance for selection of production enhancement operations. The paper describes one of the approaches to long-term strategic planning based on approximate estimates of the performance of various simulation cases for all fields operated by a company using statistical proxy models. This enables assessment of company expenses and long-term economic performance. In Tatneft Company, this approach is implemented in Epsilon software package. Epsilon integrates hierarchical proxy models of Lazurit workstation. The models fully reproduce the production history and generate remaining oil reserve maps showing unswept areas and bypassed oil pockets, being potential candidates for infill drilling. The workflow allows for automatic, step-wise introduction of planned operations with gradual increase of well grid spacing. Each stage provides for evaluation of geological risks and profitability of each well. Those wells that do not meet specified conditions are excluded. At every simulation time step, remaining oil reserves are automatically redistributed according to extent of their depletion. Automatic execution of the algorithm yields a nonuniform, dense grid of planned production enhancement operations that meet geological, operational, and economic constraints. The paper describes optimization problem solution for different objective functions and constraints. To estimate the production and economic performance of Tatneft’s production assets and to optimize the investments in the selected development scenarios for each target, we applied two taxation systems. Analysis of the key performance indicators and selection of the best development scenario for the Company’s fields made it possible to decide on the most appropriate taxation system for a particular field.cie
1. Gharbi R., Application of an expert system to optimize reservoir performance, Journal of Petroleum Science and Engineering, 2005, V. 49, no. 3-4, pp. 261–273, DOI: http://dx.doi.org/10.1016/j.petrol.2005.05.008
2. Nageh M., Abu M., Sayed E., Sayyouh H., Application of using fuzzy logic as an artificial intelligence technique in the screening criteria of the EOR technologies, SPE-175883-MS, 2015, DOI: https://doi.org/10.2118/175883-MS
3. Bing Han, Xiaoqiang Bian, A hybrid PSO-SVM-based model for determination of oil recovery factor in the low-permeability reservoir, Petroleum, 2018, V. 4, no. 1, pp. 43–49, DOI: https://doi.org/10.1016/j.petlm.2017.06.001
4. Aldhaheri M., Wei M., Bai B., Alsaba M., Development of machine learning methodology for polymer gels screening for injection wells, Journal of petroleum science & engineering, 2017, V. 151, pp. 77-93, DOI: https://doi.org/10.1016/j.petrol.2016.12.038
5. Tarrahi M., Afra S., Surovets I., A novel automated and probabilistic EOR screening method to integrate theoretical screening criteria and real field EOR practices using machine learning algorithms, SPE-176725-MS, 2015, DOI: https://doi.org/10.2118/176725-MS
6. Khazalia N., Sharifia M., Ahmadi M.A., Application of fuzzy decision tree in EOR screening assessment, Journal of Petroleum Science and Engineering, 2019, V. 177, pp. 167–180, DOI: https://doi.org/10.1016/j.petrol.2019.02.001
7. Ramos G.A.R., Akanji L., Application of artificial intelligence for technical screening of enhanced oil recovery methods, Journal of Oil, Gas and Petrochemical Sciences, 2017, V. 0, pp. 6–16, DOI: https://doi.org/10.30881/jogps.00002
8. AhmadiM.A., Soleimani R., Lee M. et al., Determination of oil well production performance using artificial neural network (ANN) linked to the particle swarm optimization (PSO) tool, Petroleum, 2015, V. 1, no. 2, pp. 118–132, DOI: https://doi.org/10.1016/j.petlm.2015.06.004
9. Panja P., Velasco R., Pathak M., Deo M., Application of artificial intelligence to forecast hydrocarbon production from shales, Petroleum, 2018, V. 4, no. 1, pp. 75–89, DOI: https://doi.org/10.1016/j.petlm.2017.11.003
10. Wang Sh., Chen Z., Chen Sh., Applicability of deep neural networks on production forecasting in Bakken shale reservoirs, Journal of Petroleum Science and Engineering, 2019, V. 179, pp. 112–125, DOI: https://doi.org/10.1016/j.petrol.2019.04.016
11. Ruiz M., Alzate-Espinosa G., Obando A., Alvares H., Combined artificial intelligence modeling for production forecast in an oil field, CT&F - Ciencia, Tecnologia y Futuro, 2019, V. 9, no. 1, pp. 27–35, DOI: https://doi.org/10.29047/issn.0122-5383
12. Krasnov F., Glavnov N., Sitnikov A., A machine learning approach to enhanced oil recovery prediction, Analysis of Images, Social Networks and Texts: 6th International Conference, AIST 2017, Moscow, Russia, 2017 July 27–29, Cham: Springer, 2018, pp. 164–171.
13. Suleimanov B.A., Ismayilov F.S., Dyshin O.A., Veliyev E.F., Selection methodology for screening evaluation of EOR methods, Petroleum Science and Technology, 2016, V. 34, no. 10, pp. 961-970, DOI: https://doi.org/10.1080/10916466.2015.1107849
14. Khisamov R.S., GanievB.G., Galimov I.F. et al., Computer-aided generation of development scenarios for mature oil field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2020, no. 7, pp. 22–25, DOI: https://doi.org/10.24887/0028-2448-2020-7-22-25.
15. Nasybullin A.V., Sattarov Ram.Z., LatifullinF.M. et al., Creation of software tool for long-term investment planning with a view to the effective development of oil fields (In Russ.), Neftjanoe hozjajstvo = Oil Industry, 2019, no. 12, pp. 128–131, DOI: https://doi.org/10.24887/0028-2448-2019-12-128-131.
16. Zvezdin E.Ju., MannapovM.I., Nasybullin A.V. et al., Stage-wise optimization of project well pattern using oil reserves evaluation program module (In Russ.), Neftjanoe hozjajstvo = Oil Industry, 2019, no. 7, pp. 28–31, DOI: https://doi.org/10.24887/0028-2448-2019-7-28-31.
17. Ganiev B.G., Nasybullin A.V., Sattarov Ram.Z. et al., Application of machine learning method for planning of well drilling in producing oil formations (In Russ.), Neftjanoe hozjajstvo = Oil Industry, 2021, no. 7, pp. 23–27, DOI: https://doi.org/10.24887/0028-2448-2021-7-23-27.18. Poirriez V., Yanev N., Andonov R., A hybrid algorithm for the unbounded knapsack problem, Discrete Optimization, 2009, V. 6, no. 1, pp. 110–124, DOI: https://doi.org/10.1016/j.disopt.2008.09.004
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|OIL FIELD EQUIPMENT|
Steels have been extensively used for construction of oilfield equipment, particularly tanks and vessels. However, steel materials fail to resist corrosion when exposed to aggressive media. Two methods are mainly used to protect metal structures against corrosion in specific environments. These are application of insulating coatings and electrochemical protection. Electrochemical (sacrificial or cathodic) protection is provided by application of direct current having negative polarity onto metal structure. Cathodic protection systems require an outside DC power source, namely special-purpose AC to DC converters or cathodic protection stations. During corrosion protection, the negative pole of cathodic protection station is connected to metal structure to be protected, while the positive pole is connected to electrode (anode). Reliability of cathodic protection systems largely depends on anode material and structure. Nowadays, low-solubility electrodes have gained wide acceptance in anodic grounding of cathodic protection units, particularly electrodes made of high silicon cast iron - ferrosilide. Ferrosilide, as anode-resistant material, has limited applications confined to moderate operating conditions. Severe conditions associated with protection of offshore structures, saline soils-buried pipelines, and the interior of oilfield tanks and vessels require anode materials exhibiting better resistance in chloride-containing environments. Manufacturers of equipment for electrochemical corrosion protection systems contribute to the development of technologies for production of grounding anode materials with platinum group-metal mixed oxide coatings to ensure an excellent corrosion resistance without sacrificing the electrical conductivity.
