Mining of Mineral Deposits

ISSN 2415-3443 (Online)

ISSN 2415-3435 (Print)

Flag Counter

Modeling of the lifting of a heat transfer agent in a geothermal well of a gas condensate deposit

Mykhailo Fyk1, Volodymyr Biletskyi1, Mohammed Abbood1, Mohammed Al-Sultan2, Majid Abbood1, Haval Abdullatif 3, Yevhen Shapchenko4

1National Technical University “Kharkiv Polytechnic Institute”, Kharkiv, 61002, Ukraine

2LLC Weatherford Ukraine, Kyiv, 03150, Ukraine

3Brightpetrozone Co., Erbil, 92001, Iraq

4UMG “Kharkivstransgaz”, Kharkiv, 61002, Ukraine

Min. miner. depos. 2020, 14(2):66-74

Full text (PDF)


      Purpose is to develop mathematical model of nonisothermal inflow and lifting of the recovered gaseous mixture (i.e. geothermal fluid) of a well taking into consideration dynamic coefficient of heat transfer and thermal diffusion coefficient; fluid expansion coefficient in terms of nonadiabatic process; effect of average integral environmental temperature on the heat transfer coefficient; changes in molar mass of the fluid during the well operation; and a process of the productive seam cooling during initial development stages (i.e. months-years).

      Methods of material and energy balance of fluid-heat flows within a productive formation and within a well as well as forecasting of geothermal fluid production; numerical methods of fluid thermal gas dynamics; Runge-Kutta 4th order method; and Quazi-Newton method to solve nonlinear equations have been applied.

      Findings. It has been demonstrated that thermal gradient of rocks and thermal carrier-rock heat exchange vary depending upon operation modes of the formation and the well in terms of temperature effect, temperature difference in humidity, viscosity, compressibility, and other rock characteristics determining efficiency of thermal diffusion as well as coefficient of heat exchange between the fluid and rocks.

      Originality.The specified equations of thermal energy balance in terms of radial filtration and well product lifting have been developed. The equations are more preferable to compare with the current calculation technique, where a coefficient of fluid is expanded in a seam in the context of nonadiabatic process, and consideration of effect of average integral environment temperature of the heat transfer strength (the known methods takes into account geometric mean of the formation temperature). Actual changes in molar mass of the produced geothermal fluid during the whole period of the well operation (i.e. up to 50 years) are involved. Thermal gas dynamic model well inflow-lifting has been improved owing to the consideration of a transient process of the productive formation cooling during the initial stage of the geothermal fluid production (i.e. months-years).

      Practical implications.The developed mathematical model helps specify calculation of a well yield by 10-15%. To compare with the standard methods, the model makes it possible to perform 20-30% specification of heat output by a gas condensate well in terms of thermobaric intensification of the fluid production as well as in terms of binary techniques of fluid-geoheat generation.

      Keywords: yield of geothermal fluid, thermal gradient, rock, parametric temperature full-scale, heat exchange coefficient, Joule-Thompson effect


