The implementation of production system tools has become extremely popular phenomenon. Most of the effectively developing companies consider this opportunity as a real tool to increase productivity, efficiency and reduce costs. In addition, among the specialists who have been engaged in the production system for a long time there is an opinion about the need for critical transformation of the standard model of the automobile conveyor to a specific type of activity. This transformation should be as deep as specific process differs from the basic model.

The article describes an example of the implementation of the principles and tools of the production system to the work of the research laboratory of VNIIneft JSC. The main elements and standard tools are considered, a critical analysis of applicability is given, and modified tools that are more applicable, in the author's opinion, to research activities are proposed. The article also provides examples of specific implemented measures that have proved their worth in practice. The form of some of them was borrowed from the practices of related units; some were implemented as part of a process of continuous improvement. It is worth noting a number of implemented projects that allowed, on the one hand, to significantly increase the value for the customer, i.e. new value chains were implemented, while they turned out to be new for the contractor, which is an innovation that is not quite typical for the practice of lean production. Nevertheless, according to the author, a radical change in the process to create additional or new value should be an indispensable part of the lean manufacturing process, especially in the field of research and development.

References

1. Taiichi Ohno, Toyota production system: Beyond large-scale production, Productivity Press, 1988, 152 p.

2. Womack J.P., Jones D.T., Lean thinking: Banish waste and create wealth in your corporation, Free Press, 2003, 188 p.

3. Rother M., Shook J., Learning to see: Value stream mapping to add value and eliminate MUDA, Lean Enterprise Institute, 2003, 102 p.

The article considered an exploration experience for Cuu Long Basin, located on the southern shelf of the Socialist Republic of Vietnam. It reviews the combining the results of forward stratigraphic modeling, seismic interpretation (such as inversion, seismic facies analysis) and subsequent exploration well drilling as implementation of decisions, which were made as a result of this integration. Authors briefly reviewed characteristics of basin sedimentation that influenced the location of clastic material source area and its transit ways. It is noted, that the results of forward stratigraphic modeling confidently confirm basic concepts about the formation of sedimentary cover and the facial zonation key trends in the target interval – from lower Oligocene to lower Miocene. Most interesting details and relations are described, that was obtained during forward stratigraphic modeling. In addition, after obtaining results of full-wavelet inversion of seismic data, it became possible to detail the facies forecast in the work area. Geological body stretching along a paleoslope, which was previously mapped from the results of forward stratigraphic model, also finds its response in a detailed facies model. In particular, a successful example of estimating for trends in the clastic transfer directions is shown. It based on the results of modeling the sedimentation process and their confirmation by independent results of seismic facies analysis. Based on the results of the estimation, an exploratory well was drilled. It confirmed the predictive models for the distribution of reservoir properties. Thus, it has been demonstrated that the used solutions for the joint use of seismic data and dynamic sedimentation modeling have good reliability of the geological forecast.

References

1. Einsele G., Sedimentary basins. Evolution, facies and sediment budget, Springer-Verlag Berlin Heidelberg, 1992, 628 р.

2. Shakhov P.A., Desyatnikova A.E., Berezovskaya E.A., Possibilities of forward stratigraphic modeling for geological tasks of different scales on the example of the Vietnam’s southern shelf (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2022, no. 1, pp. 36–39, DOI: 10.24887/0028-2448-2022-1-36-39

3. Geologicheskoe stroenie i neftegazonosnost’ shel’fovykh neftyanykh mestorozhdeniy SP “V’etsovpetro” (Geological structure and oil and gas content of the offshore oil fields of JV «Vietsovpetro»): edited by Tu Than Nghia, Veliev M. M., St. Petersburg: Nedra Publ., 2016, 524 p.

4. Kudryashov S.I., Le V’et Khay, Fam Suan Shon et al., The White Tiger field: from the history of development to development prospects (dedicated to the 40th anniversary of the Vietsovpetro joint venture) (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 6, pp. 6-14.

5. Nguyen Du Hung, Hung Van Le, Hoan Vu JOC, Hydrocarbon geology of Cuu Long Basin – Offshore Vietnam, Proceedings of AAPG International Conference, Barcelona, Spain, September 21-24, 2003, Article no. 90017.

6. Shoup R.C., Morley R.J., Swiecicki T., Clark S., Tectono-stratigraphic framework and tertiary paleogeography of Southeast Asia: Gulf of Thailand to South Vietnam Shelf,  Proceedings of AAPG International Conference and Exhibition, Singapore, September 16–19, 2012.

7. John Jong, Kessler F.-L., The South China Sea: Sub-basins, regional unconformites and uplift of the peripheral mountain ranges since the Eocene, Berita Sedimentologi. Indonesian journal of sedimentary geology, 2016, V. 35, pp. 5–54.

8. Matthews S.J., Fraser A.J., Lowe S. et al., Structure stratigraphy and petroleum geology of SE Nam Con Son Basin, offshore Vietnam, Petroleum Geology of SoutheastAsia. Geological Society, London, Special Publication, 1997, V. 126, pp. 89–106, DOI:10.1144/GSL.SP.1997.126.01.0

The search, exploration and reserves increment is one of the most important tasks in the work of each petroleum geologist. The increase in reserves can be achieved both through the discovery of new fields and through additional exploration of existing ones. The unique White Tiger field was discovered and brought into development in 1975-1986. The field is at the final stage of development. Basement is the main object from the beginning of development to this day. In the current situation, the actual task is the additional exploration of the field and the search for areas for drilling new wells and sidetracking.

In this work a detailed seismic interpretation (tracking) of the basement roof was carried out. After seismic interpretation structural constructions were completed and small structures were identified or refined – local uplifts. These local uplifts contain oil. The authors focus on the importance of detailed seismic interpretation both at the stage of putting the field into development and at the final stages of field development. Detailed seismic interpretation helps identify residual oil reserves in the final stages of field development. As a result 21 promising points for drilling new wells are identified, and estimation of oil reserves is made for the best forecasting. Recommendations for drilling five wells in the near future are given.

References

1. Pereschet zapasov nefti i rastvorennogo gaza mestorozhdeniya Belyy Tigr po sostoyaniyu na 01.01.2017 goda (Recalculation of oil and dissolved gas reserves of the White Tiger field as of 01.01.2017), Vungtau: Publ. of V’etsovpetro, 2017.

2. Geologicheskoe stroenie i neftegazonosnost’ shel’fovykh neftyanykh mestorozhdeniy SP “V’etsovpetro” (Geological structure and oil and gas content of the offshore oil fields of JV «Vietsovpetro»): edited by Tu Than Nghia, Veliev M. M., St. Petersburg: Nedra Publ., 2016, 524 p.

The presence of vugs in carbonate reservoir has strong influence on filtration processes. Porosity in this case can be low (less than 5%), but permeability can be higher than dozens of millidarcy. Common petrophysical models do not take into account vug type porosity.

For two fields two types of petrophysical models had been viewed. For the first field we used Wyllie-Rose model (relation between permeability and total porosity and irreducible water saturation). Wyllie-Rose equation coefficients had been empirically chosen to maximize fit with core analysis results. In comparison with previously used common petrophysical model, Wyllie-Rose model not only takes into account permeability of “low porosity zone” reservoir, but also better describes all core data for whole porosity interval. Wyllie-Rose model with empirically chosen coefficients was used for permeability grid construction in simulation model. For the second we choose a model with direct accounting of vug porosity (based on logging data, relation between permeability, total porosity and vug porosity). Obtained from logging data vug component of porosity was used in statical model and distributed by the same methods as total porosity. Permeability was calculated as function of two variables and exported to simulation model as initial data.

