A highly depleted gas field in the southern North Sea has been selected as a potential CO2 storage site. Data from drilling of production wells shows that wells experienced substantial tight spots, overpulls, cavings, mud losses, even pack offs, and considerable time was spent in reaming tight holes and circulating excessive cuttings. To mitigate the drilling risks for new CO2 injection wellbores, a geomechanical study was undertaken to understand the drilling issues and to quantify a practical mud-weight window.
The study used offset well drilling and wireline log data to derive field stresses, formation pressure, rock strength and elastic properties. A practical workflow was developed to characterise the interaction between pressure depletion and fracture gradient changes. In this particular case the results showed that the fracture gradient was as low as 9.3 ppg, and the wellbore collapse pressure in the overburden shale was highly dependent on the well trajectory. A vertical well could be drilled safely with a hydrostatic mud weight of ~8.6 ppg. A wellbore deviating at more than 65º would require mud weight approaching 9.3 ppg, the fracture gradient, to prevent wellbore failure. This leads to a tight mud-weight window for drilling management. If an operation mud-weight window of 0.5 ppg is required, the well inclination should be below 65º if it is planned towards the minimum horizontal stress Shmin orientation, or less than 45º if towards the maximum horizontal stress Shmax azimuth to mitigate drilling risks.
This paper describes a geomechananical workflow that assists in understanding the interaction between pressure depletion and fracture gradient changes from which it is possible to quantify a mud-weight window for safe drilling. The workflow description shows how the approach can help mitigate drilling risks and minimise drilling costs by optimising well trajectories and therefore play a significant role in the well planning and drilling management of depleted reservoirs.