Prediction of Bottom-hole Pressure in Deep Wells Considering Temperature-pressure Coupling Effects

Abstract

Reliable bottom‑hole pressure (BHP) prediction is essential to guarantee operational safety during deep and ultra‑deep well drilling. Substantial shifts in drilling‑fluid physical properties under high‑temperature and high‑pressure (HTHP) conditions greatly modify pressure‑propagation behaviours inside the wellbore. Conventional prediction approaches commonly treat drilling‑fluid properties as fixed constants, which leads to degraded calculation precision when wellbore temperature and pressure experience sharp variations. To tackle this practical limitation, this work constructs a thermo‑pressure coupled BHP prediction model that accounts for temperature‑sensitive fluid compressibility and rheological parameters. A PVT equation of state is adopted to capture temperature‑dependent density variations of drilling fluids, while a modified Arrhenius model describes how rheological characteristics respond to temperature fluctuations. A segment‑by‑segment iterative algorithm is deployed to solve the coupled system consisting of fluid‑property correlations, wellbore temperature‑field equations and pressure‑gradient equations, yielding the full wellbore pressure distribution. Field data obtained from a 4583‑m multi‑string cased gas well was employed for model validation. Comparative analyses covering static hydrostatic pressure and circulating‑pressure scenarios reveal relative errors ranging from 1.26% to 2.03% against field measurements. Capable of reflecting how thermally induced fluid‑property shifts reshape wellbore pressure development, the proposed model fits well with HTHP well pressure‑prediction demands. It offers a practical analytical tool for deep‑well pressure evaluation and pressure management amid complex drilling scenarios.