In case of common petrophysical model permeability in simulation model leads to necessity of its modification. Such simulation model has insufficient forecast ability because of local permeability modifications and high level of uncertainty in undrilled and between-well zones. Using of Wyllie-Rose model allowed to decrease permeability modifications volume and to cut down for one order of vertical conductivity multiplier median. Thus, using of Wyllie-Rose model allows to “reconstruct” wells exploitation data more accurate. On the base of this simulation model 2021-2022 years drilling results retrospective analysis was executed. Model showed high level of quality and quantity converging and was accepted for field development forecast. Geological and simulation models, based on vug porosity direct accounting model, are going to be justifying by drilling data. Simulation model fad been matched to historical data, on their basis the drilling prospects were determined.

References

1. Kolodzie Jr.S., Analysis of pore throat size and use of the Waxman-Smits equation to determine OOIP in Spindle field, Colorado, SPE-9382-MS, 1980, DOI: 10.2118/9382-MS

2. Pittman E.D., Relationship of porosity and permeability to various parameters derived from mercury injection—Capillary pressure curves for sandstone, American Association of Petroleum Geologists Bull., 1992, V. 76 (2), pp. 191–198.

3. Swanson B.F., A simple correlation between permeabilities and mercury capillary pressures, J. Pet Technol., 1981, V. 33(12), pp. 2498-2504, SPE-8234-PA, DOI: 10.2118/8234-PA

4. Lucia F.J., Kerans C., Jennings, J.W., Carbonate reservoir characterization, Journal of Petroleum Technology, 2003, V. 55(06), pp. 70–72, DOI: 10.2118/82071-JPT

5. Watfa M., Youssef F.Z., An improved technique for estimating permeability in carbonates, SPE-15732-MS, 1987, DOI: 10.2118/15732-MS.

6. Wylle M.R.J, Rose W.D., Some theoretical considerations related to the quantitative evaluation of the physical characteristics of reservoir rocks from electrical log data, J. Pet. Technol., 1950, no. 2(4), pp. 105–118, SPE-950105-G, DOI: 10.2118/950105-G

The article presents a design of water shut-off treatments to decrease the water cut in producing wells on Zapadno-Khosedayuskoye oilfield located in Central-Khoreiver Uplift. The key features of the field are relatively high oil viscosity (12-13 mPa∙s) and average formation temperature 70°С. The main producing horizon is carbonate formation D3fmIII, characterized by mixed wettability and high salinity of formation water (up to 210 kg/m3). Based on the results of field data analysis, well testing and well logging it was found that increased water cut of many wells is caused by bottom water coning, including channeling through high permeability vugular streaks. To solve the problem of water coning we evaluated compositions based on polymers and inorganic components. Thermally activated gelant compositions based on inorganic aluminum salts were selected for field trials. Gelation mechanism involves decomposition of additive component (carbamide) at reservoir temperature and formation of strong gel screen. Chemical properties of the composition were analyzed. The residual resistance factor to water (relative decline of mobility after gelation) is in range of few units (for oil-saturated heterogeneous media) to several hundreds or thousands (for high-permeability streaks). The key parameters for modeling gel screen stability and permeability to oil and water were determined. Obtained laboratory data were used to calculate the threshold pressure drop and flow regimes using analytical methods as well as linear and radial single well hydrodynamic models.

In 2019–2021 17 water shut-off workovers were performed on Zapadno-Khosedayuskoye field to isolate the inflow of bottom water from D3fmIII formation. Candidate wells were selected using the analysis of geological heterogeneity of the penetrated zones and water inflow diagnostic plots. Workovers were performed using additional perforation of the bottom zone and followed by cement plug to isolate the wellbore. Injected volume ranged from 350 to 500 m3. In most wells water cut was decreased after workover. Cumulative incremental oil production from water shut-off operations is 106 thousand tons, average incremental oil rate from workovers – 18,1 tons/day, showing prospective to use the suggested injection scheme on other oilfields with similar properties.

References

1. Blazhevich V.A., Umrikhina E.N., Umetbaev V.G., Remontno-izolyatsionnye raboty pri ekspluatatsii neftyanykh mestorozhdeniy (Repair and insulation work during oil field operation), Moscow: Nedra Publ., 1981, 232 p.

2. Zemtsov Yu.V., Razvitie i sovershenstvovanie remontno-izolyatsionnykh rabot na mestorozhdeniyakh Zapadnoy Sibiri (Development and improvement of repair and insulation works in Western Siberia), St. Peterburg: Nedra Publ., 2014, 320 p.

3. Kabir H., Chemical water & gas shutoff technology – An overview, SPE-72119-MS, 2001, DOI: 10.2118/72119-MS

4. Baykova E.N., Muslimov R.Kh., Experience in the application of water shut-off and remedial cementing technologies in fractured carbonate reservoirs (In Russ.), Georesursy = Georesources, 2016, V. 8, no.3, Part 1, pp. 175-185, DOI: 10.18599/grs.18.3.6

5. Yudin E.V., Bagmanov R.D., Khairullin M.M. et al., Development of approach to modelling complex structure carbonate reservoirs using example of the central Khoreyver Uplift fields, SPE-187811-MS, 2017, DOI: 10.2118/187811-MS

6. Fedorov K.M., Pecherin T.N., Comparative effectiveness of techniques of production water cut causes diagnostics (In Russ.), Izvestiya vuzov. Neft’ i gaz, 2009, no. 4, pp. 49–58.

7. Yortsos Y.C., Choi Y., Shah P.C., Analysis and interpretation of the water-oil ratio in waterfloods, SPE-38869-MS, 1997, DOI: 10.2118/38869-MS

8. Vasquez J., Curtice R., A shallow-penetration polymer sealant for water and gas control: Case histories and lessons learned after more than 250 well interventions, SPE-174276-MS, 2015, DOI: 10.2118/174276-MS

9. Lakatos I., Szentes G., Toro M. et al., Mitigation of formation damage caused by chemical overdosing in water shut-off treatments, SPE-199292-MS, 2020, DOI: 10.2118/199292-MS

10. Portwood J.T., The Kansas Arbuckle formation: Performance evaluation and lessons learned from more than 200 polymer-gel water-shutoff treatments, SPE-94096-MS, 2005, DOI: 10.2118/94096-MS

11. Al-Azmi N., Al-Sabea S., Abdullah A.-E. et al., Water shutoff and zonal isolation for high permeability depleted reservoir using organically crosslinked polymer sealant system, SPE-201577-MS, 2020, DOI: 10.2118/201577-MS

12. Al-Azmi A.A., Al-Yaqout T.A., Al-Jutaili D.Y. et al., Application of specially designed polymers in high water cut wells- A holistic well-intervention technology applied in Umm Gudair field, Kuwait, SPE-200957-MS, 2021, DOI: 10.2118/200957-MS

13. Altunina L.K., Kuvshinov V.A., Kuvshinov I.V., Gels, sols and surfactant compounds applied for enhanced oil recovery at the late stage of development (In Russ.), Georesursy, 2014, no. 4(59), pp. 20–27.

14. Makarshin S.V., Rogova T.S., Egorov Yu.A. et al., Assessment of opportunities for the use of gels based on aluminum salts for regulating filtration flows in carbonate reservoirs (In Russ.), Proceedings of VNIIneft, 2016, V. 155, pp. 22–36.

