Abstract
The narrow drilling window of a High Pressure-High Temperature (HPHT) formation creates challenges in managing bottom hole pressure (BHP) during drilling and tripping operations. Managed Pressure Drilling (MPD) techniques have proven effective in accurately controlling downhole pressure, especially in HPHT environments. This study evaluates the capability of automated Managed Pressure Tripping (MPT) techniques in the Haynesville shale gas. The results show that this approach effectively controls the BHP while tripping, resulting in significantly improved operational efficiency, cost, and safety.
MPD hydraulics are developed primarily based on the well profile, mud properties, and drill string dimensions. It uses analytical formulation to compute annular pressure losses along the wellbore every second. Subsequently, the required mud volume, pumping schedule, and applicable surface back pressures (SBP) for the displacement of the heavy pill are simulated to accurately follow the narrow drilling margin. This technique is provided to the field as guidance, and the heavy pill is displaced in multiple stages while maintaining constant bottom-hole pressure through MPD. This method is fully automated, given accurate drilling parameters, and can be controlled remotely from a remote operations center (ROC).
Drilling the deepest HPHT Haynesville wells with a narrow drilling window was successful by using MPD techniques with a mud weight of 16.0 ppg. The pore pressure / stability limit of 17.0 ppg was less than 2% of the formation integrity test (FIT) limit of 17.3 ppg. The MPD hydraulics simulator enables real-time BHP calculations, coupled with a pre-engineered mud schedule, which improves overall tripping efficiency. The heavy pill was displaced in multiple stages during casing and drilling BHA runs based on FIT results. This method resulted in smooth tripping procedures with no reported wellbore stability issues or fluid loss concerns. In comparison to conventional tripping, managing adequate SBP along with a mud pumping schedule allows tripping execution within such a narrow margin. There were no reported observations of wellbore stability issues nor any significant fluid loss concerns. In this case study, the well was drilled to a total depth of 24,100ft MD, and the production casing was successfully run to the planned depth using a multi-stage displacement technique.
