This paper will discuss the Managed Pressure Directional Drilling fit for purpose solution deployed to meet the drilling challenges in Mexico offshore Zaap field. This innovative solution integrates a new state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as total losses, wellbore instability and stuck pipe were mitigated, and an improved drilling performance with reduction of NPT as compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling (DD). Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication plan are crucial for the effective execution. The solution is based on a rigorous Drilling Engineering process; including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the operator to tackle drilling hazards without compromising the directional drilling requirements. The paper will also discuss the effective communication plan between the directional drilling services, MPD services and rig contractors to ensure safe operational alignment. Also, the paper includes a planning and operational blueprint to reduce NPT related to total losses, stuck pipe & wellbore instability, increase drilling performance (ROP improvement) and quality wellbore for liner run afterwards in the Middle Cretaceous formation. Drilling challenges in the Zaap field requires the utilization of both Directional Drilling technology and MPD techniques to improve drilling performance and reduce NPT respectively. Through processes, best practices and lesson learned, this paper hope to serve as the bellwether for the combined solution to achieve technical limit drilling performance in the Zaap field, offshore Mexico.

Given the increased demands on the production of hydrocarbons and cost-effectiveness for the Operator's development wells, the industry is challenged to continually explore new technology and methodology to improve drilling performance and operational efficiency. In this paper, two recent case histories showcase the technology, drilling engineering, and real-time optimization that resulted in record drilling times. The wells are located on shallow water in the Gulf of Mexico, with numerous drilling challenges, which typically resulted in significant Non-Productive Time (NPT). Through close collaboration with the Operator, early planning with a clear understanding of offset wells challenges, well plan that minimize drilling in the Upper Cretaceous "Brecha" Formation were formulated. The well plan was also designed to reduce the risk of stuck pipe while meeting the requirements to penetrate the geological targets laterally to increase the area of contact in the reservoir section. This project encapsulates the successful application of the latest Push-the-Bit Rotary Steerable System (RSS) with borehole enlargement technology through a proven drilling engineering process to optimize the drilling bottomhole assembly, bit selection, drilling parameters, and real-time monitoring & optimization The records drilling times in the two case histories can be replicated and further improved. A list of lessons learned and recommendations for the future wells are discussed. These include the well trajectory planning, directional drilling BHA optimization, directional control plan, drilling parameters to optimize hole cleaning, and downhole shocks & vibrations management during drilling and underreaming operation to increase the drilling performance ultimately. Also, it includes a proposed drilling blueprint to continually push the limit of incremental drilling performance through the use of RSS with hydraulics drilling reamers through the Jurassic-age formations in shallow waters, Gulf of Mexico.

This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet the drilling challenges faced in 5 consecutive wells drilled in South Texas, USA. This innovative solution integrates a state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as well control events, simultaneous kick-loss, and stuck pipe were mitigated, and an improved drilling performance with a reduction of NPT as compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol are crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the Operator to tackle drilling hazards without compromising the directional drilling requirements. This paper will summarize the 5 wells operations, the drilling optimization results, and the lessons learned from an integrated services point of view in terms of deliverables that made the difference on this project and allowed the Operator to achieve their objectives. In particular, the effective communication protocol between the directional drilling services, MPD services, and rig contractors to ensure safe operational alignment.

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.

Two hole sections (12-1/4Љ x 14-3/4Љ and 10-5/8Љ x 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 Љintact wellbore wall zero failure degreeЉ 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.