The paper discusses the advantages and disadvantages of various grounding anode materials, presents available types of grounding anodes used for cathodic protection against corrosion. The paper also reveals the findings of laboratory and bench tests on samples of titanium electrodes with manganese-dioxide corrosion-resistant coating, as well as the results of field trials of titanium electrode application in anode grounding for internal cathodic protection of vertical steel tanks.
1. Metodicheskie rekomendatsii po primeneniyu zhelezokremnistykh anodov dlya katodnoy zashchity podzemnykh metallicheskikh sooruzheniy (Guidelines for the use of iron-silicon anodes for cathodic protection of underground metal structures), Sbornik normativnykh dokumentov dlya rabotnikov stroitel'nykh i ekspluatatsionnykh organizatsiy gazovogo khozyaystva RSFSR. Zashchita podzemnykh truboprovodov ot korrozii (Collection of normative documents for employees of construction and operating organizations of the gas industry of the RSFSR. Corrosion protection of underground pipelines), Leningrad: Nedra, 1991, pp. 181-186.
2. Ermakov A.V., Igumnov M.S., Studenok E.S. et al., Development of new promising materials for anodes of electrochemical protection against corrosion (In Russ.), Korroziya Territorii Neftegaz, 2012, no. 3(23), pp. 62-65.3.
Promising anode materials in cathodic protection of pipelines and tanks from
electrochemical corrosion (In Russ.), Korroziya Territorii Neftegaz, 2018, no.
1(39), p. 107.
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|OIL TRANSPORTATION & TREATMENT|
665.61.033.5 + 546.13
One of the stock-tank oil quality indicators according to requirements of regulatory documents, is content of organic chlorides in fraction that boils at temperatures range from the true boiling point to 204 °Ñ. Main sources of oil contamination with organochlorine compounds are chemical agents used at certain stages of oil production. Numerous studies have confirmed that certain chemical agents initially free from organochlorine compounds can promote their formation. These are hydrochloric acid and quaternary ammonium salts contained in some corrosion inhibitors, bactericides, and paraffin inhibitors. Oil production is a complex process flow that involves application of both pure chemicals, and a wide variety of chemical compositions. One of the most widely used components of these compositions is hydrochloric acid, which, potentially can react with each agent in a composition. To assess the risk of formation of organochlorine compounds in the process of injection of HCl-based compositions, chemical interactions of individual components were studied. To determine the content of organic chlorine in organochlorine compounds, X-ray fluorescence analysis and gas chromatography-mass spectrometry methods were used. It was found that organochlorine compounds can be formed following reactions between chemical agents and hydrochloric acid contained in fluids used in the process of oil production; also, agents with high content of unsaturated compounds can, potentially, lead to forming of organochlorine compounds. Considering high risk of organochlorine compounds forming, such solvents are not recommended for use in technologies involving contact with hydrochloric acid.
1. Tatyanina O.S., Abdrakhmanova L.M., Sudykin S.N., Zhilina E.V., Obrazovanie legkoletuchikh khlororganicheskikh soedineniy pri pervichnoy peregonke nefti v rezul'tate razlozheniya khimicheskikh reagentov, soderzhashchikh soli chetvertichnykh ammonievykh soedineniy (Formation of volatile organochlorine compounds during primary distillation of oil as a result of decomposition of chemical reagents containing salts of quaternary ammonium compounds), Proceedings of TatNIPIneft', Naberezhnye Chelny: Ekspozitsiya Neft' Gaz Publ., 2017, V. 85, pp. 363–369.
2. Tatyanina O.S., Gubaidulin F.R., Sudykin S.N., Zhilina E.V., Gubaidulina R.I., Issledovanie vliyaniya khimicheskikh reagentov, primenyaemykh v sisteme neftedobychi, na obrazovanie khlororganicheskh soedineniy v nefti (Investigation of impact of chemical agents used in oil production process on forming of organochlorine compounds in oil), Proceedings of TatNIPIneft, Moscow: Neftyanoye Khozyaistvo Publ., 2020, V. 88. pp. 266-268.3. Tat'yanina O.S., Gubaydulin F.R., Sudykin S.N. et al., Quality control of chemical agents used by Tatneft PJSC for organic chlorine compounds content (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 7, pp. 56–58, DOI: https://doi.org/10.24887/0028-2448-2021-7-56-58
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Ultrasound wave stimulation at the hot separation stage has been considered as a promising method to improve hydrogen sulfide removal from crude oil. Application of ultrasound waves has proved effective in various industries and has been used for an appreciable length of time now to achieve different goals, in that number, to improve dispersion, dissolving, impregnation, cutting, bonding, and welding of different materials and media. Numerous experiments have shown that ultrasound waves improve the process of desorbing of water-dissolved gases, however literature about ultrasound waves used for gas removal, in particular, hydrogen sulfide removal from crude oil, is scarce. The efficiency of ultrasound wave stimulation of the hydrogen sulfide stripping process is controlled by physicochemical properties of the treated medium, pressure and temperature conditions, exposure time, sound wave power, ultrasound intensity and frequency. The experiments demonstrated that in oils with viscosities over 400 mPa·s, specific sound wave power increase has little, if any, effect on effectiveness of hydrogen sulfide stripping, while in oils with viscosities below 150 mPa·s, increase of the sound wave power from 100 to 200 W/dm3 enhances hydrogen sulfide removal twofold. The same tendency was observed for the ultrasound wave frequency. Increase of sound wave power and exposure time improves the hydrogen sulfide stripping process. This is especially true for lower-viscosity oils. Albeit considerable reduction of hydrogen sulfide in crude oil, increase of the sound wave power is not entirely worthwhile. A relationship between exposure time and oil viscosities in the range between 40 and 415 mPa·s has been offered. The ultrasound technology can be used to full advantage at oil treatment facilities reducing consumption of hydrogen sulfide chemical scavenger.
1. Ibragimov N.G., Shatalov A.N., Sakhabutdinov R.Z. et al., Process solutions to improve efficiency of nonchemical hydrogen sulfide removal from crude oil (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 6, pp. 58–61, DOI: https://doi.org/10.24887/0028-2448-2017-6-58-61
2. Sakhabutdinov R.Z., Anufriev A.A., Shatalov A.N., Shipilov D.D., Improvement of hydrogen sulfide stripping physical methods (In Russ.), Ekspozitsiya Neft' Gaz, 2017, no. 3, pp. 39–41.
3. Shatalov A.N., Anufriev A.A., GarifullinR.M. et al., Vybor optimal'noy skhemy ochistki nefti ot serovodoroda na UPVSN «Kutema» NGDU «Nurlatneft'» (Selection of the optimal scheme for oil purification from hydrogen sulfide at the Kutema UPVSN of NGDU Nurlatneft), Sbornik nauchnykh trudov TatNIPIneft' / OAO Tatneft', Moscow: VNIIOENG, 2011, V. 79, pp. 310–314.
