Two hole sections (12-1/4Љ ϫ 14-3/4Љ and 10-5/8Љ ϫ 12-1/4Љ) were planned to be drilled through sequences of unstable shale and depleted sand packages with no drilling windows, which are defined by the shale Wellbore Stability Gradient (WBSG) delimited by the "intact wellbore wall zero failure degree" and the depleted sand fracture gradient criteria. Historically, significant non-productive time (NPT) associated with wellbore instability and lost circulation had resulted in sidetracks and other costly remediation in both hole sections. The operator and the service provider have identified the Constant Bottomhole Pressure (CBHP) variant of Managed Pressure Drilling (MPD) and wellbore strengthening as the necessary technology approach to safely drill through both challenging hole sections. Dynamic and static wellbore strengthening were applied to increase the near wellbore stresses across the depleted sands to create a drilling window, whilst the MPD CBHP was used to mitigate bottom hole pressure fluctuations and cyclic stress across the shale packages.The MPD well evaluated in this paper had just four hours of non-productive time related with downhole problems and wellbore stability, a minimal fraction when compared to the 980 hours lost in the previous conventional offset well. The MPD well did not require any back reaming operation, whereas the offset well in the area required 7 back-reaming events to get a good quality wellbore. A total of 533 hours were required to drill the 2 hole sections in MPD compared to the 2,410 hours required to drill the same sections conventionally in a previous offset well in the area. This paper summarizes the key MPD planning, engineering, results obtained and lessons learned that delivered a successful campaign of producer wells.

A major operator in the Gulf of Mexico (GOM) desired to increase oil production to meet growing energy demand. To meet this challenge, the operator explored an alternate completion design to mitigate reservoir damage observed in previous producing wells and collaborated with the fluids provider to design a solution to address this concern. The design and solution ultimately applied resulted in "negative skin" with production rates far exceeding historical field rates. Additionally, the operator realized significant cost savings with this change in completion approach by eliminating traditional steps. The development field had its unique challenges with ongoing depletion, wellbore instability risks, and compartmentalization in the reservoir, making access to thinner oil reservoirs challenging to develop. The standard completion approach was to drill with a synthetic-based fluid, perforate the casing, and perform a frac-pack completion. Using technology from another region, the operator elected to change the traditional cased hole frac-pack approach to drilling horizontally through the reservoir, run production screens, and perform an open hole gravel pack completion. In the fluids design phase, the fluids provider performed hydraulics modeling and laboratory testing on multiple formulations, including brine compatibility with formation water; formation response testing; high-pressure/high-temperature (HPHT) rheology and fluid loss; static age testing for intervals of 16 hours, 3 days, and 5 days; and contamination testing with solids, synthetic-based mud, and cement. This paper discusses the methodology used in the design phase required to engineer a reservoir friendly fluid to meet the challenges faced with this complex well.

This paper highlights the new drilling and completion technologies used in the delivery of the company’s first successful horizontal open hole gravel pack (OHGP) in the deep-water Gulf of Mexico (GoM). The well was drilled and completed with well performance exceeding the planned objectives. A new drilling fluid system was needed to address the high depletion, minimize formation damage, and manage the wellbore stability challenges associated with depleted horizontal drilling stress anisotropy. A brine-based system inclusive of a reservoir drill-in fluid (RDIF), solids free screen running pill, and displacement push pill, were qualified. Managed pressure drilling (MPD) was employed to manage the drilling of depleted sands, and managed pressure cementing (MPC) was used for cementing across narrow frac gradient (FG) windows, a new application for the company. New real time drilling surveillance was also applied to allow for trajectory optimization and maximining the open hole (OH) length. For the completion, a new high temperature gravel pack (GP) carrier fluid was developed to meet the high reservoir temperature and pressure requirements. This GP fluid was also designed to break on surface using an optimized breaker system, allowing for full capture with zero discharge. The sandface completion system included a new to GoM shunted wire wrap screen (WWS), y-manifold, and new lower completion hardware including an anti-swab GP service tool. New completion open hole displacement and GP procedures, to include a new skid-based GP pumping technique, were also implemented successfully.