A Well with plug set in both tubing was sabotaged and even after initially capping the well, it was observed that attempting to kill the Target Well via surface pumping was abortive. Therefore, in order to achieve well control, drilling a relief well became imperative and required some critical decision to be taken. This include location selection, type fluid to be used in drilling, the casing setting depth, downhole measuring tools for use, as well as contractors needed in achieving success in a suitation of incomplete well survey data. This paper presents how this keys needs were met in drilling the Relief Well planned for 97days trouble free and performed in 107days from spud to hitting Target Well. The success was on single attempt in spite of it having an incomplete survey record acquired 49 years earlier.

Access to new reserves and subsequent production is becoming a challenging scenario for oil and gas companies all over the world. In this particular context, a major operator planned an onshore well in Pakistan (located 350km north of Karachi) as part of a revamped drilling campaign in this mature field. However, in previously drilled wells in the vicinity several drilling issues were encountered including, but not limited to, a challenging drilling window with kicks and losses. These are mainly due to formation structural conditions that require very strick control of the equivalent circulating density (ECD) and the equivalent static density (ESD) for new wells drilled in the area. If successful operationally and if reserves prove economically exploitable, this well will be used as potential reference for future infill drilling in this reservoir. To overcome the issues and ensure the greatest potential to successfully drill this well, it was decided to use managed pressure drilling (MPD) equipment for the last two challenging well sections. Because of this, a full dynamic drilling modelling solution was selected to support the planning phase and subsequently, the decision process during the operations. The dynamic models applied include consideration of temperature, pressure, mud compressibility and rheology as well as gel breaking effects in a transient simulation. For well control considerations a two-phase model considers both influx of the reservoir fluid and modelling of the fluid properties by equation of state as well as distribution and migration of the influx in a drilling kick scenario. As direct result of this study, it was decided to revise and slightly adjust the optimized drilling fluid weight to better manage the ECD/ESD, thereby avoiding compromising the integrity of the well during the operations. Some of the specific parameters were re-defined based on the modelling results, providing enhanced best practices for the MPD utilization. The implemented approach required the drilling practices to be tailored for this particular well and opened the opportunity to implement the lessons learned into the company well design process and drilling practices. For this, a multi-domain collaboration is key to minimize the uncertainty associated with the behavior of the drilling dynamics with respect to the drilling window and the overall operational system. In addition it requires the inclusion of dynamic modelling to provide a more realistic planning approach makes it possible to consider different drilling opportunities in mature fields with challenging profiles. This paper will describe the analysis done using this dynamic drilling modelling approach, with focus on the primary and secondary well control.

With the goal to exhibit leadership in industry process safety, North Caspian Operating Company (NCOC), Eni, and Kinetic Pressure Control have collaborated to evaluate the feasibility and potential process safety benefits from use of the Kinetic Blowout Stopper (K-BOS®) technology in High-H2S and high-pressure drilling and completions and intervention applications from artificial islands in Kashagan field. The study focused on efforts to detect any showstoppers for the application of K-BOS, quantify the reduction in the blowout probability due to its application, and summarize the information currently available about the technology. Using the Eni proprietary e-wise™ fault tree analysis approach, a quantitative risk assessment was performed to compare the probability of a blowout in Kashagan field using conventional BOP systems to the probability of a blowout with the K-BOS added to the stack. The study also reviewed OEM provided operating procedures, a risk assessment for running the equipment, as well as a feasibility study regarding any height restrictions in the BOP stack and the position of the K-BOS in the stack. The impact of alternative equipment for risk reduction such as additional redundancy was also assessed. The application of the 13 5/8" 10M K-BOS system during reservoir drilling, completion and intervention operations significantly reduces the probability of a blowout by at least an order of magnitude. For drilling operations in the most challenging Rim portion of the reservoir, the blowout probability decreases by more than 90% and the residual value is below the blowout frequency for Producing Wells. The improved shearing/sealing capacity and reduced closure time provided by the K-BOS enable a reduced likelihood of a blowout and enhance the risk profile for the oil and gas industry.