4. Kuznetsov O.L., Efimova S.A., Primenenie ul'trazvuka v neftyanoy promyshlenosti (Application of ultrasound in the oil industry), Moscow: Nedra Publ., 1983, 192 p.5. AnufrievA.A., Shatalov A.N., Shipilov D.D. et al., Improved efficiency of hydrogen sulfide stripping (In Russ.), Neftyanaya provintsiya, 2019, no. 2, pp. 174–183, URL: https://docs.wixstatic.com/ugd/2e67f9_4c0b16023ff94c509fca0b88654b017a.pdf
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|ENERGY SAVING SOLUTIONS|
The paper discusses optimal operation of pump stations during periods of peak demands with a view to power reduction. The energy suppliers establish control intervals of generator and network power with increased charges in the electricity tariff. Power consumption governing is realized through a number of administrative and operational activities. These include change of pumps scheduling during minimum tariffs’ periods (night working hours, days-off and holidays) and shutdowns during control intervals. Various factors responsible for maximum shutdown period are considered: pump excess capacity, fluid volumes, well operation modes, etc. If necessary, relevant actions are undertaken to extend shutdown periods. The shutdown periods of each pump station are distributed over the control periods’ hours. Then, general shutdown schedules separately for tank farms, treatment facilities, oil production units, fields, and the Company are prepared. Maximum power reduction is provided for the control intervals of generator power having the highest electricity tariffs. Considering that the Company operates several dozens of pump stations, the process is rather time-consuming with a variety of solutions. The task is further complicated by the fact that the control intervals of generator power differ in the probability of occurrence – high, medium, and low. The analysis of the facilities’ scheduling process showed that the task can be algorithmized to create a scheduling software. One of the two offered algorithms was used for the software engineering. For each pump station, the software program calculates possible scenarios of shutdown distribution over the control intervals and analyzes the cost efficiency. The output results are the facilities’ schedules and summary tables of hourly breakdowns of power inputs. Improvement of the activities’ efficiency is achieved by walk through different scenarios of pump stations operation and shutdown during control hours.
1. Arsent'ev A.A., Sobolev S.A., Fattakhov R.B. et al., Algoritm uchastiya predpriyatiya v regulirovochnykh meropriyatiyakh s tsel'yu snizheniya platy za elektricheskuyu energiyu (Algorithm for the participation of the enterprise in regulatory measures in order to reduce the payment for electricity), Proceedings of TatNIPIneft' / Tatneft', Moscow: Neftyanoe khozyaystvo Publ., 2020, V. 88, pp. 250-256.
2. Fattakhov R.B., Sattarov Rav.Z., Khanipov M.N. et al., Regulirovanie potrebleniya elektricheskoy energii i moshchnosti v sisteme podderzhaniya plastovogo davleniya (Regulation of electrical energy and power consumption in the formation pressure maintenance system)Sbornik nauchnykh trudov TatNIPIneft' / PAO «Tatneft'». – M.: Neftyanoe khozyaystvo, 2016. – Vyp. 84. – S. 202-208.3. Certificate of official registration of the
computer program no. 2021680622 RF, Programma raspredeleniya raboty kustovykh
nasosnykh stantsiy po intervalam kontrolya moshchnosti v period pikovoy
nagruzki energosistemy (The program for distributing the work of cluster
pumping stations by intervals of power control during the peak load period of
the power system), Authors: Sobolev S.A., Arsent'ev A.A.
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|OIL & GAS COMPANIES|
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|GEOLOGY & GEOLOGICAL EXPLORATION|
Most of the currently known fields of the West Siberian oil and gas province are characterized by a complex geological structure and the presence of reserves difficult to recover. The development of these complex features will help maintain declining production from discovered and developed fields in Western Siberia. Efficient development of deposits of the Bazhenov formation and Achimov formation is possible only if there are objective ideas about the geological structure of these deposits. It seems important to link the features of the formation of these objects at the junction of the Jurassic and Cretaceous periods.
Based on the results of the detailed well log correlation of the entire well stock for the Nong-Eganskoye field, this article will show what processes took place during the formation of the Bazhenov-Achimov rock complex and their results. It has been established that the currently observed sharp "jumps" of the Bazhenov formation itself on the correlation schemes and seismic sections are the result of keyboard block subsidence along consedimentary faults. The analysis of structural and thickness maps of the anomalous section of the Bazhenov formation, the Bazhenov formation itself, and the Achimov compensation pack, showed almost identical outlines of the configurations of the positive or negative structures of the three studied objects, which indicate the tectonic nature of their formation. The use of such research methods as successive paleoprofiling and reduction of to one thickness made it possible to substantiate the formation of the Bazhenov-Achimov rock complex by tectonic movements. Genesis of this complex has a block character of multispeed subsidence of adjacent block. Undisturbed character bedding of rocks deals with different-velocity subsidence of the seabed in the same time interval within the blocks.
1. Gutman I.S. Korrelyatsiya razrezov skvazhin slozhnopostroennykh neftegazonosnykh ob»ektov i geologicheskaya interpretatsiya ee rezul’tatov (Correlation of well sections of complex oil and gas objects and geological interpretation of its results), Moscow: ESOEN Publ., 2022, 336 p.
2. Gutman I.S., Comprehensive confirmation of tectonic nature of the anomalous sections of the Bazhenov formation and the lower cretaceous Achimov stratum of Western Siberia. Part 1. The anomalous sections of the Bazhenov formation and the lower cretaceous Achimov stratum of Western Siberia (In Russ.), Aktual’nye problemy nefti i gaza, 2019, no. 3(26), DOI: https://doi.org/10.29222/ipng.2078-5712.2019-26.art5
3. Gutman I.S. Aref’ev S.V., Mitina A.I., The rationale for the block structure of the abnormal sections of the Bazhenov formation and related sections of the Achimov sequence by the example of the North-Konitlorskoe field (In Russ.), Geologiya geofizika i razrabotka neftyanykh i gazovykh mestorozhdeniy, 2020, no. 2, pp. 4–12, DOI: https://doi.org/10.30713/2413-5011-2020-2(338)-4-12
4. Gutman I.S., Aref'ev S.V., Mitina A.I., Methods of detailed correlation of well sections in the study of the geological structure of Upper Jurassic and Lower Cretaceous rock complexes on the example of the Tevlinsko-Russkinskoye oil field of the Surgut arch. Part 1. Substantiating the formation features of the Upper Jurassic Bazhenov formation proper and its anomalous sections (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2020, no. 8, pp. 18-21, DOI: https://doi.org/10.24887/0028-2448-2020-8-18-215. Gutman I.S., Aref'ev S.V., Mitina A.I., Methods of detailed correlation of well sections in the study of the geological structure of Upper Jurassic and Lower Cretaceous rock complexes on the example of the Tevlinsko-Russkinskoye oil fields of the Surgut arch. Part 2. Substantiating the formation features of the Lower Cretaceous Sortym formation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2020, no. 10, pp. 25–29, DOI: https://doi.org/10.24887/0028-2448-2020-10-25-29
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This article presents some results of the sequence-stratigraphic analysis performed at the Minkhovskoye field in connection with the discovery of gas deposits in the Lower Cretaceous clinoform complex (Akhskaya formation).
The Minkhovskoye gas condensate field is located in Western Siberia on the northern shore of the Taz Bay within the Tazovsky District of the Yamalo-Nenets Autonomous District of the Tyumen region. In conformity with the accepted oil and gas geological zoning, it is located in the Messovsky oil and gas bearing area of the Gydan oil and gas region. The reduction in size and complexity of new objects in the Neocome of Western Siberia, together with the increase in the resolution of modern 3D seismic exploration, require further development of the clinoform concept. It follows from a number of modern works based on the modern model-independent methodology of sequence stratigraphy. The use of genetic sequencing for this purpose, firstly, makes it possible to fully utilize the vast experience gained during clinoform modeling, and secondly, it better corresponds to the practice of dividing the section into regional reservoirs and cap rocks. As a result of drilling N well in the Akhskaya formation of the Neocom of the Minkhovskoye field, two gas-saturated objects were identified, displayed on time sections in the form of two echelon-like intense negative anomalies. During the sequence-stratigraphic analysis, it was found that both objects are part of the Pym 2 genetic sequence. The lower one is the body of coastal-marine sandstones as part of the HST system tract, and the upper one is the body of coastal-marine sandstones as part of the lower parasequence of the FSST system tract. Judging by the forms of dynamic anomalies, the sand bodies in both cases were formed as a result of the progradation of the lobed (delta) type coast. The fact of the proven gas bearing capacity of these stratigraphic elements poses the task of their further mapping outside the Minkhovskoye seismic cube. The small area of the seismic cube has not yet made it possible to clarify the gas potential of submarine fan and shelf sand bodies in the upper parasequences of the FSST, as well as the gas potential of the shelf formation as part of the LST. This requires more extensive field studies.
