A Coupled Transient Wellbore/Reservoir-Temperature Analytical Model

Abstract

Summary This work presents a new coupled transient wellbore/reservoir thermal analytical model, consisting of a combined reservoir/casing/tubing system. The analytical model considers flow of a slightly compressible, single–phase fluid in a homogeneous infinite–acting reservoir system and provides temperature–transient data for drawdown and buildup tests at any gauge location along the wellbore. The model accounts for Joule–Thomson (J–T), adiabatic–fluid–expansion, conduction, and convection effects. The wellbore–fluid mass density is modeled as a function of temperature, and the analytical solution makes use of the Laplace transformation to solve the transient heat–flow differential equation, accounting for a transient wellbore–temperature gradient ∂T/∂z. The solutions presented assume moderate– to high–permeability reservoirs and do not consider skin effects in the formation. Results of the analytical model are compared with those of a commercial thermal simulator and with those of available models in the literature. Our model provides more accurate transient–temperature–flow profiles along the wellbore in comparison with previous analytical models in the literature. Furthermore, a generalization of a well–known parameter–estimation method from transient–temperature data is provided.

Establishment and application of temperature–pressure coupling model for opening and closing wells in HTHP gas wells

“…Compared with normal temperature and normal pressure wells, the distribution of wellbore temperature and pressure at different times when high-temperature and high-pressure gas wells are on and off is more complex and dynamic monitoring is also more difficult (Huan et al, 2021; Wang et al, 2020). Many existing conventional monitoring process methods and interpretation techniques often cannot meet monitoring needs (Wang et al, 2019; Galvao et al, 2019), and theoretical analysis must be used to predict the distribution of wellbore temperature and pressure. In addition, in actual production, it was also found that the wellbore temperature will change after the shut-in of a high-temperature and high-pressure gas well, resulting in changes in fluid physical parameters and liquid phase settlement.…”

Simulation and Analysis of Temperature and Pressure Fields in the Wellbore of Self-Injection Well

“…The results were like the oil and gas production flow process: parameters such as discharge volume, tubing size, formation temperature gradient and pressure gradient had a large influence on the wellbore temperature and pressure. Galvao [8] et al considered the flow of compressible single-phase fluid in a homogeneous infinite-acting reservoir system and provided temperature transient data for a pressure drop test at an arbitrary measurement location along the wellbore, and synthesized the heat transfer process between the wellbore-reservoir and correlation coefficients, a new transient temperature-pressure coupled calculation model was proposed, which consists of a combined system of reservoir, casing, and tubing. Zheng et al [9] established a wellbore temperature-pressure prediction model based on the conservation of fluid energy, momentum, and mass, and took into account the fluid velocities, densities, and Joule-Thomson coefficients affecting the wellbore temperatures and pressures of high-temperature and high-pressure gas wells and analyzed the impact of different production rates and production times on the wellbore temperature-pressure prediction model and the effect of different production rates and production times on the wellbore temperature-pressure prediction model.…”

Prediction of Gas Hydrate Formation in the Wellbore

“…As a result, it may not be suitable for accurately predicting temperature distribution in the wellbore during the early stages of production. Galvao et al [8] developed a method that incorporates Joule-Thomson (J-T) effects, adiabatic fluid expansion, and fluid compressibility in the prediction of temperature-flow profiles, while their method only considered density as a function of temperature and ignored the impact of pressure. Most scholars rely on the overall heat transfer coefficient of the wellbore when calculating temperature distribution [9][10][11].…”