The temperature distribution in the wellbore under different conditions was studied by using a designed horizontal well simulation experimental device. The experimental results showed that the Joule-Thomson effect was significant in perforated wellbore. When the opening mode was the same, the larger the gas flow rate, the lower the temperature in the wellbore. Furthermore, with the increase of liquid volume, the temperature drop effect decreased gradually. The more uniform the perforation distribution, the smaller the temperature change in the wellbore. With the increase of liquid volume, the influence of gas flow rate on temperature distribution decreased. The temperature gradient caused by Joule-Thomson effect decreased with the increase of wellbore holdup. At the same time, the experimental results were compared with the theoretical values. It was found that the error of the model was within 4%, which showed the reliability of predictions of the model.
horizontal well simulation experiment perforation Joule-Thomson effect temperature distribution
This is a preview of subscription content, log in to check access.
The authors gratefully expressed their thanks for the financial support for these researches from the Foundation of the Educational Commission of Hubei Province of China (No. Q20191310), National Natural Science Foundation of China (Grant No. 61572084), and National Major Scientific and Technological Special Project (2016ZX05046004-003).
Zhang Z., Xiong Y.M., Guo F., Analysis of wellbore temperature distribution and influencing factors during drilling horizontal wells. Journal of Energy Resources Technology-transactions of the ASME, 2018, 140(9): 092901.CrossRefGoogle Scholar
Maubeuge F, Arquis E, Bertrand O. Mother: A model for interpreting thermometrics. SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 1994. DOI: https://doi.org/10.2118/28588-MS.
Muradov K.M., Davies D.R., Novel analytical methods of temperature interpretation in horizontal wells. SPE Journal, 2011, 16(3): 637–647.CrossRefGoogle Scholar
Luo H.W., Li H.T., Zhou X.J., Li Y., et al., Modeling temperature behavior of multistage fractured horizontal well with two-phase flow in low-permeability gas reservoirs. Journal of Petroleum Science and Engineering, 2019, 173: 1187–1209.CrossRefGoogle Scholar
Luo H.W., Li H.T., Li Y.H., Lu Y., Tan Y.S., Investigation of temperature behavior for multi- fractured horizontal well in low-permeability gas reservoir. International Journal of Heat and Mass Transfer, 2018, 127: 375–395.CrossRefGoogle Scholar
Yoshioka K., Zhu D., Hill A.D., A new inversion method to interpret flow profiles from distributed temperature and pressure measurements in horizontal wells. SPE Production & Operations 2009, 24(4): 510–521.CrossRefGoogle Scholar
Cui J.Y., Zhu D., Jin M.Q., Diagnosis of production performance after multistage fracture stimulation in horizontal wells by downhole temperature measurements. SPE Production & Operations, 2016, 31(4): 280–288.CrossRefGoogle Scholar
Li X.Y., Zhu D., Temperature behavior during multistage fracture treatments in horizontal wells. SPE Production & Operations, 2018, 33(3): 522–538.CrossRefGoogle Scholar
Peszyńska M., The total compressibility condition and resolution of local nonlinearities in an implicit black-oil model with capillary effects. Transport in Porous Media, 2006, 63(1): 201–222.MathSciNetCrossRefGoogle Scholar
Ghoreishian Amiri S.A., Sadrnejad S.A., Ghasemzadeh H., Montazeri G.H., Application of control volume based finite element method for solving the black-oil fluid equations. Petroleum Science, 2013, 10(03): 361–372.CrossRefGoogle Scholar