1. Trushkova L.Ya., Igoshkin V.P., Khafizov F.Z., Klinoformy neokoma – unikal’nyy tip neftegazonosnykh rezervuarov Zapadnoy Sibiri (Neocomian clinoforms are a unique type of oil and gas bearing reservoirs in Western Siberia), St. Petersburg: Publ. of VNIGRI, 2011, 125 p.
2. Baldin V.A., Igoshkin V.P., Munasypov N.Z., Nizamutdinova I.N., Problems and methods of stratification (as exemplified by Jurassic-Cretaceous sediments in northeastern West Siberia) (In Russ.), Geofizika, 2020, no. 3, pp. 17-30.
3. Ershov S.V., Sequence stratigraphy of the Berriassian-Lower Aptian deposits of West Siberia (In Russ.), Geologiya i geofizika, 2018, V. 59, no. 7, pp. 1106–1123, DOI: https://doi.org/ 10.15372/GiG20180711
4. Zhemchugova V.A., Rybal’chenko V.V., Shardanova T.A., Sequence-stratigraphic model of the west siberia lower cretaceous (In Russ.), Georesursy, 2021, V. 23, no. 2, pp. 179–191, DOI: https://doi.Org/10.18599/grs.2021.2.18
5. Spodobaev A.A., Nezhdanov A.A., Merkulov A.V., Results of the sequence-stratigraphic analysis of the Achimovsky deposits of the Yamburg oil and gas condensate field (In Russ.), Ekspozitsiya. Neft’ Gaz, 2018, no. 2(62), pp. 22–27.
6. Catuneanu O., Model-independent sequence stratigraphy, Earth-Science Reviews, 2019, no. 188, pp. 312–388, DOI: https://doi.org/10.1016/j.earscirev.2018.09.017
7. Catuneanu O., Principles of sequence stratigraphy, Amsterdam: Elsevier, 2006, 375 p.
8. Catuneanu O., Galloway W.E., Kendall C.G.St.C. et al., Sequence stratigraphy: methodology and nomenclature, Newsletters on Stratigraphy, 2011, V. 44, pp. 173–245, DOI: https://doi.org/10.1127/0078-0421/2011/0011
9. Potapova E.A., A sequence-stratigraphic approach implementation to reveal prospective zones of the new deposits within the southern part of Antipayuta Basin (In Russ.), Geologiya, geofizika i razrabotka neftyanykh i gazovykh mestorozhdeniy, 2020, no. 7(343), pp. 23–28.
10. Galloway W.E., Genetic stratigraphic sequences in basin analysis, I. Architecture and genesis of flooding-surface bounded depositional units, AAPG Bull., 1989, no. 73, pp. 125–142, DOI: https://doi.org/10.1306/703C9AF5-1707-11D7-8645000102C1865D11. Margulis L.S., Sequence stratigraphy in studying the structure of sedimentary covers (In Russ.), Neftegazovaya geologiya. Teoriya i praktika, 2008, no. 3, URL: http://www.ngtp.ru/rub/2/37_2008.pdf
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At present, hydrocarbon reserves in carbonate sediments are the source of growth and maintenance of oil production levels. Carbonate deposits development is characterized by high geological and technological risks of well drilling, related to poor reservoir properties and complex geological structure. Petroleum engineers making prompt decisions on drilling wells need express estimation tools that would help them rate geological and technological factors when identifying high-risk areas. The article discusses the use of an integral map of drilling risks for the Middle Carboniferous carbonate strata (reservoir Ñ2ks-pd) of the Arlanskoe field. The reservoir Ñ2ks-pd is defined by poor PVT characteristics, high lateral and areal heterogeneity, and void morpholoical variability. The development of the integral map of drilling risks was based on fuzzy logic methods, which allowsed finding unrevealed dependencies between successful drilling and different affecting factors. Preliminarily to form the list of geological and technological data, on which integral map development will be based. According to the obtained integral risk map, Ñ2ks-pd reservoir was ranked into 4 categories based on desirability degree: high, moderate, low and critical. The approach proposed in the article allowed adjusting drilling targets for wells previously placed in areas with low and critical desirability and highlight dangerous areas to perform additional research for prevention negative results prevention.
1. Lozin E.V., Razrabotka unikal’nogo Arlanskogo neftyanogo mestorozhdeniya vostoka Russkoy plity (Developing a unique Arlan oil field of the East of the Russian Plate), Ufa: Skif Publ., 2012, 704 p.
2. Burikova T.V., Savel’eva E.N., Khusainova A.M. et al., Lithological and petrophysical characterization of Middle Carboniferous carbonates (a case study from north-western oil fields of Bashkortostan) (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 10, pp. 18–21, DOI: https://doi.org/10.24887/0028-2448-2017-10-18-21
3. Amineva G.R., Burikova T.V., Savel’eva E.N. et al., Criteria for revealing petrophysical rock types using well logging in the Middle Carboniferous section of oil fields in North-Western Bashkortostan (In Russ.), Vestnik akademii nauk RB, 2020, V. 35, no. 2, pp. 26–35, DOI: https://doi.org/10.24411/1728-5283-2020-10203
4. Privalova O.R., Gadeleva D.D., Minigalieva G.I. et al., Well logging interpretation for Kashir and Podolsk deposits using neural networks (In Russ.), Neftegazovoe delo, 2021, V. 19, no. 1, pp. 69–76, DOI: http://dx.doi.org/10.17122/ngdelo-2021-1-69-76
5. Komova A.D., D’yakonova T.F., Isakova T.G. et al., Features of the structure and identification the complex reservoirs of Kashirskian-Podolskian deposits on an example of one of the fields of Bashkortostan (In Russ.), Geofizika, 2016, no. 3(49), pp. 18–21.
6. Gareev A.T., Nurov S.R., Vagizov A.M., Sibaev T.V., Complex approaches to improving development system of unique Arlanskoye oilfield (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2018, no. 12, pp. 112–116, DOI: https://doi.org/10.24887/0028-2448-2018-12-112-1167. Kharisov M.N., Yunusova E.A., Vagizov A.M. et al., Determination of optimal well interventions using Data Mining (In Russ.), Neftegazovoe delo, 2018, V. 16, no. 5, pp. 59–64, DOI: https://doi.org/10.17122/ngdelo-2018-5-59-64
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The drilling fluid filtration index depend on a number of factors such as process water composition, chemical reagents and materials, composition and concentration of the drilled and artificially introduced solid phase. Drilling fluid filtration index is also affected by technological and geological conditions, such as the mud cleaning system, composition and properties of the rocks and formation waters. This article presents the results of a laboratory study of the filtration rate dependence on the concentration of the solid phase presented in a model mineralized water-based biopolymer drilling fluid used in the fields of Eastern Siberia for drilling in the interval of salt and subsalt, including productive deposits. The study was carried out stepwise using drilling fluid samples, various models of the solid phase, both with and without the introduction of a calcium carbonate bridging agent. The model composition of the finely dispersed solid phase was a combination of geological section of rocks and based on previously performed studies. In the work, standard methods and common laboratory instruments to control the parameters were used. The research results showed that the increase in the concentration of drilled solids has a negative impact on the filtration index of the drilling fluid, and the introduction of calcium carbonate leads to a decrease in both the absolute values of the filtration index and its growth rate. Mathematical models that describe the dependence of the filtration index on the concentration of the solid phase in both the drilling fluid with and without a bridging agent are proposed. The optimal composition of the solid phase under considered conditions was revealed.
