While the main objective for Well #1 was to appraise the hydrocarbon potential at depths below a known gas reservoir, the operator was able to drill a high-pressure, high-temperature (HPHT) reservoir section with a mud density of 18.4-lb/gal (2.2 sg) with zero fluid losses. The highly deviated appraised interval had both very low and extremely high pore pressures, with the maximum overbalance of approximately 6,800 psi(46,900 kPa).
Compared to offset appraisal wells, downhole losses, hole instability, differentially stuck pipe and well control issues were avoided through the adoption of a low-invasion synthetic fluid system designed with wellbore shielding technology. During the planning phase, the operator conducted extensive laboratory testing to assure technical performance, as well as cost reductions, were achieved by optimizing the drilling fluid design. Best practices from previous HPHT wells were carefully studied and replicated to ensure the success of the well.
Wellbore stability was achieved and the 8½-in. hole section was drilled into the targeted formation tops. In the reservoir hole section, the mud weight was increased to 18.4-lb/gal (2.2 sg) in order to compensate for high pore pressures up to 14,000 psi (96,500 kPa); the highest overbalanced pressure measured was 6,800 psi (46,900 kPa) due to the low pore pressure in the sands above. The drilling fluid was designed with wellbore shielding technology to create an impermeable barrier across low-pressure zones and minimize pressure transmission from high mud density. The rheological properties of the drilling fluid were monitored along with maintaining a thin filter cake and low solids content.
Operational issues and challenges to drilling exploration wells in HPHT environments with high differential pressures continue to be an ongoing industry concern. The drilling fluid design used in this well shows great potential to eliminate drilling hazards in tough downhole conditions.