Following the major pre-salt reservoirs discovery in Santos Basin by Petrobras in 2006, a large number of exploratory and development wells have been drilled in the area. More recently, some of those wells have been drilled in large wellbore configurations, mostly due to deeper pre-salt layers and geological uncertainties. This paper presents a case study on drilling a deep 16 ½″ vertical section at a deepwater location, where a turbine and an impregnated bit were used because of an extremely tough drilling scenario. This specific run achieved TD at more than 5000m, marking the first record ever of successfully running an impregnated bit of this size offshore. The basic well design data is shown, as well as the drilling program and offset well and other 16 ½″ bit records. The challenges that were found on drilling deep post-salt 16 ½″ sections in other locations and on the previous BHA runs with PDC bits on this section are highlighted and analyzed with drilling parameters. The impregnated bit specifications and the turbine characteristics are outlined taking operational recommendations into account. Available power at the bit was taken into consideration and the concern with its impact on drilling performance is explained through a comparison with other bit diameters which are widely used. The bit records, drilling parameters and UCS analysis of the section made clear that the turbine with impregnated bit was the most appropriate and effective drilling system for the scenario at the end of the section. A drilling time and cost comparison with other deep hard-formation-16 ½″ sections drilled in other locations shows that the use of this system may yield significant reduction in the total cost by shortening the overall rig time, making it the preferred option in some future challenging drilling projects. Lastly, further turbodrilling and impregnated bit improvements are suggested, theoretically analyzed and justified considering drilling performance maximization and drilling tools and rig equipment limitations.
Drilling from a tension leg wellhead platform (TLWP) to targets away from the slot creates several challenges and brings many operational risks that are not always easy to predict. The decision to reduce costs with dry completions, wellheads, and deep-water rig day-rates considerably increases drilling complexity. In this scenario, an involuntary sidetrack incident happened while circulating for hole cleaning below the casing shoe. This left a reservoir exposed in the mother well. This paper shows the decision-making process, the premises, and the directional work up to the interception of the original well. The BHAs used, drilling parameters, planned and actual well path will be discussed. The rotary steerable performance and settings while drilling to intercept the original well and the survey strategy receive special attention. Discussion about the BHA selection after the identification of the incidental sidetrack is also covered. Having an exposed reservoir made the required trajectory critical. It should be precise but also feasible, including the casing run thereafter. An additional reaming run smoothed the high local doglegs. The conclusion summarizes the complexity of this type of directional drilling operations and the estimated savings in one of the most challenging well drilled in Brazilian deep waters. There were multiple lessons learned from the operation that can help prevent the situation in future, and sharing this knowledge provides guidelines when facing a similar challenge.
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