1. Predein A.P., Krysin N.I., On the issue of cleaning drilling fluids (In Russ.), Stroitel’stvo neftyanykh i gazovykh skvazhin na sushe i na more, 2006, no. 7, pp. 24–28.
2. 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/10.24887/0028-2448-2021-2-62-663.
Etalonnye materialy VNIIM. Standartnye obraztsy. Katalog (Reference materials
of the VNIIM. Standard samples.
Catalog), St. Petersburg: Publ. of D.I. Mendeleyev Institute for Metrology -
VNIIM, 2019, pp. 13–14.
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|OIL FIELD DEVELOPMENT & EXPLOITATION|
Laboratory modeling and study of the process of oil penetration into the gas cap, followed by its displacement by water or gas, is relevant for most oil and gas and gas-oil fields, including fields containing almost 10% of the current oil reserves of Rosneft Oil Company. One of the possible ways to increase the efficiency of development and reduce technological and economic risks is advanced (or simultaneous) development of the gas cap and oil reservoir. However, according to many scientists, a decrease in pressure in the gas cap due to gas extraction causes the penetration of oil into gas-saturated intervals and, as a result, irreversible losses of this oil, a decrease in the total oil recovery for the deposit. This approach to the development of oil objects in contact with the gas cap was formed because there was no purposeful laboratory study of the process, the formation of residual oil saturation in the gas cap after the penetration of oil into it. And the residual oil saturation in the gas cap was taken on the basis of the results of traditional experiments on the displacement of oil by water (or gas) for extremely oil-saturated core samples. The Tyumen Petroleum Research Center have developed and certified a method for measuring residual oil saturation in a gas-saturated reservoir after oil has been penetration into it, followed by its displacement by water or gas. The technology of physical modeling and determination of residual oil saturation in gas caps is based on many years of experience in conducting filtration experiments using a specialized stand, a distinctive feature of which is the use of two sources of gamma radiation from the radioactive isotope 241Am. A series of test experiments on core samples of a weakly consolidated reservoir of the Pokur suite, carried out at the bench, confirmed that the values of residual oil saturation after the penetration of oil into the gas cap are significantly lower than for extremely oil-saturated core samples of similar properties. This paper continues the discussion of the features of the technology of physical modeling of residual oil saturation in a gas cap after the penetration of oil into it. The results of the experiment on core samples from the BT formation of one of the Rosneft Oil Company fields in Eastern Siberia are presented.
1. Medvedev N.Ya., Yur'ev A.N., Baturin Yu.E., Metody i rezul'taty proektirovaniya i razrabotki neftegazovykh zalezhey mestorozhdeniy Surgutskogo rayona s obshirnymi podgazovymi zonami (Methods and results of design and development of oil and gas deposits in the fields of the Surgut region with extensive under-gas zones), Collected papers “Razrabotka neftyanykh i neftegazovykh mestorozhdeniy. Sostoyanie, problemy, puti resheniya” (Development of oil and oil and gas fields. Status, problems, solutions), Materials of the meeting, Almetyevsk, September 1995, Moscow: Publ. of VNIIOENG, 1996.
2. Martyntsev O.F., Oil recovery during the invasion of the oil rim in the gas-saturated part of the reservoir fluid during the directional discharge of water (In Russ.), Neftyanaya i gazovaya promyshlennost', 1973, no. 3, pp. 23–24.
3. Cheremisin N.A., Shulga R.S., Zagorovskiy A.A. et al., Residual hydrocarbon saturation in the transition zone and the gas cap, SPE-206585-MS, 2021, DOI: https://doi.org/10.2118/206585-MS
4. Cheremisin N.A., Sonich V.N., Baturin N.E., Medvedev N.Ya., Basic physics of increasing the efficiency of developing granulated reservoirs (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2002, no. 8, pp. 38-42.
5. Durmish'yan A.G., Gazokondensatnye mestorozhdeniya (Gas condensate fields), Moscow: Nedra Publ., 1979, 333 p.
6. Dvorak S.V., Sonich V.P., Nikolaeva E.V., Zakonomernosti izmeneniya neftenasyshchennosti v gazovykh shapkakh Zapadnoy Sibiri (Patterns of changes in oil saturation in gas caps in Western Siberia), Collected papers “Povyshenie effektivnosti razrabotki neftyanykh mestorozhdeniy Zapadnoy Sibiri” (Improving the development of oil fields in Western Siberia), Tyumen', 1988.
7. Mikhaylov N.N., Ermilov O.M., Sechina L.S., Physicochemical peculiarities of absorbed oil in core samples of gas condensate deposit (In Russ.), DAN = Doklady Earth Sciences, 2016, V. 466, no. 3, pp. 319–323.
8. Cheremisin N.A., Rzaev I.A., Borovkov E.V. et al., Improving the full-scale hydrodynamic model formation AV 1-5 Samotlorskoye field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2012, no. 10, pp. 49–53.
9. Anderson W.G., Wettability literature survey - Part 5: The effects of wettability on relative permeability, J Pet Technol, 1987, V. 39(11), pp. 1453–1468, DOI: https://doi.org/10.2118/16323-PA
10. Heidari M.A., Habibi A., Ayatollahi S. et al., Effect of time and temperature on crude oil aging to do a right surfactant flooding with a new approach, SPE-24801-MS, 2014, DOI: https://doi.org/10.4043/24801-MS
11. Jia D., Buckley J.S., Morrow N.R., Control of core wettability with crude oil, SPE-21041-MS, 1991, DOI: https://doi.org/10.2118/21041-MS
12. Zhou Xi., Morrow N.R., Shouxiang Ma, Interrelationship of wettability, initial water saturation, aging time, and oil recovery by spontaneous imbibition and waterflooding, SPE-62507-PA, 2000, DOI: https://doi.org/10.2118/62507-PA
13. Wang F., Effect of wettability alteration on water-oil relative permeability, dispersion and flowable saturation in porous media, SPE-15019-PA, 1986, DOI: https://doi.org/10.2118/15019-PA
14. Jerauld G.R., General three-phase relative permeability model for Prudhoe Bay, SPE-36178-PA, 1997, DOI: https://doi.org/10.2118/36178-PA
15. Jerauld G.R., Rathmell J.J., Wettability and relative permeability of Prudhoe Bay: A case study in mixed-wet reservoirs, SPE-28576-PA, 1997, DOI: https://doi.org/10.2118/28576-PA
16. DiCarlo D.A., Sahni A., Blunt M.J. Three-phase relative permeability of water-wet, oil-wet, and mixed-wet sandpacks, SPE-60767-PA, 2000, DOI: https://doi.org/10.2118/60767-PA
17. Hui M.-H., Blunt M.J., Effects of wettability on three-phase flow in porous media, J. Phys. Chem. B., 2000, V. 104 (16), pp. 3833–3845, DOI: https://doi.org/10.1021/jp9933222.
18. Legatski M.W., Katz L.D. et al., Displacement of gas from porous media by water, SPE-899-MS, 1964, DOI: https://doi.org/10.2118/899-MS
19. Mikhaylov N.N., Motorova K.A., Sechina L.S., Smachivaemost' neftegazovykh plastovykh sitem (Wettability of oil and gas reservoir systems), Moscow: Publ. of Gubkin University, 2019, 360 p.