15. Mullagalin I.Z., Strizhnev V.A., Khamitov A.T. et al., Approaches to solving the efficiency enhancement problems while remedial cementing (In Russ.), Neftepromyslovoe delo, 2016, no. 12, pp. 31–37.

Since 2015, Zarubezhneft JSC has been testing the steam-thermal effect on carbonate reservoir M saturated with native bitumen at the pilot area of Boca de Jaruco field (Republic of Cuba). Oil of deposit M is one of the heaviest in the world: viscosity in reservoir conditions is 36000 mPa·s, density is 1021.7 kg/m3. The reservoir rock is a fractured-porous carbonate with a dense fractures system. At the first stage of formation M development (2015-2019), the production was provided by vertical wells. During this time, commercial oil inflows were obtained: oil flow rates was up to 50 t/day, steam-oil ratio (SOR) reduced to 5 t/t during the best cycle. In 2020-2021 four horizontal wells were drilled as part of the second stage of pilot work. Horizontal wells are more efficient than vertical wells, primarily due to involved bituminous rocks volume increase. To implement this sweep, larger volumes of steam injection are required. Early 2021, due to the negative results of the first steam cycling stimulation (SCS) on horizontal wells, a decision was made to change the operation strategy. The new strategy was based on the principle of gradually increasing injection from smaller volumes to larger volumes (mini-SCS strategy). Since 2021 to present the achieved results of the pilot project confirmed the feasibility of choosing the mini-SCS strategy. From the first mini-cycles to the present, there has been a decrease in SOR for all horizontal wells; a record value of 4 t/t in the cycle has been reached. Based on the results obtained, an assessment of the prospects for horizontal wells during the period of business planning was implemented. Taking into account the presence of a dense system of fractures and small distances between wells (30-100 m), special attention is paid for monitoring and control of wells.

References

1. Afanasev I.S., Yudin E.V., Azimov T.A. et al., Technology for the thermal treatment of the productive formations of the Boca de Jaruco field: Challenges, opportunities, prospects (In Russ.), SPE 176699-RU, 2015, DOI: 10.2118/176699-MS

2. Osipov A.V., Esaulov A.O., Ibragimova M.V., Terentiev V.L., Petrashov O.V., Azimov T.A., The results of pilot steam stimulations of heavy oil saturated fractured carbonate reservoir, Boca de Haruko field (In Russ.), Нефтяное хозяйство = Oil Industry, 2018, no. 9, pp. 58–61, DOI: 10.24887/0028-2448-2018-9-58-61

3.  Yudin E.V., Petrashov O.V., Osipov A.V.,  Results of pilot work on extraction of natural bitumens from oil-wet fractured carbonate rocks: Boca de Jaruco field case (In Russ.), SPE-187683-RU, 2017, DOI:10.2118/187683-MS

4. Jiang Q., Yuan J., Russel-Houston J. et al., Evaluation of recovery technologies for the Grosmont carbonate reservoirs, Journal of Canadian Petroleum Technology, 2010, V. 49(05), DOI:10.2118/2009-067

5. Annual Presentation Saleski Thermal Pilot AER Approval 11337, LARICINA ENERGY LTD., 2014

6. Norkina A., Simakov I., Petrashov O., Solovev A., Geomechanical approach in classification of borehole failures in fractured carbonates of Boca de Jaruco field, SPE-208065-MS, 2021, DOI:10.2118/208065-MS

The authors provide a process to evaluate and plan the injection of low salinity water to enhance oil recovery on Central-Khoreiver Uplift (CKU) fields with relatively high oil viscosity (6-7 mPa∙s). Use of chemicals for oil displacement in such conditions is complicated due to high formation water salinity (up to 210 kg/m3)and high formation temperature (70 °С).

Several scenarios are described for application of low salinity or engineered salinity water to improve oil recovery from carbonate formations, but there is no established and integrated mechanism to characterize the mechanism of oil mobilization. As a result of coreflooding experiments on cores from CKU producing formations it is shown that incremental oil recovery from injection of low salinity water ranges from 1 to 10% in comparison with formation water. Linear hydrodynamic models were tuned to laboratory data, and then sector models were built to predict the technological efficiency. Joint application of low salinity water and polymeric chemicals was evaluated, coreflooding experiments were used to find the incremental recovery factors due to combined use of polymer and water with different salinity. It was shown that joint use of polymers and low salinity water can yield an increased oil recovery up to 15% in zones fully swept by injected agent.

In December 2020 the low salinity water injection pilot was started on Visovoye oilfield. Low salinity water (8-9 kg/m3) from the Jurassic horizon replaced treated produced water (180-210 kg/m3). During the long-term injection salinity of produced water in some wells dropped by 20-40%, it allowed to evaluate the swept zones of the formation and improve the forecasting ability of hydrodynamic model. The expected technological efficiency of low salinity water injection on Visovoye field involves the improvement of recovery factor by 1% (to 2033). Potential combined injection of mobility control agent (polymer) and low salinity water can lead to incremental oil recovery from 22 to 44 tons of oil per 1 ton of polymer injected.

References

1. Kornilov A., Zhirov A., Petrakov A. et al., Selection of effective surfactant composition to improve oil displacement efficiency in carbonate reservoirs with high salinity formation water, SPE-196772-MS, 2019, DOI: 10.2118/196772-MS

2. Kruglov D.S., Smirnov A.E., Tkachev I.V. et al., Design of pilot test to evaluating the efficiency of surfactant-polymer flooding in field conditions using single well chemical tracer test (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 12, pp. 102–106, DOI: 10.24887/0028-2448-2021-12-102-106

3. Fathi S.J., Austad T., Strand S., Water-based enhanced oil recovery (EOR) by “Smart Water” in carbonate reservoirs, SPE-154570-MS, 2012, DOI: 10.2118/154570-MS

4. Fathi S.J., Austad T., Strand S., Water-based enhanced oil recovery (EOR) by «Smart Water»: Optimal ionic composition for EOR in carbonates, Energy & Fuels, 2011, V. 25(11), pp. 5173-5179, DOI: 10.1021/ef201019k

5. Zhang P., Austad T., Wettability and oil recovery from carbonates: Effects of temperature and potential determining ions, Colloids and Surfaces A: Physicochem. Eng. Aspects, 2006, V. 279, pp. 179-187, DOI: 10.1016/j.colsurfa.2006.01.009

6. Shariatpanahi S.F., Strand S., Austad T., Evaluation of water-based enhanced oil recovery (EOR) by wettability alteration in a low-permeable fractured limestone oil reservoir, Energy & Fuels, 2010, V. 24(11), pp. 5997–6008, DOI: 10.1021/ef100837v

7. Yousef A.A., Liu J.S., Blanchard G.W. et al., Smart waterflooding: Industry’s first field test in carbonate reservoirs, SPE-159526-MS, 2012, DOI: 10.2118/159526-MS

8. Keller Yu.A., Uskov A.A., Krivoguz A.N. et al., The application of SWCTT for evaluating the efficiency of low-salinity water flooding at the carbonate reservoir of the Kharyaginskoye oil field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2020, no. 7, pp. 109-113, DOI: 10.24887/0028-2448-2020-7-109-113

9. Chorniy A., Khodakov I., Popov D. et al., Practical application of flow diversion techniques for development of fractured carbonate reservoirs, SPE-196855-MS, 2019, DOI: 10.2118/196855-MS

