The industry continues to apply scientific methods searching for drilling performance improvement. Advanced applications aimed at rate of penetration (ROP) improvement, bottom hole assembly (BHA) longevity through performance management and lost time avoidance through early event detection have evolved as downhole and surface data continue to become more robust. Applying this science to actually improve well construction requires a workflow that enables the operations team to respond to the data in a timely manner. The driller is the most influential person in the performance improvement workflow, yet drilling performance ranks down the list of priorities, rightfully so, behind well control, crew safety and rig equipment operations. Successful well construction improvement requires a tool that delivers timely advice to the driller, enabling performance improvement without distracting from other priorities. This paper will discuss the development and field application of a new technology that allows data to be turned into actions at the well site, improving overall well construction performance. The development team applied a rich understanding of existing wellsite workflows, technology and workplace ergonomics and key attributes from gaming and telecommunications industries. The end result is a piece of technology that brings together several performance improvement analytical tools developed over years of research and development into one console, turning data into clear directions for the driller, and delivering performance improvement feedback immediately. Results, Observations, Conclusions: Field data from 10 wells throughout the world show how the system has been used to reduce well construction time by more than 20%. The radical new way of presenting data to the driller was a significant key to success. The software development platform allowed for quick feedback throughout field testing, integrating user input to continuously evolve the best fit-for-purpose application.

Managed pressure drilling is a technique viewed as a means of improving the chances to drill the most challenging wells. Wellbore pressure management allows operators to address key technical risks such as narrow pore pressure and fracture gradient windows, sensitive wellbore stability environments and navigating steep and unknown pore pressure ramps. Certainly, the technology delivers added advantages while the drilling team attempts difficult wells. Successful execution, however, requires awareness of all aspects throughout the drilling process and full integration of the entire well construction team. Even best laid plans can encounter challenges that quickly become insurmountable. Despite being on alert, as is most often the case with MPD wells, misunderstanding subtle signs throughout the drilling process, poorly synchronized execution or untimely technical failures can lead to catastrophic outcomes for the operator. Additionally, it is not until execution when a full understanding of the wellbore sensitivity to pressure swings becomes apparent. The authors will look at a series of uniquely different wells, all employing MPD but for different technical reasons. Exploration drilling through challenging pore pressure ramps, high angle and horizontal wells across formations highly sensitive to pressure cycling, PMCD wells and wells drilled through very narrow pore pressure and stability window across depleted zones. Analysis of the detailed design during the planning phase, with the information that was known at that time, will lay the foundation of how each well was executed. In each case, the desired outcome was not achieved for reasons unique to the respective project falling outside the core MPD engineering design. Analysis of the failures will identify key lessons learned and show progressive continuous improvement that has made MPD critical to success on future projects and raised confidence of the users.

Technology Update In the past, most wells have been drilled using conventional methods, but the landscape is changing as economic pressures have forced the drilling industry to refocus. Attention is at an all-time high on technologies that deliver operational efficiency and improve safety. Operators, drilling contractors, and service companies have gone through exhaustive measures to reduce cost, refine efficiency, optimize asset performance, and maximize returns. The recently introduced Schlumberger Managed-Pressure Drilling Integrated Solution offers a significant impact in all of these areas. Managed-pressure drilling (MPD) is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. In conventional drilling, the system is open to the atmosphere. However, with MPD, a closed-loop circulation system is created. The closed-loop system is the key element, as it enables control of the annular pressure profile through the application of surface pressure. MPD can dramatically improve operational efficiency through the reduction of nonproductive time associated with influxes, mud losses, and stuck-pipe events. The closed-loop system improves safety by providing an increased awareness of pressure state in the well and facilitates a much higher level of control with quicker response. The MPD drilling technique has been around for many years on land but is relatively new to deep water, as the needed technologies have only become available in the past 5 to 7 years. While manual chokes have been the principal form of control of MPD operations since the technique was introduced, it has been noted that the consistency and repeatability of manual methods is only as good as the choke operator’s skill and the level of experience and teamwork between the driller and the choke operator. For this reason, automated MPD was introduced, and a solution now exists that addresses the many challenges associated with MPD operations. A Shifting Business Case Historically, MPD components have been owned and leased through various service companies. Operators have called out multiple providers to deliver the kit and execute the service. Deepwater MPD requires substantial planning and financial investment, which has typically recurred with each call-out. On top of that has been the need to coordinate multiple service providers to work with the drilling contractor so that the system is properly integrated. Given these requirements, operators have tended not to use the technique unless the well or hole section they are planning cannot be drilled without it. For the most part, MPD in deep water has been a contingency solution rather than a standard practice. It is difficult to build a reasonable business case around a contingency solution or a call-out service that requires such significant investment and has multiple variables at stake. Additionally, service companies must charge a premium to ensure a sufficient return on their investment.

