With operations reaching a performance plateau, an operator and service company embarked on an ambitious project called "Well of the Future" (WoF Project) to increase well delivery performance, utilizing current technology, knowledge and experience. The main goal was to reduce overall well construction and completion cost and time up to 30%. In the past, wells typically took up to 300 days and USD 65 million to drill. Twenty years of drilling performance history in the Colombian Foothills were analyzed, and global 'best practices' reviewed to determine what innovative and sustainable solutions can be applied to future wells in the hydrocarbon-rich foothill license area and beyond. Many of the identified cost/time issues related to borehole instability occurred in the Carbonera Formation, a series of intercalated formations that include argillaceous and sandy-silty coal beds. The classical approach to evaluating borehole stability was not effective, and was expanded using additional formation evaluation data, fluids properties and historical operational data to gain a better understanding of the problem. Parameters that affect the Equivalent Circulation Density (ECD) were also evaluated, including: mud density, mud rheology, Rate of Penetration (ROP), gas, mud flow, restrictions and contaminants. In addition, caving volume measurements from offset wells were included in the pre-well study. During the execution of the first well, the caving rate data was fed into the real-time data management/visualization system and plotted together with all other factors that affect the ECD, enabling a more coherent analysis. Percentage of Caving shape was also plotted during drilling and tripping operations, enabling a deeper understanding of wellbore instability that included: Fragility of rocks associated with micro-fractures, sensitivity to the amount of mechanical energy applied to the weakest formations while drilling or tripping, time dependency, attack angle with respect to shale bedding plane and well trajectory, coal bed displacement and sealing strategy. All the information combined with Logging While Drilling (LWD) data and on bottomhole Measured While Drilling (MWD) enabled not only the detection of the events, but the understanding of the root causes. Results indicated that the mud weight and sealing management aren't enough to solve the wellbore instability in the Carbonera Formation. The solution involves other factors such as correct casing seat, BHA designs, trips frequency, pills record, identifying the stronger intervals to circulate, caving monitoring as a borehole quality indicator, and the handling of drilling assembly. As a result of this workflow, a new record for the field was achieved: 216 days of drilling for the total well (65 days faster than the original plan), where real time wellbore stability monitoring contributed to reduce the days of drilling of one of the most difficult sections and establishing lessons learned for further drilling campaigns.
With the increasing complexity of wells being drilled to optimally access as much of the reservoir as possible, an integrated drilling risk assessment strategy needs to be presented to address the increasing level of challenges and risks. Wells are being drilled deeper, through intervals that are heavily depleted into virgin, unexplored reservoirs. They are extending outward to horizontal lengths that were not even dreamed of several years ago. The assessment process described in this publication incorporates a better understanding of the complex geologic environment such as a multitude of pressure compartments, complex faulting and lithological variations that could potentially increase the risk magnitude. With these challenges, there is a step change in understanding and quantifying these hazards, risk liabilities and uncertainties that need to be addressed to make these projects commercially viable and be able to drill down to their designed targets without cost overruns due to NPT, and not less important, keeping a stable borehole capable of being evaluated and resulting in successful production rate. In order to address these challenges, more upfront in-depth planning and analysis must be performed. Often times, a review of the drilling issues are performed around symptoms of drilling events to respond to them, but not necessarily to determine why these events happened in the first place – the root cause. This shows when contingencies are built into a well plan to account for the NPT consequences of these drilling events observed in offset wells. In order to proactively address these increasing risks and hazards, development and incorporation of a detail risk mitigation strategy is required. Through experience, leveraging drilling, geomechanical and geological models in the risk assessment process, has proven to be successful in understanding the hazards that are present. Bringing out the potential hazards is just part of the strategy. A multi-discipline team needs to analyze each potential hazard and determine the best mitigation strategy to mitigate that risk down to a safe, acceptable level. The collaboration of a multi-discipline team is the key component to understand all the different drilling, geological, geomechanical and fluids influences on the potential hazard. With this type of approach in assessing the risk, the process can then address all the potentially different variables required to design an intelligent, proactive drilling strategy. Even with the best strategy in place, there are geologic uncertainties that still need to be analyzed. Knowing these uncertainties, this multi-discipline team designs a mitigation strategy utilizing the right mix of technologies and real-time monitoring component to be able to update models to fine-tune the drilling window and to provide recommendations while drilling - to optimize the drilling process. Showing that this process is effective, several results will be discussed, demonstrating the value of incorporating a pre-drill risk assessment along with real-time monitoring to reduce drilling time, uncertainties and to successfully provide safe and predictable operations from start to finish that provide ideal wellbore conditions for completion.
Los Alamos National Luborafoy is operated by the University of California for the Unifed Sfates Departmenf of Energy under contract W-7405-ENG36. DlSTRlBUTlON OF THIS DOCUMENT IS UNLiMiTED I APPI participation in this survey was accomplished under Cooperative Research and Developmenf Agrement (CRADA) (LA93J10090). An Afirmafive Action/Equal Opporfunity Employer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither The Regents ofthe university of California, the United States Governmenf nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any spec@ commercial product, process, or service by trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, orfnwring by The Regents of the University of California, the United States Government, or any agency therw5 The views and opinions of authors expressed herein do not necessarily state or rejlect those of The Regents of
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