10. Kornilov A.V., Tkachev I.V., Fomkin A.V. et al., Injection of low-salinity water as an integral part of enhanced oil recovery programmes for carbonate formations of the Central-Khoreiver Uplift oilfields, SPE-206433-MS, 2021, DOI: 10.2118/206433-MS

11. Shakeel M., Pourafshary P., Hashmet M.R., Hybrid engineered water-polymer flooding in carbonates: A review of mechanisms and case studies, App. Sci., 2020, no. 10 (6087), DOI: 10.3390/app10176087

The displacement efficiency and oil displacement profile are important parameters that determine the oil recovery efficiency. In accordance with the industry standard, these parameters are measured via flow experiments to displace oil with water or other injected agents (surfactants, polymers, micro-emulsions, etc.) from a porous medium model. During the experiment, flow products are sampled at predetermined time intervals, while the oil volume in the samples is measured visually. At the end of the flow experiment, the water saturation is measured in a Dean Stark / Soxhlet apparatus which allows to calculate the final displacement efficiency. Field experience shows that in the case of light oils displacement, the results of visual (volumetric) and estimated (according to the Dean Stark / Soxhlet apparatus) displacement efficiency determination methods demonstrate high match. However, in the study of heavy viscous oils capable of forming stable emulsions with water, the visual displacement efficiency determination may be accompanied by errors exceeding the measured value. Such significant errors in oil measurement in the samples lead to the impossibility of accurately determining the relative oil recovery profile during the experiment, especially in the case of sequential oil displacement by various injected agents. To eliminate this problem, a simple and accurate method for measuring oil in flow products is proposed. The method is based on the volumetric additivity rule for oil solutions density in chloroform. This method does not require any expensive equipment and can be performed in a conventional oil laboratory equipped with analytical scales and an electronic density meter. The authors describes in detail the experimental features of the method and its main metrological characteristics that meet the criteria of linearity, correctness, and intra-laboratory precision when measuring both heavy and light oil in the presence of reservoir water of a wide range of salinities. The described method has been successfully tested to determine the oil recovery profile in six flow experiments, showing high match of the results with the displacement efficiency estimated according to the Dean Stark / Soxhlet data.

References

1. VNIIneft enterprise standard. Neft’. Metod opredeleniya koeffitsienta vytesneniya nefti vodoy v laboratornykh usloviyakh (Oil. The method of determining the coefficient of oil displacement by water in the laboratory), Moscow: Publ. of VNIIneft’, 2017, 26 p.

2. Katika K., Ahkami M., Fosbol P.L. et al., Comparative analysis of experimental methods for quantification of small amounts of oil in water, J. Petrol. Sci., 2016, V. 147, pp. 459–467, DOI: 10.1016/j.petrol.2016.09.009

3. Rendel P.M., Mohammadkhani S., Jensen A.E., Feilberg K.L., An innovative method for the quantification of small amounts of crude oil in water using a multi-wavelength separation analyzer, J. Petrol. Sci. Eng., 2021, V. 200, DOI: 10.1016/j.petrol.2021.108388

4. Metrologicheskie osnovy analiticheskoy khimii (Metrological foundations of analytical chemistry): edited by Shekhovtsova T.N., Garmash A.V., Sorokin N.M., Moscow: Publ. of MSU, 2017, 51 p.

There is a lot of laboratory and field experiments confirmed the effectiveness of gas methods for enhanced oil recovery (EOR). However, a wide range of reservoir conditions, characteristics and properties of produced and injected fluids, injection technologies, along with a wide variety of research methods, leads to difficulties to compare the results obtained by different authors for different fields.

The article discusses topical issue to improve the methodology of filtration experiments on oil by gas displacement using slim-tube models of the reservoir. The geometric parameters of the models, fluid filtration rates, and other characteristics of the experiments affecting the result vary in studies performed by different authors. The authors compared some methods to determine the possibility and correctness of comparing the results. The key features of experimental determination the minimum oil-gas miscibility pressure and the selection of the optimal gas composition under given thermobaric conditions are detected, and the order of their implementation is optimized. It is noted, the special attention should be paid to the sampling of heavy oil and its stability while mixing with the injection gas. The stability of oil displacement process is an important condition of filtration experiments at high filtration rates, i.e. removing of gravitational and viscous influence by using slim tube with a length more than 12 m. Increase of the slim tube length reduces the experimental error due to an increase in the volume of fluids. Two approaches are considered – oil displacing from short slim-pipe model (6 m long) with reservoir filtration rates and displacement with increased rates from the slim tube of increased length (18 m). The reproducibility of the final results of the displacement is shown, which indicates the achievement of the stability of the oil displacement process in both cases.

References

1. Perkins T.K., Johnston O.C., A review of diffusion and dispersion in porous media, Society of Petroleum Engineers Journal, 1963, V. 3(01), pp. 70-84, DOI:10.2118/480-PA

2. Ashoori S., Sharifi M., Masoumi M., Salehi M.M., The relationship between SARA fractions and crude oil stability, Egypt. J. Pet., 2016, V. 26, pp. 209−213, DOI:10.1016/j.ejpe.2016.04.002

3. Ekundayo J.M., Ghedan S.G., Minimum miscibility pressure measurement with Slim tube apparatus – how unique is the value, SPE-165966-MS, 2013, DOI:10.2118/165966-MS

4. Flock D.L., Nouar A., Parametric analysis on the determination of the minimum miscibility pressure in slim tube displacements, Journal of Canadian petroleum technology, 1984, V. 23, pp. 80–88, DOI:10.2118/84-05-12

5. Patent no. RU 209988 U1, Sistema dlya opredeleniya svoystv perekhodnoy zony pri smeshivayushchemsya vytesnenii nefti gazom (System for determination of transition zone properties in miscible oil-gas displacement), Inventors: Egorov Yu.A., Petrakov A.M.

Prospects of chemical methods of enhanced oil recovery are currently due to both the deterioration of mature oil fields reserves and chemical industry development, which is able to provide solutions to urgent problems of the oil and gas companies. The initial selection of compositions for enhanced oil recovery includes experiments to assess the physicochemical properties: viscosity, interfacial tension, etc. These parameters are determined under conditions close to reservoir ones. At the next stage of the laboratory selection of the chemical composition, coreflooding experiments are carried out to assess the effectiveness of oil displacement by the selected chemical composition. These experiments can be carried out on model analog cores, as well as on single cores or composite core columns of samples taken from the target reservoir. As a result, the nature of the interaction of the selected composition with oil and rock in conditions close to reservoir ones is determined. The results of coreflooding experiments (increase in displacement efficiency, pressure gradients during flooding) are the basis for making decisions on the further implementation of regarded technology at the field. It should also be noted that these experiments have a high degree of uncertainty due to the complex processes occurring in the pore medium during flooding of chemicals. There are also a number of parameters that cannot be measured during the experiment, but these parameters affect the efficiency of oil displacement by chemicals.

The article considers the features of creating and matching linear models of coreflooding experiments conducted to assess the technological effectiveness of surfactant-polymer flooding. The purpose of constructing a linear model of the coreflooding experiment is to increase the accuracy of predicting the effectiveness of the selected technology by reducing the degree of uncertainty in interpreting the results of the coreflooding experiment. Uncertainty reduction is achieved by reproducing main parameters of the experiment in a linear simulation model. These parameters are adjusted on a linear model by matching the calculated parameters to the actual experimental data. The properties of chemicals estimated on the adapted linear model are used in further to predict the effect of the technology.