Manual choke control has been the staple of many Managed Pressure Drilling (MPD) operations. To be successful manual choke control requires close communication and cooperation with between the driller and the choke operator. Responding to contingency scenarios, such as rig pump failure, is highly dependent upon the situational awareness of the choke operator and the speed at which they can respond. The consistency and repeatability of manual methods is therefore only as good as the choke operator's skill, experience and how well the choke operator and driller work together. Automated choke control increases the consistency and repeatability of control, as well as the ability to respond to contingency scenarios with little or no operator intervention. However, automation tends to increase the complexity of the equipment needed and changes the competencies required from personnel. Achieving a fit for purpose degree of automation that balances the delivery required to successfully drill the well without adding any more complexity than is absolutely necessary is therefore a challenge. This paper describes a new automated MPD system that was developed with the goal of providing increased performance while minimizing any additional complexity. The new system had to be capable of providing pressure trapping, to be able to manage multi-step pressure/flow pump ramp schedules, and yet had to have a similar physical footprint to and work with existing equipment. The technology was evaluated in terms of ability to control, setup time, ease of use, and ability to perform the scope of work required. The system represents a step change in performance compared to manual MPD and yet maintains a streamline equipment footprint.

Objective/Scope The rotating control device is an integral piece of equipment for managed pressure and underbalanced drilling applications. In 2005, a joint IADC/SPE committee, collaborating with American Petroleum Institute, authored specification guidelines first published as API-16 Specification RCD (API-16 RCD). Does applying a manufacturing specification as a control for operations really minimize risk, or does it limit liability? This paper will outline the journey toward API-16 RCD certification, gaps identified between testing results and operating guidelines, and methodology applied to field performance data to bridge test data with real-life performance expectations. Method/Procedure/Process Analysis of a large laboratory test data set has been accumulated for the API-16 RCD application process. Meanwhile, a much larger data set of field performance has been accumulated over several years from live operations throughout the world. In an effort to seek continuous performance improvement, interrogating the data to determine a proper base line for performance was initiated. It became apparent that determining this base line was challenging, given the wide range of variables. However, through systematic data analytics, along with improved field data capture guidelines, normalizing these variables enabled operating data to validate performance inferences drawn from the existing lab data. Results/Observations/Conclusions Several hundred field runs were compared against more than 50 independent lab tests to determine links. Through comprehensive data analysis, along with acknowledgement of the scientific limits understanding elastomer performance over conditions and time, RCD testing in the lab is better able to predict field performance, serving as a suitable alternative to costly fit-for-purpose field simulation testing. Additionally, this methodology better guides technology improvements required to expand performance criteria. Novel/Additive Information Replicating field conditions in controlled laboratory tests requires a significant range of variables beyond RPM, temperature and pressure. For example, field failures have resulted from chemical factors such as mud compatibility at a range of temperatures, or physical factors such as drillpipe condition and rig alignment. Some in industry view fit-for-purpose testing as a solution, but this can become cost prohibitive for service providers and operators alike. This paper will document viable alternatives.