Distributed fiber optic temperature sensing (DTS) monitoring technology is increasingly widely applied in oil reservoir water injection development. However, existing DTS interpretation methods for layered water injection processes have insufficiently considered the effects of multilayer injection and reservoir damage. To address this issue, this paper takes into account interlayer heterogeneity and reservoir damage and, based on the laws of conservation of mass and energy, comprehensively incorporates the effects of friction, the Joule–Thomson effect, thermal convection, and thermal expansion. By coupling wellbore pipe flow with formation seepage, a temperature profile prediction model for multilayer water absorption under steady-state water injection conditions is established. Comparative validation against classical models such as those by Babak and Nowak demonstrates that the proposed model achieves high computational accuracy. Using this model, the influence patterns of injection rate, tubing diameter, formation coefficient, and skin factor on wellbore temperature distribution are systematically analyzed: a higher injection rate leads to a smaller temperature rise in the injected water; a larger tubing diameter results in a greater temperature rise; the formation coefficient affects the temperature profile by regulating interlayer water absorption distribution, while reservoir damage (skin factor) has a relatively limited direct impact on the temperature profile. The model is applied to interpret DTS field data from Well A, and the water absorption rate of each sublayer is quantitatively obtained: the main water absorbing intervals are 1878.7–1897.5 m and 1919.5–1950.6 m, with water absorption accounting for 30.57% and 24.28% of the total injection rate, respectively, while the remaining intervals exhibit secondary water absorption. These interpretation results are in good agreement with earlier oxygen activation tests. This study provides a theoretical basis and analytical method for applying distributed fiber optic temperature measurement technology to monitor water absorption profiles in multilayer injection wells.
Tao et al. (Fri,) studied this question.