References

1. Trushin Y.M., Aleshchenko A.S., Zoshchenko O.N. et al., Planning of pilot injection of surfactant-polymer composition to improve oil recovery from carbonate reservoir of Kharyaga oilfield and evaluation of the results, SPE-206420-MS, 2021, DOI: https://doi.org/10.2118/206420-MS.

2. Kruglov D.S., Smirnov A.E., Tkachev I.V. et al., Design of pilot test to evaluating the efficiency of surfactant-polymer flooding in field conditions using single well chemical tracer test (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 12, pp. 102-106, DOI: 10.24887/0028-2448-2021-12-102-106

3. Hu Guo, Ma Dou, Wang Hanqing, Review of capillary number in chemical enhanced oil recovery, SPE-175172-MS, 2015, DOI: https://doi.org/10.2118/175172-MS.

4. Petrakov A.M., Rogova T.S., Makarshin S.V. et al., Selection of surfactant-polymer technology for enhanced oil recovery project in carbonate formations of Central-Khoreiver uplift (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2020, no. 1, pp. 66-70, DOI: 10.24887/0028-2448-2020-1-66-70

5. Kornilov A., Zhirov A., Petrakov A. et al., Selection of effective surfactant composition to improve oil displacement efficiency in carbonate reservoirs with high salinity formation water, SPE-196772-MS, 2019, DOI: https://doi.org/10.2118/196772-MS.

6. Limousin G., Gaudet J.P., Charlet L. et al., Sorption isotherms: a review on physical bases, modeling and measurement, Applied Geochemistry, 2006, no. 22(2), pp. 249–275, DOI: https://doi.org/10.1016/j.apgeochem.2006.09.010

Software robotization in Zarubezhneft Group of Companies is actively implementing starting from 2020 as part of the digital transformation. To solve the problems of increasing operational efficiency Zarubezhneft JSC formed two competence centers for software robotization: at VNIIneft JSC (for robotization of production processes) and at Nestro LLC (for robotization of accounting processes). At the first stage in 2020-2021 a platform Robin for creating software robots was chosen. The capabilities of software robotization were successfully tested on pilot production processes of the corporate center of Zarubezhneft JSC with the involvement of the VNIIneft Competence Center. At the second stage in 2021-2022 robotization of 10 processes for the corporate center was completed with a total labor cost saving of 235 man-hours per month. In addition, the Competence Center robotized 8 accounting processes within the perimeter of VNIIneft JSC, with a total labor cost saving of 104 man-hours per month. It is expected that employees will be able to use the freed up time to solve creative, rather than routine tasks. The payback period for the development of one robot is up to 6 months. At the moment, the transition to the third stage is being carried out with the replication of the experience of software robotization in the subsidiaries of Zarubezhneft JSC. As part of the third stage, VNIIneft JSC is developing a software infrastructure that allows to create and control the operation of software robots using Open Source technologies. This approach will allow to get away from using a licensed platform and to made more flexible the functionality of the developed robots, not being limited to a fixed set of tools of the existing platform. This infrastructure will allow integrating previously developed software robots on Robin. Thus, the implementation of the software robotization system in the Zarubezhneft Group of Companies makes it possible to significantly reduce the cost of information processing, increase productivity and quality in robotic processes.

Since 2019, the Zarubezhneft Group of Companies has been actively developing the direction of digital transformation. The tasks of digital transformation are solved through the use of innovative technologies and solutions in the areas of activity, including through the implementation of the Digital Field concept.

As part of the this concept, a digital ecosystem is being formed with the implementation of the principles of unification of the software used, their centralization and the creation of software lines by business segments. One of the first software products developed on the software infrastructure of VNIIneft JSC using machine learning methods and big data analysis is a virtual flow meter for Vietsovpetro JV. As part of the virtual flowmeter project, an algorithm for working with Big Data has been developed, which makes it possible to increase the responsiveness to changes in fluid flow rates and reduce their losses due to operational monitoring of data "from the wellhead". Machine learning models are considered as the basis of the algorithm. Data were collected and analyzed for the Vietsovpetro JV field, and a review was made on machine learning approaches and techniques, big data processing and model generation using the Python programming language libraries. A mechanism for automating the collection and filtering of initial data has been developed. Various types of machine learning models were tested to solve the regression problem. The software infrastructure has been improved for automatic additional training of virtual flow meter models upon receipt of new data. The uniqueness of the proposed approach lies in the fact that the wellhead parameters are only a part of the influencing indicators on the desired fluid flow rate, in addition to this, reservoir indicators, which are not promptly measured, are used. The liquid flow rate prediction error of the virtual flow meter prototype does not exceed 10 m3/day, which is sufficient to solve the tasks set for prompt response to flow rate changes at the wells of Vietsovpetro JV. Thus, the implementation of the Digital Field concept in the Zarubezhneft Group of Companies allows increasing the speed of information processing, improving the quality of planning and increasing the economic efficiency of field development.

References

1. Heddle R., Foot J., Rees H., ISIS Rate&Phase: Delivering virtual flow metering for 300 wells in 20 fields, SPE-150153-MS, 2012, DOI:10.2118/150153-MS

2. Gobel D., Briers J., Yee Men Chin, Architecture and Implementation of an Optimization Decision Support System, Proceedings of International Petroleum Technology Conference, Beijing, China, March 2013, DOI:10.2523/IPTC-17009-MS

The article provides brief information on the prospects and features of clarifying the geological structure of the deposits of the Tyumen formation in one of the areas of the Frolov oil and gas region of Western Siberia. The essential initial data for the complex analysis are the materials of 3D seismic surveys, core analysis and well logging. A significant development of disjunctive tectonics was noted for the studied territory, especially on the local arches of structures, which is associated with the activation of tectonic processes in the Jurassic and Cretaceous time. Zones of rock destruction associated with local protrusions of the Pre-Jurassic base have been identified on seismic sections. The predominant transverse size of the identified destruction zones is 150-250 m. The areas of core sampling with signs of fracturing coincide with the position of the selected zones of destruction of rocks. On the basis of a comprehensive analysis, an idea of the models of the formation of hydrocarbon deposits in the area is compiled, the main patterns of the placement of oil-producing sites are proposed, directions for further refinement of the geological structure of the territory and its oil-bearing prospects are determined. The prospects of the Pre-Jurassic foundation are traditionally associated with areas of rock decompression characterized by reduced values of amplitudes and acoustic stiffness, the nature of which is tectonic activity at the site. Productive objects of the upper part of the deposits of the Tyumen formation are characterized by high lithological heterogeneity both in section and laterally, have low filtration and capacitance properties. The main prospects are related to the search for traps and deposits of lithological type, confined to the desalinated zones of the meander belt. Productive strata are an extensive network of channels that can be promising for the detection of reservoirs with relatively high filtration and capacitance properties. It is concluded that it is necessary to use a paleogeodynamic approach when interpreting the results of a comprehensive analysis of seismic data, drilling, core studies and well testing.

