As shallower reservoirs are driven to depletion the world over and the world energy demand keeps growing at a steady pace, operators explore for deeper horizons within current fields in hope of making significant discoveries. Deeper exploration in most fields entails significant risk, and a much higher cost per well.
With deeper drilling depths comes tougher drilling challenges, mostly arising from higher pressures and higher temperatures at those depths. High-pressure, high temperature (HPHT) wells present numerous drilling risks, often including influxes while drilling into over-pressured formations, insufficient mud weight and bottomhole pressure control due to bottomhole density reduction with high temperatures, late kick detection due to low permeability formations, swabbing from the formation due to an insufficient trip margin, losses due to high equivalent circulating densities (ECD's), differential sticking, and stuck pipe following extended periods of well-control events.
It is thus of paramount importance for the operator to minimize the associated risk, time, and cost on all HPHT wells.
One such field in Pakistan where the target formation is a high-pressure shale in the Lower Basal Sand Reservoir, which is potentially a tight gas reservoir. This shale formation is known to be over-pressured, with a pore pressure of 18.6 ppg equivalent mud weight (EMW). The estimated fracture pressure of this formation is 19.2 ppg EMW, which results in a narrow drilling window. When an offset well in the field was drilled conventionally, it was plagued with severe well control issues, lost circulation, and stuck pipe events due to ineffective ECD management with a conventional mud system. The operator spent a total of 45 days to regain control of that well.
The operator for the subject well therefore intended to deploy an automated managed pressure drilling (MPD) system to drill the target section with minimal nonproductive time (NPT). The MPD system was expected to facilitate drilling the section with minimal overbalance and compensate the required bottomhole pressure (BHP) with the application of backpressure. The automated MPD system would also account for mud density variations with a high bottomhole temperature (BHT) by executing an advanced well-hydraulics model in real time. Furthermore, the MPD system would provide early kick detection and reaction to well control events.
The operator, in addition to drilling, intended to collect three whole cores while drilling with an MPD system.
Through the application of an automated MPD system, the operator was able to reduce the NPT to practically zero, and successfully achieve target depth and collect the three desired cores.
The paper discusses the planning, wellsite execution, results, and lessons learnt by the application of an automated MPD system in the subject field.