Case Study: Dual Bottomhole Pressure Management for Differential Sticking Mitigation & Hole Instability During MPD Liner Operations in Contrasting Pressure Regime

Abstract

Maintaining wellbore stability and avoiding differential sticking in HPHT wells becomes increasingly challenging when narrow and conflicting pressure regimes coexist across the open hole. This challenge was encountered during the execution of a 7-in liner in a 35° inclination well drilled to 5,400 m MD under HPHT conditions, with bottomhole temperatures approaching 150 °C. The well penetrated highly permeable, unexpectedly low-pressure (1.33 SG) limestone sequences of Formation-C and Formation-S, followed by the high pressure (breakout pressure of 1.47 SG) shale-dominated Formation-N. The sharp pressure contrast, combined with differing formation characteristics, resulted in an effectively non-existent static pressure window. This environment had previously led to two incidents of BHA differential sticking during drilling operations. Running the liner posed a significantly higher sticking risk than drilling assemblies due to increased wall contact, extended stationary periods during connections, and slower pipe movement. Conventional mud weight selection, mud treatments, and operational practices were insufficient to simultaneously mitigate differential sticking in the highly fractured limestone while maintaining stability in the high-pressure shale formation beneath. To address these challenges, an unconventional MPD-assisted approach employing variable bottomhole pressure (BHP) was adopted, specifically tailored for liner deployment to manage the competing requirements of differential sticking mitigation and shale stability. Prior to entering open hole with the 7-in liner, a higher BHP equivalent to 1.47 SG was maintained throughout while running inside casing. Once in open hole, two distinct BHP setpoints were applied. A reduced BHP of 1.40 SG was maintained during stationary periods for connections, resulting in lower differential pressures than those derived from Formation-N and remaining below its optimal stability requirement for short durations. Formation fingerprinting data acquired during drilling confirmed limited flow potential from the shale interval Formation-N and a low risk of instability during brief exposure to reduced pressure, allowing controlled relaxation of annular pressure without compromising well integrity. During pipe movement, a higher BHP of 1.47 SG was then maintained, with continuous movement providing additional mitigation against differential sticking at elevated pressures. The liner was successfully run to bottom without sticking, and all liner hanger setting operations were performed under MPD with controlled annular pressure exposure. Cementing was executed at an elevated bottomhole equivalent circulating density to mitigate gas invasion risk, with liner rotation applied to improve displacement efficiency and circumferential cement coverage. Cement displacement, liner top packer setting, and subsequent operations were completed without incident. A successful negative pressure test was achieved, and cement bond evaluation confirmed acceptable zonal isolation.