References

1. Valyaev B.M., Astaf'ev D.A., Kuzin A.M. et al., Global and regional unevenness of the formation and distribution of the resources and fields of the hydrocarbons and the mechanics of the processes of the oil and gas accumulations (In Russ.), Georesursy. Geoenergetika. Geopolitika, 2012, no. 2(6), URL: http://oilgasjournal.ru/vol_6/valyaev.html

2. Muslimov R.Kh., Trofimov V.A., Plotnikova I.N. et al., Rol' glubinnoy degazatsii Zemli i kristallicheskogo fundamenta v formirovanii i estestvennom vospolnenii zapasov neftyanykh i gazovykh mestorozhdeniy (The role of deep degassing of the Earth and the crystalline basement in the formation and natural replenishment of oil and gas fields), Kazan: FEN Publ., 2019, 264 p.

3. Bembel' S.R., Manifestation features of present local geodynamics in the western part of KhMAO-Yugra, their relation with zones of oil and gas accumulation (In Russ.), Geologiya nefti i gaza, 2010, no. 4, pp. 8–12.

4. Bembel' R.M., Bembel' S.R., Geologicheskie modeli i osnovy razvedki i razrabotki mestorozhdeniy nefti i gaza Zapadnoy Sibiri (Geological models and fundamentals of exploration and development of oil and gas fields in Western Siberia), Tyumen: Publ. of TIU, 2022, 220 p.

5. Bembel' S.R., Bembel' R.M., Avershin R.V., Kornev V.A., Prospects for the allocation of productive sites in Jurassic sediments in the areas of the Frolovskaya oil and gas bearing region (In Russ.), Izvestiya vuzov. Neft' i gaz, 2018, no. 4, pp. 7–14, DOI: 10.31660/0445-0108-2018-4-7-14

6. Bembel' S.R., Bembel' R.M., Rogozhneva V.O., Definition of the geological structure of deposits of Tyumen suite based on the results of tectonic-sedimentary analysis of the eastern part of the Krasnoleninsky arch of Western Siberia (In Russ.), Izvestiya vuzov. Neft' i gaz, 2022, no. 6, pp. 9–25, DOI: 10.31660/0445-0108-2022-6-9-25

7. Bembel' S.R., Presentation on fractal hydrocarbon deposits as a method of increasing the effectiveness of the methods of study (In Russ.), Kazanskaya nauka, 2011, no.2, pp. 276–278.

8. Bembel' S.R., Particularities of the fractality of hydrocarbons reservoirs and the problem of mapping (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2012, no. 4, pp. 19–20.

The article presents the domestically manufactured advanced pulse neutron gamma-ray spectral logging appliance (АINK-PL), the potential capacity of it for geology and the results of pilot field trials. The described appliance is a product of Agreement for cooperation between Rosneft Oil Company and State Atomic Energy Corporation Rosatom (Dukhov Automatics Research Institute). It appears to be a real breakthrough in the area of hi-tech well logging since АINK-PL is not only comparable to the most recent foreign developments, but does predominate in terms of engineering design. Dual-spacing and sophisticated gamma-ray detector based on lanthanum bromide (LaBr3) provides АINK-PL with high logging quality, speed and level of details. On top of that, the advanced engineering solutions allow extra data recording (hydrogen content, thermal-neutron capture cross-section, organic carbon, spectral gamma-logging) and under the cased hole condition make it possible to replace completely a basic logging unit with АINK-PL. As of the current date the results of pilot field trials have demonstrated substantiation of the given technology in almost every Russian major oil and gas province (Volga-Urals, Western Siberia, Eastern Siberia), both for terrigenous and carbonate deposits of complicated mineral composition. Results of АINK-PL pilot field trials guarantee high level of process safety for the Rosneft assets and for the domestic well survey service as a whole by total allocation of hi-tech instrumentation manufacturing within the Russian Federation. The planned extensive implementation of the presented appliance within the Rosneft Oil Company will provide substantial decrease of well logging operating costs and increase the oil and gas production efficiency.

References

1. Rakaev I.M., Gadel'shin E.V., Khanafin I.A. et al., Developing market of domestic hi-tech well survey appliances (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2022, no. 12, pp. 78-82, DOI: 10.24887/0028-2448-2022-12-78-82.

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

3. Basyrov M.A., Mitrofanov D.A., Makhmutov I.R. et al., The development of the technique for measuring mass fractions of chemical elements using AINK-PL logs (In Russ.), Karotazhnik, 2021, no. 8(314), pp. 121–130.

4. Zverev V.I., Khomyakov A.S., Novyy pribor impul'snogo neytronnogo gamma-spektrometricheskogo karotazha dlya opredeleniya elementnogo sostava gornykh porod (A new device for pulsed neutron gamma spectrometric logging for determining the elemental composition of rocks), Collected papers “Uglevodorodnyy potentsial Dal'nego Vostoka” (Hydrocarbon potential of the Far East), Proceedings of 6th scientific and practical seminar, Moscow, 2021, p. 5.

5. Kopylov S.I., Kosov M.V., Kuratov S.E. et al., An experience in an alternative simulation of pulse-neutron spectral-gamma logging tool (INGK-89S-2) logs (In Russ.), Karotazhnik, 2022, no. 3(317), pp. 59–69.

The article deals with an actual problem of horizontal drilling- the presence of gaps from the LWD and WLL offset points. There is a high probability of overpassing the target interval while drilling horizontal wells, and as a result, a decrease in production rate. In these cases, the importance of gas logging increases. Gas logging is a set of studies designed to analyze the gas that is formed while drilling. The method is based on determination of volume and composition of gases in the drilling fluid coming to the surface from the well. It is a direct method; unlike other types of logging that solve the problem of identifying pay zones in the well section and their saturation. The results of gas logging while drilling provide information about reservoir saturation.

To date, there are several basic methods for analyzing the composition of a gas-air mixture that allow tracking the change in the reservoir saturation by the proportion of heavy and light hydrocarbons in the analyzed gas-air mixture. This makes it possible to determine the phase composition of hydrocarbons contained in the reservoir, as well as to identify interfluid contacts (gas-oil and water-oil).

This article is focused on the modern experience of using gas logging as an additional source of information for geosteering in complex geological and technological drilling conditions. Examples of operational determination of formation exposing and finding GOC according to gas logging data are considered.

Thus, it is shown that gas logging is a relevant method of well exploration, which allows reducing uncertainty in horizontal wells.

References

1. Martynov V.G., Geofizicheskie issledovaniya skvazhin (Well logging), Moscow: Infra-inzheneriya Publ., 2009, 960 p.

2. Luk'yanov E.E., Issledovaniya skvazhin v protsesse bureniya (Well surveys while drilling), Moscow: Nedra Publ., 1977, 248 p.

3. Pomerants L.I., Gazovyy karotazh (Gas logging), Moscow: Nedra Publ., 1982, 240 p.

4. Tarasova E.V., Quick evaluation of rock saturation by mud log (In Russ.), Karotazhnik, 2011, no. 10(208), pp. 10–22.

5. Luk'yanov E.E., Interpretatsiya dannykh GTI (Interpretation of mud logging data), Novosibirsk: Istoricheskoe nasledie Sibiri Publ., 2011, 944 p.

6. Haworth J.H., Sellens M., Whittaker A., Interpretation of hydrocarbon shows using light (C1–C5) hydrocarbon gases from mud-log data, The American Association of Petroleum Geologists Bulletin, 1985, V. 69, no. 8, pp. 1305–1310, DOI:10.1306/AD462BDC-16F7-11D7-8645000102C1865D

7. Pixler B.O., Formation evolution by analysis of hydrocarbon ratios, SPE-2254-PA, 1969, DOI:10.2118/2254-PA

8. Starosel'skiy V.I., Etan, propan, butan v prirodnykh gazakh neftegazonosnykh basseynov (Ethane, propane, butane in natural gases of oil and gas basins), Moscow: Nedra Publ., 1990, 186 p.

