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The Egina project has delivered best-in-class upper and lower completions, utilizing deep water completion experiences, global best practices, and lessons learned using a "factory" approach providing robust completion processes. Continuous improvement throughout the completion process was achieved through process optimization practices that contributed to the overall success of the project. Lower completion (LC) times have been reduced by 60 % between the first and 26th well, while reducing upper completion (UC) times by 40 % for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies (OE), and run reliabilities (RR), exceeding 98 %. Mechanical skins average approximately 2.5, while productivity/injectivity indices recorded 26 wells, during initial flowback and injection testing, average around 150 B/D/psi (325 m3/D/bar). Standardized completion designs identified the fundamental process tasks and estimated cycle times associated with those tasks. A disciplined process approach was maintained to help minimize potential risks—by using Failure Mode, Effects, and Criticality Analysis (FMECA) and Failure Risk Analysis (FRA)—during all stages of the project, anticipating requirements and potential issues. Implementation of lessons learned from previous deep water operations during the project was fundamental to design optimization and the allocation of local resources. Following in the spirit of a "factory" approach in executing the completions, all times for tasks and subtasks were captured from the onset of project inception, allowing the project team to establish benchmark task times, while demonstrating continuous improvement throughout the project. The project has delivered best-in-class completions, leveraging deep water completion experiences and referencing global best practices and lessons learned. Fundamental tasks for both the lower and upper completions were identified as the areas where the most significant efficiency improvements could be gained. The team developed a data tracking process to help ensure tasks and subtasks were monitored during the completion process, allowing the project to establish best practices. Statistical analysis of lower and upper completion tasks and subtasks was constantly monitored, with results communicated to the team. Since project kickoff, lower completion run rates have been reduced by 60 % between the first and 26th well, while reducing upper completion rates by 40 %. Well construction durations currently average 24 days per well, and lower and upper completion operating efficiencies and run reliabilities exceed 98 %. The project established Key Performance Indicators (KPIs) for fundamental tasks monitored during the completion process, establishing benchmark metrics for each while monitoring continuous improvement. Reviews of these tasks within the completion process for completed wells have helped identify the improvement of best practices and lessons learned, at the task and subtask level, which have been applied to future completion activities in Nigeria and additionally shared within the operator’s global deep water operations.
The Egina project has delivered best-in-class upper and lower completions, utilizing deep water completion experiences, global best practices, and lessons learned using a "factory" approach providing robust completion processes. Continuous improvement throughout the completion process was achieved through process optimization practices that contributed to the overall success of the project. Lower completion (LC) times have been reduced by 60 % between the first and 26th well, while reducing upper completion (UC) times by 40 % for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies (OE), and run reliabilities (RR), exceeding 98 %. Mechanical skins average approximately 2.5, while productivity/injectivity indices recorded 26 wells, during initial flowback and injection testing, average around 150 B/D/psi (325 m3/D/bar). Standardized completion designs identified the fundamental process tasks and estimated cycle times associated with those tasks. A disciplined process approach was maintained to help minimize potential risks—by using Failure Mode, Effects, and Criticality Analysis (FMECA) and Failure Risk Analysis (FRA)—during all stages of the project, anticipating requirements and potential issues. Implementation of lessons learned from previous deep water operations during the project was fundamental to design optimization and the allocation of local resources. Following in the spirit of a "factory" approach in executing the completions, all times for tasks and subtasks were captured from the onset of project inception, allowing the project team to establish benchmark task times, while demonstrating continuous improvement throughout the project. The project has delivered best-in-class completions, leveraging deep water completion experiences and referencing global best practices and lessons learned. Fundamental tasks for both the lower and upper completions were identified as the areas where the most significant efficiency improvements could be gained. The team developed a data tracking process to help ensure tasks and subtasks were monitored during the completion process, allowing the project to establish best practices. Statistical analysis of lower and upper completion tasks and subtasks was constantly monitored, with results communicated to the team. Since project kickoff, lower completion run rates have been reduced by 60 % between the first and 26th well, while reducing upper completion rates by 40 %. Well construction durations currently average 24 days per well, and lower and upper completion operating efficiencies and run reliabilities exceed 98 %. The project established Key Performance Indicators (KPIs) for fundamental tasks monitored during the completion process, establishing benchmark metrics for each while monitoring continuous improvement. Reviews of these tasks within the completion process for completed wells have helped identify the improvement of best practices and lessons learned, at the task and subtask level, which have been applied to future completion activities in Nigeria and additionally shared within the operator’s global deep water operations.
A major operator with two large projects in Africa has been using a unique subassembly design, called the dual-isolation assembly (DIA), positioned on the bottom or toe of an open hole stand-alone screen (SAS) completion. The main objective of the DIA is to enhance the circulation process for washdown capabilities and provide efficient management and removal of the filter cake for the subsequent improvement of injectivity rates by lowering formation skin values on the injector wells. After providing high-rate washdown through the float shoe at the toe of the completion, the DIA provides a means of circulating a filter cake removal treatment for the open hole. Once the filter cake treatment has been circulated sufficiently, the service tools are retrieved from the completion to surface. For an injector well, the flow path into the formation would be through the sand-control screens and the float shoe from the inside. Since the float shoe incorporates spring-loaded valves that would normally open during injection and close when pumping stops, it is beneficial to lock the valves out of service to prevent long term spring fatigue that could cause the valves to remain open at some point during the life of the well, allowing flow back of formation material inside the screens. After treatment of the open hole, an additional function of the DIA is to close the barrier isolation valve to isolate the formation while the filter cake treatment is activating. As a continuation of an earlier paper (Roane, et al. 2018), the DIA has met all expectations on all 19 wells where it has been implemented in Africa. Due to enhanced procedures, the mechanical skins have averaged 2.5 and injectivity indices have averaged above 140 (B/D/psi) on these wells. Installation times have continually improved during the project due to following best practices. In addition to fulfilling the requirements of these standalone screen (SAS) completions, the DIA design addresses other potential challenges, such as the prevention of hydraulic locks and formation swabbing, which can be detrimental and problematic to open hole completions. Other characteristics of the DIA that benefit open hole management were realized during the course of the project, such as the capability of the DIA to wash through the interior of the isolation barrier valve prior to closing the valve. Once closed, the valve can be re-opened and re-closed as required. An important aspect of the physical attributes of the DIA that benefits logistics and running speed of the completion is its compact design allowing it to be completely assembled in the shop and shipped to location, such that it is a single pickup and makeup on the rig floor. This benefit has been exhibited by continual improvement in completion installation times throughout the project.
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