Electrical Subsea and Drilling (Norway)

Abstract Drilling the upper hole section of wells in deepwater is conventionally done riserless with returns taken to the seabed in a process known as "pump and dump". The depth to which a hole can be drilled using this method is limited by the presence of drilling hazards (shallow water/gas) as well as the economics of not recovering drilling fluids. Using pumps developed for dual gradient drilling operations and taking the mud returns along with the drilled cuttings to the rig rather than at the seafloor can have significant impact on the costs of drilling the well. Additionally, utilizing a mud pump at the sea floor creates possibilities for managing the bottom hole pressure by varying the inlet pressure of the subsea pump. The ability to vary annular pressure allows management of potential shallow water flow situations, creating opportunities to drill through such zones and set the conductor casing, typically 20″ in the Gulf of Mexico (GOM), deeper. Setting the conductor casing deeper can significantly impact well economics, ranging from the saving of a complete size of casing string to larger final borehole completions. To assess the viability of a solution based on using subsea mud pumps to drill the upper hole sections, an economic study and analysis of the costs of drilling deepwater wells in the GOM was carried out. This paper discusses the results and the economic benefits based on a probabilistic risk-based cost analysis comparing cost data of actual wells drilled in the Gulf of Mexico to wells that were modeled using the alternate drilling method. In the modeled wells, two rigs were used, one to drill and set the conductor casing only, followed by another rig to complete the well. For this paper, the drilling costs for the 2-rig approach are compared to the costs of conventionally drilling the same well. Details of the analysis, the modeling process and the assumptions are discussed. The analysis showed that significant savings in well costs are possible, and on a conservative basis varied from 6 – 25% of the total well cost. The analysis also showed that apart from cost savings, using such a 2-rig arrangement could also aid in mitigation of risk while deploying new technologies by transferring the risk to the first rig used solely for drilling the upper hole sections.