The presented article is devoted to the creation and testing of an ensemble probabilistic computational tool for operational forecasting of well flow in the short term. The ensemble includes models based on such physical and mathematical devices as: the equation of non-stationary filtration, material balance, Darcy's law and machine learning models. After making calculations by each model, their forecasts are combined into a single ensemble forecast. Each model makes a forecast based on historical information about the production and injection wells. The approach is based on the Monte Carlo method on Markov chains in the form of a separate probabilistic model using the Bayes formula. At the same time, the statistical weights of each model (the degree of confidence in each model) are determined in the form of a probability distribution based on the reliability of the retrospective component of the forecasts. The test results presented in this article were obtained on the basis of real field data of the deposit. Despite the shortcomings in the ensemble approach, the analysis of the tool use on real data showed that the proposed approach has a smaller average error on the forecast and a much smaller variance than each ensemble model separately. Forecasts were made for a short period of 30 to 90 days. Discretization of calculations in time was 1 day. The average value modulo the relative error for individual wells for the ensemble was 2.8% for liquid and 5.1% for oil, while the classical method of forecasting by the rate of decline gave an error of 24.5% and 24.3%, respectively.

References

1. Lake L.W., Petroleum engineering handbook. Volume I, Society of Petroleum Engineers, 2014.

2. Friedman J. et al., Regularization paths for generalized linear models via coordinate descent, Journal of Statistical Software, 2010, V. 33, DOI:10.1163/ej.9789004178922.i-328.7

3. Kim Seung-Jean et al., An interior-point method for large-scale L1-regularized least squares, IEEE Journal of selected topics in signal processing, 2007, V. 1, no. 4, DOI: 10.1109/JSTSP.2007.910971

4. Chen T., Guestrin C., XGBoost: A scalable tree boosting system, Proceedings of the 22nd ACM SIGKDD International Conference on Knowledge Discovery and Data Mining, 2016, pp. 785–794, DOI:10.1145/2939672.2939785

5. Gabitova S.I., Davletbakova L.A., Klimov V.Yu. et al., A new method of decline curve forecasting for project wells on the base of machine learning algorithms (In Russ.), PRONEFT''. Professional'no o nefti, 2020, no. 4, pp. 69-74, DOI: 10.7868/S2587739920040102

6. Ranganathan A., The Levenberg-Marquardt algorithm, 2004.

7. Yousef A.A., Gentil P.H., Jensen J.L., Lake L.W., A capacitance model to infer interwell connectivity from production and injection rate fluctuations, SPE-95322-MS, 2006, DOI: 10.2118/95322-PA

8. Holanda R.W. et al., A state-of-the-art literature review on capacitance resistance models for reservoir characterization and performance forecasting, Energies, 2018, V. 11, no. 12, DOI: 10.3390/en11123368

9. Osvaldo M., Bayesian analysis with Python, Packt Publishing, 2018, 282 p.

Oil companies are now focusing more and more on the development of tight reservoirs, partly due to the depletion of oil reserves in traditional reservoirs. An example is the transition of development to low-permeability formations (less than 10-3 mkm2) at the N field in Western Siberia. The efficiency of the development of low-permeability reservoirs of an oil field is related to the efficiency of maintaining reservoir pressure provided by the injection of water from different sources and, accordingly, different quality. It is well known that the presence of total suspended solids (TSS) in the injected water, the processes of interaction of water with the reservoir rock and the compatibility of water with reservoir water are negative factors affecting the efficiency of water injection into the reservoir. The article considers the results of filtration tests with different content of TSS in water. Analysis of the results showed the ambiguity of the ongoing processes in the pore medium, possibly associated with the strength of the framework and the structure of the pore space, with the mineral composition of the rock, with the processes of particle association. The analysis showed that the porous medium is clogged not only by the introduced TSS, but also by rock particles that are formed as a result of the interaction of water and rock. In this regard, for the effective development of low-permeability formations, it is proposed to control the level of TSS and their size to a level that ensures their free passage in a porous medium. In addition, it is shown that measures to restore the injectivity of injection wells using acidic compositions should take into account the properties and composition of minerals in the bottomhole zone of wells and TSS.

References

11. Civan F., Near-wellbore formation damage by inorganic and organic precipitates deposition, In: Reservoir Formation Damage, 2016, pp. 819-842, DOI: https://doi.org/10.1016/b978-0-12-801898-9.00024-2

2. Chepkasova E.V., Ivanov M.G., Technological efficiency evaluation applying water like as displacement agent in low permeable formation (In Russ.), Territoriya NEFTEGAZ, 2016, no. 2, pp. 82-86.

3. Tronov V.P., Tronov A.V., Ochistka vod razlichnykh tipov dlya ispol'zovaniya v sisteme PPD (Purification of various types of water for use in the reservoir pressure maintenance system), Kazan: Fen Publ., 2001, 560 p.

4. Boronin S., Tolmacheva K., Osiptsov A. et al., Modelling of injection well capacity with account for permeability damage in the near wellbore zone for oilfelds in Western Siberia (In Russ.), SPE-187806-RU, 2017, DOI:10.2118/187806-RU

5. Borisov G.K., Ishmiyarov E.R., Polyakov M.E. et al., Physical modeling of colmatation processes in the near-well bottom zone of Sredne-Botuobinsky field. Part 1. Physical modeling of colmatation processes in the near-well bottom zone of Sredne-Botuobinsky field (In Russ.), Neftepromyslovoe delo, 2018, no. 11, pp. 73–80, DOI: doi.org/10.30713/0207-2351-2018-11-73-80

6. Kim C., Lee J., Experimental study on the variation of relative permeability due to clay minerals in low salinity water-flooding, J. Pet. Sci. Eng., 2017, V. 151, pp. 292–304, DOI: doi.org/10.1016/j.petrol.2017.01.014

7. Voloshina A.A., Kotenev Yu.A., Physical modeling of pore space clogging in porous medium of low-permeable reservoir (In Russ.), Neft'. Gaz. Novatsii, 2021, no. 9(250), pp. 54–58.

8. Wang L., Clay stabilization in sandstone reservoirs and the perspectives for shale reservoirs, Advances in Colloid and Interface Science, 2020, V. 276, DOI: doi.org/10.1016/j.cis.2019.102087

9. Yu X., Wang Y., Yang Y. et al., Effect of particle content on relative permeabilities in water flooding, Journal of Petroleum Science and Engineering, 2021, V. 205, DOI: doi.org/10.1016/j.petrol.2021.108856

10. Al-Yaseri A., Al Mukainah H., Lebedev M. et al., Impact of fines and rock wettability on reservoir formation damage, Geophysical Prospecting, 2016, V. 64, pp. 860–874, DOI: doi.org/10.1111/1365-2478.12379

11. Folomeev A.E., Davidenko I.S., Vakhrushev S.A. et al., Adaptation of the technology for bottom-hole zones treatment under conditions of scaling at the Sorovskoye field (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2019, no. 11, pp. 124–129, DOI: 10.24887/0028-2448-2019-11-124-129

12. Folomeev A.E., Khatmullin A.R., Imamutdinova A.A. et al., Acidizing technology adaptation for tight sandstone formations (In Russ.), Neft'.Gaz.Novatsii, 2022, no. 8, pp. 77–82,

13. Gusakov V.N., Telin A.G., Pasynkov A.G. et al., Monitoring and a choice of bottomhole zones treatment technologies at RN-Yuganskneftegaz OOO fields (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2007, no. 11, pp. 57–61.