20. Mikhaylov N.N., Sechina L.S., Gurbatova I.P., Wettability indicators in the porous environment and dependence between them (In Russ.), Georesursy, geoenergetika, geopolitika, 2011, no. 1(3), URL: http://oilgasjournal.ru/vol_3/mikhailov-sechina.html
21. Suicmez V.S., Piri M., Blunt M.J., Blunt pore-scale modeling of three-phase wag injection: Prediction of relative permeabilities and trapping for different displacement cycles, SPE-95594-MS, 2006, DOI: https://doi.org/10.2118/95594-MS22.
Cheremisin N.A., Sonich V.P., Baturin Yu.E., Methodology for substantiating
residual oil saturation in the water-driven mode of operation of productive
formations (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 1997, no. 9, pp. 58–61.
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Over the past few years, hard-to-recover reserves have been actively developed. The main method of well stimulation in case of low reservoir permeability is hydraulic fracturing. Currently, commonly used water-based fracturing fluids are cross-linked guar gels. The advantages of these systems include high values of effective viscosity, due to which the compositions retain the proppant well in volume. Another advantage is controlled time of cross-linking and destruction, which can be varied over a wide range by changing the concentrations of the reagents in the compositions. However, such fluids have several disadvantages; the main one is the clogging of the pore space of the fractured zone and the proppant pack by the remains of the undestroyed polymer. Clogging and, as a result, a decrease in the fracturing efficiency can also be related to swelling and subsequent migration of particles of clay minerals. New types of fracturing fluids that can minimize the disadvantages of cross-linked guar systems remain underestimated because of established approaches to testing sand-bearing fluids. Such liquids are compositions based on viscoelastic surfactants and synthetic polymers. The authors propose integrated approach to the study of structural and mechanical properties based on a combination of rotational and oscillatory rheology, and a comparative analysis of the influence of fluids on the reservoir rock.
1. Sullivan P.F. et al., Optimization of a viscoelastic surfactant (VES) fracturing fluid for application in high-permeability formations, SPE-98338-MS, 2006, DOI: https://doi.org/10.2118/98338-MS
2. Daeffler C. et al., Internal viscoelastic surfactant breakers from in-situ oligomerizationb, SPE-193563-MS, 2019, DOI: https://doi.org/10.2118/193563-MS
3. STO Gazprom 2-3.2-020-2005. Burovye rastvory. Metodika vypolneniya izmereniy koeffitsienta nabukhaniya glin i glinoporoshkov (Drilling solutions. Method for measuring the swelling coefficient of clays and clay powders).
4. Mordvinov A.A., Osvoenie ekspluatatsionnykh skvazhin (Development of production wells), Ukhta: Publ. of USTU, 2004, 108 p.
5. Anachkov S.E. et al., Viscosity peak due to shape transition from wormlike to disklike micelles: Effect of dodecanoic acid, Langmuir, 2018, V. 34, no. 16, pp. 4897–4907, DOI: https://doi.org/10.1021/acs.langmuir.8b00421
6. Kuryashov D.A. et al., Temperature effect on the viscoelastic properties of solutions of cylindrical mixed micelles of zwitterionic and anionic surfactants, Colloid Journal, 2010, V. 72, no. 2, pp. 230–235, DOI: https://doi.org/10.1134/S1061933X10020134
7. Agrawal N.R. et al., Wormlike micelles of a cationic surfactant in polar organic solvents: extending surfactant self-assembly to new systems and subzero temperatures, Langmuir, 2019, V. 35, no. 39, pp. 12782–12791, DOI: https://doi.org/10.1021/acs.langmuir.9b02125
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9. Gorodnov V.D., Fiziko-khimicheskie metody preduprezhdeniya oslozhneniy v burenii (Physical and chemical methods of prevention of complications in drilling), Moscow: Nedra Publ., 1984, 229 p.
10. Savari S. et al., Engineered LCM design yields novel activating material for potential application in severe lost circulation scenarios, SPE-164748-MS, 2013, DOI: https://doi.org/10.2118/164748-MS
11. Howard P.R., Hinkel J.J., Moniaga N.C., Assessing formation damage from migratory clays in moderate permeability formations, SPE-151818-MS, 2012, DOI: https://doi.org/10.2118/151818-MS
12. Maley D., Farion G., O’Neil B., Non-polymeric permanent clay stabilizer for shale completions, SPE-165168-MS, 2013, DOI: https://doi.org/10.2118/165168-MS13. Rawat A., Tripathi A., Gupta C., Case evaluating acid stimulated multilayered well performance in offshore carbonate reservoir: Bombay high, Proceedings of Offshore Technology Conference-Asia, Kuala Lumpur, Malaysia, March 2014, OTC-25018-MS, 2014, DOI: https://doi.org/10.4043/25018-MS
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Foreign projects for Rosneft Oil Company are one of the key areas for the hydrocarbon resource base development. Currently, Rosneft is running projects in Myanmar, Egypt, Iraq, Cuba and offshore of Mozambique. One of the special projects is the Varadero field on the territory of the Republic of Cuba. The oil bearing capacity at the field is found in the Upper Jurassic and Lower Cretaceous carbonate formations. The Varadero oil is a typical representative of the naphthenic oils of the North Cuban Oil Basin by its physico-chemical properties. It is characterized by high viscosity and density, significant content of resin-asphaltene compounds and sulfur. One of the essential activities during oil production at the Varadero field is the well stimulation and mitigation response in well operation. In relation to the object under consideration, it is possible to distinguish the fight against the formation of high-viscosity oil-water emulsions, the deposition of high molecular weight components and oilfield equipment corrosion. To restore the wells productivity and keep oil production at required level, it is recommended to use complex acid treatment technologies with use of organic solvents.
The article provides an algorithm for designing complex acid treatment technologies for the conditions of the Varadero field, based on a series of laboratory studies on the selection of acid compositions and solvents for cleaning the critical matrix from asphaltene deposits. The results of acid treatments are presented and an analysis of their effectiveness is performed.
1. Ananev V.V., Verzhbitskiy V.E., Obukhov A.N. et al., Geology and petroleum potential of the Gulf of Mexico, Cuba, SPE-171212-MS, 2014, DOI: https://doi.org/10.2118/171212-MS
2. Smith G.E., Hurlburt G., Li V.P., Heavy oil carbonate: Primary production in Cuba, SPE-79002-MS, 2002, DOI: https://doi.org/10.2118/79002-MS
3. Androulidakis Y., Kourafalou V., Hole L.R. et al., Pathways of oil spills from potential cuban offshore exploration: Influence of ocean circulation, J. Mar. Sci. Eng., 2020, V. 8, pp. 535, DOI: https://doi.org/10.3390/jmse8070535
4. Schenk C.J., Jurassic-Cretaceous composite total petroleum system and geologic models for oil and gas assessment of the North Cuba Basin, Cuba, In: U.S. Geological Survey North Cuba Basin Assessment Team, Jurassic-Cretaceous Composite Total Petroleum System and geologic assessment of oil and gas resources of the North Cuba Basin, Cuba, U.S. Geological Survey Digital Data Series DDS–69–M. Chap. 2, 94 p., URL: https://www.arlis.org/docs/vol1/A/289003955/289003955b.pdf
5. Gonsales P.E.O, Ramires A.B., Drilling strings design for construction of extended reach wells (on the example of Cuba), Neftegazovoe delo, 2019, V. 17, no. 5, pp. 15-22, DOI: http://dx.doi.org/10.17122/ngdelo-2019-5-15-22
6. Gusakov V.N., Kashtanova L.E., Nazarova S.V. et al., Design of technologies for processing bottom-hole zone of Varadero oilfield (Cuba) (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2017, no. 12, pp. 126–130, DOI: https://doi.org/10.24887/0028-2448-2017-12-126-130
7. Yakubova S.G., Manaure D.A., Machado R.A. et al., Effect of oxyethylated isononylphenol (neonol) on viscosity characteristics of water–oil emulsions , Petroleum Science and Technology, 2018, V. 36, no. 17, pp. 1389–1395, DOI: https://doi.org/10.1080/10916466.2018.1482318
8. Voloshin A.I., Dokichev V.A., Fakhreeva A.V. et al., Composition and physico-chemical properties of high-viscosity oil of Varadero oil field (Cuba) (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2019, no. 9, pp. 34-37, DOI: https://doi.org/10.24887/0028-2448-2019-9-34-37
9. Manaure D.A., Fakhreeva A.V., Voloshin A.I. et al., Oil composition of Varadero (Cuba) deposits according to IR and NMR spectroscopy (In Russ.), Bashkirskiy khimicheskiy zhurnal, 2019, V. 26, no. 2, pp. 55-60.
