Drilling lags behind other industries in the implementation of automation. One reason for this is the variability of drilling operations and uncertainty in knowing what is being drilled at any given time. A closed-loop system that continually monitors drilling parameters and drilling performance in real time and constantly adjusts weight on bit (WOB) and rotary speed (RPM) maximizes instantaneous rate of penetration (ROP). The system has been tested in more than 15 drilling operations around the world in both advise and control modes. Field tests show an improvement in ROP typically greater than 10% versus nonautomated operations. Maximum benefit is realized when automation is implemented by means of a closed-loop system, whereby the set points for WOB and RPM are directly fed to the controls of the drilling rig. The algorithm, the closed-loop system, and the performance improvement delivered by this system are currently subject to certain operational constraints, but these will be addressed by future enhancements.

Recent enhancements to measurement-while-drilling (MWO) tools have increased drilling efficiency in directional wells on the North Slope of Alaska. With information provided by downhole weight on bit (WOB) and torque sensors, more timely and accurate decisions have been made, resulting in lower costs per foot. Specific applications of this technology include bit optimization, directional feedback, and drillstring-friction analysis. This paper discusses actual cases where the use of data from these downhole sensors has improved drilling performance. This information will benefit those interested in optimizing polycrystalline-diamond-compact (POC) and rollercone bit runs, improving directional-drilling assembly predictability and performance, minimizing surface torques, and planning high-departure wells.Theory PDC Bit Optimization. Koskie et al. 's1 procedure for optimizing the POC bit requires measuring the forces on the bit and knowing the formation. The MWO's of downhole WOB and torque measure actual forces on the POC bit. The formation type being drilled is predicted with the dimensionless torque value, T D , the torque per unit weight:

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.

No abstract

IADC Members Abstract A BHA becomes stuck, on average, once for every three wells drilled. It is very difficult for drilling personnel to monitor sticking during all phases of the drilling operation. There are many situations where monitoring the stickiness of the hole is very difficult. very often, field crews do not have the time to continuously compute and look at graphs of friction factors, and processing algorithms need to be complimented by automatic warnings. Monitoring sticking while tripping requires knowing the "normal" overpulls, which vary with depth. The authors propose an integrated sticking pipe monitor which automatically calculates friction forces and factors anytime the drillstring is moving, builds normal profiles with depth for comparison and issues alarms to the field crew and driller when sticking is occurring at the BHA. Introduction Roughly 50% of pipe sticking occurs while tripping, 10% while on bottom drilling, and 20% each for working the pipe at a connection and reaming. It may be wrongly concluded from the statistics that drilling is the least critical time for pipe sticking monitoring. Drilling represents the first time a formation is penetrated and provides not only the earliest warning of severe sticking but also a reference point with which to compare all other operations. Previous authors have looked at friction factors while tripping, or on bottom, but an integrated approach has not been developed to monitor trends over time. This paper describes a new comprehensive approach which tracks friction factors anytime the drillstring is moving. P. 573^