14. Economides M.J., Nolte K.G., Reservoir stimulation, New York: John Willey & Sons LTD Publ., 2000, 856 p.

When modeling fractured horizontal wells with longitudinal fractures, simplified methods are currently used. They do not take into account the change in the reservoir stress-strain state caused by hydraulic fractures of previous stages. The most important task is to improve hydraulic fracturing modeling methods. Therefore, this work objective is to compare the results of hydraulic fracture geometry field studies with the results of modeling multi-fractured horizontal wells with wellbores drilled in the maximum horizontal reservoir stress direction, accounting for changes in the pre-fractured reservoir stress-strain state. Data on hydraulic fracture propagation in rocks, obtained from the results of borehole microseismic monitoring, is currently of particular interest due to the lack of alternatives among the methods for monitoring the hydraulic fracture geometry in horizontal wells. The paper presents the microseismic study results of a multi-fractured horizontal well, located in one of the large fields of Western Siberia. Microseismic monitoring data was used to be compared with the results of mathematical modeling of multi-stage hydrofracturing in horizontal wells in the hydraulic fracturing simulator RN-GRID. The fracture geometry calculations took into account changes in the reservoir stress state from the previous fracturing stages. It is demonstrated that the proppant distribution in the subsequent hydraulic fracturing stages relative to the frac ports position is almost always laterally asymmetrical. In addition, there is a risk of hydraulic fracture breakthrough, which is not predicted by simulators taking no account of the local change in the reservoir stress-strain state from previous stages. It is shown that the results of hydrofracturing microseismic monitoring can be used to improve hydraulic fracturing designs and reservoir engineering.

References

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

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

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

4. Eliseev P.I., Comparing simulation results in the RN-GRID software with field research of proppant gravity differentiation in the process of closing a hydraulic fracture in a low-permeability reservoir (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2021, no. 12, pp. 117–121, DOI: 10.24887/0028-2448-2021-12-117-121

5. Akhtyamov A.A., Makeev G.A., Baydyukov K.N. et al., Corporate fracturing simulator RN-GRID: from software development to in-field implementation (In Russ.), Neftyanoe khozyaystvo = Oil Industry, 2018, no. 5, pp. 94–97, DOI: 10.24887/0028-2448-2018-5-94-97

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

Improving the energy efficiency of a main line pump for oil and oil products during its operation is an important scientific and engineering problem due to the high consumption of power by a hydraulic machine. One of the methods to increase the pump efficiency is improving the hydrodynamic properties of the liquid-end surfaces in centrifugal pumps. This method is one of the promising ways to improve the energy efficiency of pumping equipment through reducing hydraulic losses when transferring mechanical energy to the pumped oil flow. The main advantage of this approach is preserving the design of main line pump (it does not require making any changes in the liquid end configuration and geometric parameters of working parts).

The authors have considered the results of studies of the properties of various composite coatings, which allow improving the pump performance when applying such coatings to liquid ends. The studies were carried out in laboratory conditions according to the developed methods of accelerated testing. We have presented the main provisions of the methodology on carrying out accelerated tests of composite coatings to be used in main line pumps for oil and oil products. This methodology has allowed us to describe the operational properties of composite coatings and to calculate the predicted service life of such coatings when applying them to liquid-end parts of main line pumps. The results of test confirmed the improvement of hydrodynamic properties of liquid-end surfaces in main line pumps for oil and oil products. Based on the tests performed, we have justified the feasibility of using coatings on the liquid-end parts of main line pumps for oil and oil products in the form of increased efficiency when applying coatings to liquid-end parts (from 0.27 to 3.7 %, depending on the main line pump's standard size).

References

1. Degovtsov A.V., Sokolov N.N., Ivanovskiy A.V., Possibility of replacement of cast stages of electric submersible centrifugal pumps (ESCP) in complicated conditions (In Russ.), Oborudovanie i tekhnologii dlya neftegazovogo kompleksa, 2016, no. 6, pp. 16-20.

2. Mikhaylov A.G., Volgin V.A., Yagudin R.A. et al., Comprehensive protection of downhole equipment in case of sand ingress at RN-Purneftegaz (In Russ.), Territoriya NEFTEGAZ, 2010, no. 12, pp. 20–25.

3. Grebenyuk A.N., Application of new materials and parts in ESP in wells with complicated operating conditions (In Russ.), Territoriya NEFTEGAZ, 2006, no. 10, pp. 36-37.

4. Yakimov S.B., The index of aggressiveness of the rentrained solids at TNK-BP fields in Western Siberia (In Russ.), Neftepromyslovoe delo, 2008, no. 9, pp. 33–39.

5. Lykova N.A., Devices for protection esp from severe downhole conditions (In Russ.), Ekspozitsiya Neft' Gaz, 2015, no. 5(44), pp. 19-23.

6. Yakimov S.B., Sand separation plant to protect downhole pumps. Current situation and prospects for the technology application (In Russ.), Territoriya NEFTEGAZ, 2014, no. 2, pp. 44-59.

7. Flegentov I.A., Starshinov D.M., Ivanov A.G. et al., Use of composite materials for main pumps of the oil and products pipeline transport (In Russ.), Energeticheskaya politika, 2022, no. 11, pp. 30-41, DOI: 10.46920/2409-5516_2022_11177_30

8. ISO 12944-1-1998. Paints and varnishes. Corrosion protection of steel structures by protective paint systems, Part 1: General introduction.

9. ISO 12944-6-1998. Paints and varnishes. Corrosion protection of steel structures by protective paint systems, Part 6: Laboratory performance test methods.

10. Ryabtsev E.A., Methodology for criteria-based assessment of energy efficiency of main pipeline pumps (In Russ.), Nauka i tehnologii truboprovodnogo transporta nefti i nefteproduktov = Science & Technologies: Oil and Oil Products Pipeline Transportation, 2021, no. 3, pp. 304–309, DOI: 10.28999/2541-9595-2021-11-3-304-309

Tripping operations (TO) constitute a significant share of labor efforts while performing well servicing and workover. TO is one of the most labor-consuming and non-automated operations in the course of well servicing and workover; currently it is not possible to free a man from his direct participation in these operation.

The article discusses the ways of possible prevention of a safety event associated with tubing falling out of the elevator ETA type during tripping operations. Tubing falling out of an elevator causes accidents (e.g., tubing string collapse) or personnel related safety events. When investigating oft-recurring safety events in TO, one of the root causes of tubing falling out of an elevator is erroneous decision making by those directly involved in the operation, i.e., human factor. Application of the risk-based approach and the Bow Tie Diagram method to map cause-and-effect relationships in oft-recurring safety events associated with tubing falling out of an elevator during TO allows to identify negative actions related to human factors and helps to create preventive mechanisms to control preventive and reactive safety barriers. The article presents the results of analysis of the causes and methods to prevent tubing fallout from elevators and shows a variant of effective measures to prevent similar safety events. In order to create a long-term positive effect for preventive and reactive safety barriers aimed at reducing the risk of injury and reducing consequences of tubing falling out of an elevator, a new approach is proposed. Proposed method for influencing the personnel of oilfield service companies, providing well servicing and workover services, through practice-oriented trainings based on the use of thematic shock training simulators.

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