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11. API 42. Recommended practices for laboratory evaluation of surface active agents for well stimulation, Washington D.S.: American Petroleum Institute. 2nd Edition, 1990, 22 p.
12. Shaydullin V.A., Vakhrushev S.A., Magzumov N.R. et al., Features of killing wells operating fractured formations with abnormally low formation pressures and high gas factor (In Russ.), SPE-202071-MS, 2020, DOI: https://doi.org/10.2118/202071-MS
13. Bulgakova G.T., Kharisov R.Ya., Sharifullin A.R., Pestrikov A.V., Design optimization of large volume selective acid treatments in carbonate reservoirs (In Russ.), Territoriya Neftegaz, 2010, no. 11, pp. 39-43.
14. Rozovskiy A.Ya., Kinetika topokhimicheskikh reaktsiy (Kinetics of topochemical reactions), Moscow: Khimiya Publ., 1974, 224 p.
15. Vakhrushev S.A., Folomeev A.E., Kotenev Yu.A., Nabiullin R.M., Acid treatment with diverting on carbonate reservoirs of R. Trebs oil field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2016, no. 4, pp. 112–117.16. Folomeev A.E., Taipov I.A., Khatmullin A.R. et al., Gelled acid vs. self-diverting systems for carbonate matrix stimulation: an experimental and field study, SPE-206647-MS, 2021, DOI: https://doi.org/10.2118/206647-MS
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The authors introduce a new method of oil wells stimulation for carbonate reservoirs, characterized by the presence of a gas cap or adjacent water-bearing interlayers has been tested. This method is based on combination of mechanical (radial drilling using special technical system) and chemical (acid treatment of channels) methods. The technical system provides for application of radial mechanical drilling technology with the use of a special small-sized screw downhole motor. The main advantages of the technology, as compared with standard methods of perforation, are the possibility of selective action on the formation due to the predicted route of the channel and multiple placing of reagents and logging tools to the channel. The novelty of the technology lies in selective directional treatment, which allows effectively overcome the critical matrix zone and restore well productivity after drilling fluid infiltration. The ability to predict the trajectory of the channels while drilling makes it possible to avoid contact with water-saturated interlayers. This technology was first tested during works on recompletion in the overlying carbonate reservoirs of Kashirskian-Podolskian deposits of Arlanskoye field and Bashkirian stage deposits of Yugomashevskoye fields, operated by Bashneft-Dobycha LLC. The formations are characterized by the high heterogeneity and relatively close location of water-saturated interlayers. Three wells were selected for field testing. Two channels were drilled in each well: in two wells 7 m in length, in the third well 14 m. After drilling the channels, acidizing was performed through a special jet nozzle. More than 10 m3 of hydrochloric acid composition was injected into each of the drilled channels. Oil flow rate after field tests was 1.5 t/day in the first well, 3.9 t/day in the second one and 40.5 t/day in the third one. The experience of combining radial drilling of channels and acid treatment showed a number of advantages: first, the possibility of commingling formation zones separated by low-permeability vertical barriers; second, reduction of risks of breakthrough into water-bearing formations.
1. Loginov B.G., Malyshev L.G., Garifullin Sh.S., Rukovodstvo po kislotnym obrabotkam skvazhin (Guide to acid treatment of wells), Moscow: Nedra Publ., 1966, 219 p.
2. Suchkov B.M., Intensifikatsiya raboty skvazhin (Well stimulation), Moscow - Izhevsk: Publ. of Institute for Computer Research, 2007, 612 p.
3. Shaydullin V.A., Kamaletdinova R.M., Yakupov R.F. et al., Selecting the water shut-off technology for monolithic terrigenous formations (In Russ.), Neft’. Gaz. Novatsii, 2021, no. 7, pp. 34–38.
4. Patent US6772847B2, Chemically enhanced drilling methods, Inventors: Rae Philip J., Di Lullo Arias, Gino F., Portman, Lance N.
5. Rae Ph., Di Lullo G., Chemically-enhanced drilling with coiled tubing in carbonate reservoirs, SPE-67830-MS, 2001, DOI: https://doi.org/10.2118/67830-MS
6. Portman L., Rae Ph., Munir A., Full-scale tests prove it practical to «drill» holes with coiled tubing using only acid; no motors, no bits, SPE-74824-MS, 2002, DOI: https://doi.org/10.2118/74824-MS
7. Stanley F.O., Portman L.N., Diaz J.D. et al., Global application of coiled-tubing acid tunneling yields effective carbonate stimulation, SPE-135604-MS, 2010, DOI: https://doi.org/10.2118/135604-MS
8. Moss P., Portman L., Rae Ph., di Lullo G., Nature had it right after all! Constructing a “Plant Root”-like drainage system with multiple branches and uninhibited communication with pores and natural fractures, SPE-103333-MS, 2006, DOI: https://doi.org/10.2118/103333-MS
9. Perex L.A.A., Diaz J.D., Navarro M. et al., Successful offshore application of acid tunneling technology: Overcoming the difficulties of high depths, temperatures, and deviations, SPE-113855-MS, 2008, DOI: https://doi.org/10.2118/113855-MS
10. Diaz J.D., Espina V., Guerrero M. et al., Successful implementation of coiled-tubing acid tunneling gives operator a viable alternative to conventional stimulation techniques in carbonate reservoirs, SPE-107084-MS, 2007, DOI: https://doi.org/10.2118/107084-MS
11. Akhkubekov A.E., Vasilyev V.N., Acid tunneling technology: Application potential in Timan-Pechora carbonates, SPE-135989-MS, 2010, DOI: https://doi.org/10.2118/135989-MS
12. Strasburg J., Clark J., Acid tunneling stimulation in Oklahoma limestone using coiled tubing, SPE-120772-MS, 2009, DOI: https://doi.org/10.2118/120772-MS
13. Lyagov I.A., Baldenko F.D., Lyagov A.V. et al., Methodology for calculating technical efficiency of power sections in small-sized screw downhole motors for the “Perfobur” system (In Russ.), Zapiski Gornogo instituta, 2019, no. 6, pp. 694-700, DOI: https://doi.org/10.31897/pmi.2019.6.694
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Folomeev A.E., Vakhrushev A.S., Mikhaylov A.G., On the optimization of acid
compositions for geotechnical conditions of oilfields of Bashneft JSOC (In
Russ.), Neftyanoe khozyaystvo = Oil Industry, 2013, no. 11, pp. 108-112.
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|OIL AND GAS ENGINEERING|
The article discusses approaches to creating a smart tool for operational evaluation of the efficiency of the development system by dividing the field sites (development blocks) into ranks according to the degree of confidence of reserves with further preparation of a research program, as well as the formation of geological and technical measures for the pre-development of clustered reserves. The standard practices used for the assessment and forecast of recovery factor (RF) do not allow to quickly identify problems, as well as timely and effectively plan corrective measures aimed at regulating the pace of stock selection. In this regard, an alternative tool for analyzing field development has been developed, the main idea of which is the clustering of recoverable oil reserves (according to the degree of their involvement in the development process) and verification of the parameters of the oil recovery coefficient. Effective involvement of reserves involves determining the boundaries of their localization. That is why the key stages of the proposed methodology are as follows: development of a tool for localization of remaining recoverable reserves (the method of clustering reserves and RF verification); determination of the reasons for not achieving the final RF; selection of additional research program; development of a tool for the selection of targeted geological and technical measures; assessment of the applicability of recommended geological and technical measures.