  1. Azin, R., Sedaghati, H., Fatehi, R., Osfouri, S., & Sakhaei, Z. (2018). Production assessment of low production rate of well in a supergiant gas condensate reservoir: applicatio n of an integrated strategy. Journal of Petroleum Exploration and Production Technology, 9(1), 543-560.
  2. Guo, B., Li, J., Song, J., & Li, G. (2017). Mathematical modeling of heat transfer in counter-current multiphase flow found in gas-drilling systems with formation fluid influx. Petroleum Science, 14(4), 711-719.
  3. Sharafutdinov, R.F., Kanafin, I.V., Khabirov, T.R., & Nizaeva, I.G. (2017). Numerical research of temperature field in “well – formation” system with oil degassing. Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy, 3(2), 8-20.
  4. Kiaghadi, A., Sobel, R.S., & Rifai, H.S. (2017). Modeling geothermal energy efficiency from abandoned oil and gas wells to desalinate produced water. Desalination, (414), 51-62.
  5. Kutia, M., Fyk, M., Kravchenko, O., Palis, S., & Fyk, I. (2016). Improvement of technological-mathematical model for the medium-term prediction of the work of a gas condensate field. Eastern-European Journal of Enterprise Technologies, 5(8(83)), 40-48.
  6. Fyk, M., Palis, S., & Kovalchuk, J. (2016). Gas well production enhancement on the application of innovative structural and thermal insulation nano-coatings. Visnyk of V.N. Karazin Kharkiv National University, Series “Geology. Geography. Ecology”, (45), 80-85.
  7. MahmoodMoshfeghian. (2009). Variation of natural gas heat capacity with temperature, pressure, and relative density. Posted on July 1, 2009 at 10:23 pm
  8. Al-Sutan, M. (2019). The effect of the change in well thermobaric properties on the flow rate from exhausted gas–condansate reservoir. Problems of Geoengineering and Underground Urbanism, 1-2.
  9. Fyk, M., Biletskyi, V., Fyk, I., Bondarenko, V., & Al-Sultan, M.B. (2019). Improvement of an engineering procedure for calculating the non­isothermal transportation of a gas­liquid mixture. Eastern-European Journal of Enterprise Technologies, 3(5(99)), 51-60.
  10. Lurie, M.V. (2008). Modeling of oil product and gas pipeline transportation. Weinheim, Germany: WILEY-VCH Verlag GmbH & Co. KGaA.
  11. Kabir, C.S., Hasan, A.R., Kouba, G.E., & Ameen, M. (1996). Determining circulating fluid temperature in drilling, workover, and well control operations. SPE Drilling & Completion, 11(02), 74-79.
  12. Li, F., Xu, T., Li, S., Feng, B., Jia, X., Feng, G., & Jiang, Z. (2019). Assessment of energy production in the deep carbonate geothermal reservoir by wellbore-reservoir integrated fluid and heat transport modeling. Geofluids, (2019), 1-18.
  13. Rzaev, A., Rasulov, S., Pashaev, F., & Salii, M. (2017). Features of distribution of temperature along the length of oil pipeline. Perm Journal of Petroleum and Mining Engineering, 16(2), 158-163.
  14. Kujawa, T., Nowak, W., & Stachel, A.A. (2005). Analysis of the exploitation of existing deep production wells for acquiring geothermal energy. Journal of Engineering Physics and Thermophysics, 78(1), 127-135.
  15. Shendrik, O., Fyk, M., Biletskyi, V., Kryvulia, S., & Donskyi, D. (2019). Energy-saving intensification of gas-condensate field production in the east of Ukraine using foaming reagents. Mining of Mineral Deposits, 13(2), 82-90.
  16. Fyk, M., Biletskyi, V., & Abbud, M. (2018). Resource evaluation of geothermal power plant under the conditions of carboniferous deposits usage in the Dnipro-Donetsk depression. E3S Web of Conferences, (60), 00006.
  17. Fyk, M., Fyk, I., Biletsky, V., Oliynyk, M., Kovalchuk, Y., Hnieushev, V., & Shapchenko, Y. (2018). Theoretical and applied aspects of using a thermal pump effect in gas pipeline systems. Eastern-European Journal of Enterprise Technologies, 1(8(91)), 39-48.
  18. Alimonti, C., & Soldo, E. (2016). Study of geothermal power generation from a very deep oil well with a wellbore heat exchanger. Renewable Energy, (86), 292-301.
  19. Jung, R., Hassanzadegan, A., & Tischner, T. (2019). Determination of hydraulic properties of a large self-propped hydraulic fracture in the geothermal research borehole Horstberg Z1 in the Northwest German Basin. Geofluids, (2019), 1-13.
  20. Mehmood, A., Yao, J., Fan, D., Bongole, K., Liu, J., & Zhang, X. (2019). Potential for heat production by retrofitting abandoned gas wells into geothermal wells. PLOS ONE, 14(8), e0220128.
  21. Breede, K., Dzebisashvili, K., Liu, X., & Falcone, G. (2013). A systematic review of enhanced (or engineered) geothermal systems: past, present and future. Geothermal Energy, 1(1).
  22. Lei, Z., Zhang, Y., Hu, Z., Li, L., Zhang, S., Fu, L., & Yue, G. (2019). Application of water fracturing in geothermal energy mining: insights from experimental investigations. Energies, 12(11), 2138.
  23. Лицензия Creative Commons