Collaboration between operator, service company reduces completion time on deepwater Egina field
By Connor Behrens, Contributor
Collaboration and a disciplined process approach helped Halliburton and Total E&P Nigeria to achieve a 60% reduction in lower completion times, standalone screens and open-hole gravel packs on the deepwater Egina field, Ken Johnson, Project Manager for Halliburton, said. The reduction was made between the first and 24th well on the field. Further, upper completion times for the same wells were reduced by 40%, and both lower and upper completion operating effectiveness and run reliabilities were measured at above 97%, Mr Johnson said at the 2018 IADC/SPE Asia Pacific Drilling Technology Conference on 29 August in Bangkok, Thailand.
The Egina field was discovered during the early 2000s at water depths greater than 1,500 m (4,900 ft). Project development consists of both oil producers and water injectors. Halliburton worked with Total in this environment to understand the completion challenges to create and formulate solutions that conquered any issues, including deviated wells with long horizontal drains, complex trajectories and installing necessary isolation barrier valves (IBVs) before running upper completion.
“The project goals were to develop a fully integrated team,” Mr Johnson said. “All plans were jointly developed between the operator and the service company. The challenge was to minimize invisible lost time. We were asked to transfer in lessons learned from global deepwater operations, not just operations from Nigeria but other operations in West Africa. The lessons learned that the operator had from previous operations were shared with the service provider.”
An 11,500-sq-m fit-for-purpose operational facility dedicated to the project was located near both the operator’s offices and pre-existing supplier facilities in Port Harcourt. The facility provided supplier offices, operator offices, third-party inspector offices and warehouses for completion equipment, screens, and completion service tools all under a singular setting.
“To deliver the completions, one of the requirements was a fit-for-purpose, dedicated facility that was working only for the project,” Mr Johnson said. “No other operator, no other equipment came into the facility without approval from the operator. We had one set of procedures in the facility, we had one set of people in the facility that worked only for the project. We were asked to measure continuous improvement on equipment reliability and the completion efficiency itself.”
Potential HSE risks were reviewed during the failure modes, effects and criticality analysis/failure risk analysis (FMECA/FRA) process for designing both the lower and upper completions. Finalized completion designs were made fit-for-purpose and agreed upon between the operator and service company, Mr Johnson said. Components of the completion design, such as a combo gauge mandrel and lubricator valve, were incorporated to improve overall completion efficiency, run reliability and the well’s total performance, while reducing the need for well interventions.
“The main thing we had to define is coming up with completion efficiency,” Mr Johnson said. “We tried to eliminate the need for well interventions, but if we had a well intervention, we tried to make the completion design as simple and user friendly as possible. From the day we started, this is the completion that we ran. There have been no modifications. We had continuity throughout the project.”
Since operations began in October 2014, the service company has delivered close to 1,180 incident-free days, achieved 24 wells with one rig by early Q3 2017 versus the plan of 17 to 19 wells by Q4 2017 using two rigs, including 100% reliability on remotely open IBVs, and IBV and downhole gauge reliability is at 100%.