The reserves were clustered, the RF was verified, and a smart card was built for one of the oil fields in Western Siberia, as well as the zones with the largest unprocessed reserves were identified and a program of additional studies and measures for the completion of reserves was formed. Depending on the category of the development site, as well as on the value of unprocessed reserves for each of the coefficients of the RF - an assessment of reserve losses due to the failure to achieve the design coefficient of displacement, flooding and coverage, respectively), recommendations are formed on the choice of geological and technical measures for involving non-drained zones in development.
The developed methodology has been successfully applied at the fields of the Rosneft's subsidiaries, the effectiveness has been confirmed by the completed geological and engineering operations program.
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This paper describes the approach for assessing the critical stress state and mechanical aperture of the fracture system in the near-wellbore zone, which takes into account the direction of the wellbore in relation to the revealed fracture system and the direction of the regional stress as well as the contribution of the wellbore pressure to the transition of a fracture to a critically stressed state with a subsequent increase in aperture.
Critically stressed state of a fracture was studied according to two criteria, such as dry friction criterion and Barton nonlinear shear strength criterion. The main differences between two criteria is about friction coefficient, in the case of dry friction criterion the more important are stresses (normal and shear) while in the case of the Barton nonlinear shear strength criterion shows that the importance is understanding of joint roughness coefficient, due to which the relationship between shear and normal stress becomes non-linear, also for different rocks strength will change, which approaches through such a parameter as the joint compressional strength (JCS).
The Barton-Bandis model was adopted as the fundamental model of fracture opening. This model allows the investigation of fracture aperture considering surface roughness and dilation due to shear displacement.
The simulation result is presented as a certain sinusoid (a fracture contour along the well surface, obtained from the results of the interpretation of the reservoir microscanner). The sinusoid has two attributes: fracture aperture in mm and critically stressed index. This allows us to explore how the critical stress state of a fracture in the near-wellbore zone changes when the pressure inside the well changes. This approach can be applied to select the optimal wellbore trajectory and reduce the risk of lost circulation in fractured reservoirs.
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Forecasting the drilling parameters is very relevant. Trained machine learning models make it possible to obtain a predictive value of regime parameters using previously accumulated experience without complex calculations. The applying of modern tools requires new approaches to the analysis of accumulated data. The main problem is the marking of possible cases for forecasting. The data were collected in the form of values of drilling parameters generalized over the intervals by the measured depth. A machine learning model was built to determine equivalent circulation density (ECD) based only on the project values of the well design and geology. This forecast makes it possible to determine the segments where the actual ECD deviated from the expected one. Thus, the data were re-labeled and the targets of the forecast were determined. Machine learning can classify these segments. Interpretations are discussed.
Any special tasks for machine learning impose restrictions on the data used. The article discusses the features of drilling data and the limitations of choosing such data for training. The problem of forecasting special cases is considered. Segments were identified where it was necessary to increase the ECD due to high gas readings by increasing the density of the solution. The drilling parameters of previous drilling intervals were taken as predictors. Algorithms trained specifically on such cases are able to predict them in the future. A positive forecast means a possible need to increase the mud density in the next drilling interval. The algorithm distinguishes such states from those when the density of the fluid remains unchanged. Difficulties in interpreting and evaluating such forecasts associated with working on actual data are considered.
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To provide main pipeline safe operation in course of transportation of oils with non-Newtonian rheology, a possibility to start temporarily shutdown pipelines shall be ensured. In this regard, a problem of predictive evaluation of congealed oil starting pressure is relevant. Uncertainty of this design value depends on initial parameters, specified by ranges of values. Use of an analogy between computing experiments and indirect measurements in theoretical metrology has permitted to apply a standard procedure on expressing the uncertainty to the starting pressure value. Calculations show that the oil temperature, which is initial information, contributes maximum uncertainty at the final calculation stage, the total value of which could reach 70% and more. A comparative assessment method for various modifications of calculation models for a specific sought quantity through standard uncertainty comparison is an effective formalized instrument, which is universal. Modification of a known starting model with account of oil parameters nonuniformity in radial direction was performed. With account of known experimental data, a scheme of congealed oil displacement with partial section was adopted, and a procedure for this section radius definition was offered. At that it is possible (with account of an obtained recalculation formula) to apply results of engineering calculations in compliance with an approach, which uses oil temperature averaged in cross section in each pipeline point. Prospective of using a medium flow mathematic model based on a combined rheological model of Kelvin - Voigt body and a viscoplastic Bingham model was noted.
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When developing new hydrocarbon deposits in old fields, problems related to providing operational reliability of process pipelines built using conventional steels and technologies, which were used for this climatic zone, and formerly known characteristics of recovered hydrocarbons, occur increasingly. It was found that one of the reasons of premature failure of new transport networks consists in difference between existing operational conditions and parameters laid in the design, based on which materials and technologies for oil field development were selected. These unconsidered differences were realized in pipelines from steel 09G2S as a synergistic effect, which resulted in sharp increase of corrosion and erosion damage rates for pipes themselves, various pipeline structural elements (connecting parts), as well as their weld joints. In conditions of high flow rates of gas-condensate mixture with variable density, stable turbulent motion is formed in a pipeline system, which results in rill-washing corrosion in pipes, that is increased with carbon dioxide corrosion; at that flow breakaway in metal “leak” areas in root sections of nonrotational ring erection joints or sharp change of flow motion angle in branch sleeves and elbow bends by 900 results in increase of corrosion-erosion wear, intensity of which starts depending directly on corrosion and mechanical characteristics of the base metal, weld joint areas metal, level of residual welding stresses; in single pipeline areas it could reach 3-4 mm/year. The paper shows mechanisms of corrosion-erosion failure of steel 09G2S and its weld joints, as well as it presents recommendations on performability increase for process pipelines under these operational conditions.
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On the territory of the Perm region, the most common complication of fluid extraction and transportation is the formation of wax deposits. The formation and compaction of these deposits leads to an increase in pressure in the gathering system, premature equipment failure or accidents. A strong trend of the present time is the digitalization of the oil field, which includes the creation of "digital twins" of real fields. For qualitative modeling of all technological processes, it is necessary to determine the possibility of the formation of organic deposits and their spatial and temporal distribution. Existing models of paraffin formation take into account many parameters, including flow temperature, composition and properties of oil, pressure, flow rate and others. However, a number of models do not take into account the thermal conductivity of paraffin deposits. Based on the Heat Analogy model, the authors consider the process of paraffin formation in a linear oil pipeline. For one of the sections of this pipeline, the relative thermal resistances of each element of its section are determined at different thicknesses and thermal conductivity of organic deposits. It is shown that for this oil pipeline, the formed organic deposits can become the dominant thermal resistance if they occupy 8.7 % of the pipeline. The modeling of the formation of deposits in the oil pipeline under consideration at various values of thermal conductivity was also carried out. It is shown that the correct choice of this value can significantly affect the simulation result. Thus, when the thermal conductivity of deposits changes by 0,05 W/(m∙°Ê), the change in the predicted thickness of deposits can reach 20 %. From the results obtained, we can confidently conclude that accounting and correct assessment of the thermal conductivity of organic deposits is an important task in modeling the process of their formation.
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Estimating Thermal Conductivity of Organic Deposits on the Wax Flow Loop
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