Sporadic but significant drilling downtime, potentially linked to field-scale pore pressure anomalies, has occurred during drilling to a deep carbonate reservoir in North Kuwait. Some wells experienced well-control situations while some others suffered severe mud losses. The field data show that pore pressure can vary between 9 ppg and 19 ppg before a well reaches its target depth of approximately 15,000 ft (TVD). These observations require the establishment of a good understanding of the subsurface pore pressure in order to optimize drilling operations, assess reservoir risks and provide input for better well completions.

Geomechanical studies, utilizing pore pressure and temperature data from downhole measurements, openhole logs, drilling records and lithological information, were conducted to explain the overpressure mechanisms. Analyses indicate that overpressure above the reservoir appears to result mainly from hydrocarbon accumulations and subsequent gas generation during hydrocarbon maturation where pore pressure has been measured to be as high as 15 ppg. However, due to variable sealing conditions and field-scale faulting and fracturing, the pore pressure can vary within the same field. Pore pressure close to overburden stress (~20 ppg) observed while drilling through underlying salt and interbedded anhydrite layers is caused by trapping of water released during gypsum-anhydrite phase transformation. In the reservoir below salt, pore pressure varying between 16 ppg and 17 ppg can be attributed mainly to hydrocarbon generation and buoyancy effects.

Towards the bottom of the reservoir, pore pressure is slightly low and varies between 14 ppg and 15 ppg. The severity of vertically and spatially varying borehole breakouts suggests that variations in tectonic stresses are present on the field scale, which may impact the generation of stress-related overpressure. Moreover, the intermittent presence of anhydrite layers and stiff intact limestone beds may act as localized seals generating overpressure.

Geomechanical analyses were subsequently used to constrain the contemporary stress state and fracture gradient profile. These helped explain hole stability issues experienced during drilling and assisted in planning future drilling operations. In addition, the data provided better quantitative input for reservoir risk analysis and well planning for the field development campaign.