Summary The only standard drillstring model in use today is the torque/drag model because of its simplicity and general availability. Field experience indicates that this model generally gives good results but sometimes performs poorly. For example, some friction loads predicted for casing running in horizontal wells have not been consistent with field data. In the standard torque/drag model, the drillstring shape is taken as the wellbore shape. However, given that the most-common method for determining the wellbore shape is the minimum-curvature method, this assumed wellbore shape forces the bending moment to be discontinuous at survey points. This defect is dealt with by neglecting the bending moment. A different approach assumes that the drillstring position corresponds with the minimum-curvature wellbore only at discrete points. The obvious choice for these discrete points is at the positions of the tool joints in the drillstring. Although these tool joints are fixed in position, they are allowed to rotate within the wellbore. These extra degrees of freedom allow solution of the bending-moment problem, because continuity of bending moment can now be ensured at each tool joint. This paper gives a complete description of the drillstring calculation. Typical torque/drag problems are studied to compare the two torque/drag formulations. These studies give comparisons in drag forces and torques for the two models, and for the new formulation, the magnitude of the bending moments.

Since downhole vibration measurements were introduced in the early 1990's, these measurements have become extremely useful for improving drilling efficiency in most parts of the world. Most operators will specify a vibration sensor of some sort to be run with most MWD (Measurement While Drilling) and LWD (Logging While Drilling) applications.Unlike most other downhole measurements, there is no industrial standard for how to sample, process and present the vibration data. This raises a few issues that this paper attempts to address:• Vibration measurements from different companies cannot be readily compared -and it is not known if the different tools and systems will detect the same vibration mechanisms and/or severity of vibrations • Vibration Specifications of MWD and drilling tools from different service providers cannot be compared. It is not possible to compare specifications of the various tools as these are given based on the individual service company's internal vibration definitions This paper looks into the physics and statistics of how four major MWD service providers conduct their vibration measurements.Even though all the service companies basically can measure the same physical parameters such as tri-axial accelerations and instant changes in downhole RPM (Revolutions Per Minute), the data are handled differently when it comes to the physical understanding of the data, as well as the statistical modelling of the vibration severities. To further confuse the issue, the data is also presented differently and on different severity scales.The torque/RPM vibration measurement, commonly referred to as "stick-slip", is well documented by previous publications by the different companies (Chen et. al. 2006). The present paper mostly concentrates on how the different MWD companies measure, process, report and interpret their tri-axial data. An analysis is conducted to establish if the various service companies are tuned to look for the same type of vibrations, or whether different vibration patterns tend to be detected with the various procedures in place.Finally, the need for an industry standard is highlighted, and the MWD industry is challenged to move towards standardisation.

The only standard drillstring model in use today is the torque-drag model because of its simplicity and general availability. Field experience indicates that this model generally gives good results but sometimes performs poorly. For example, some friction loads predicted for casing running in horizontal wells have not been consistent with field data.In the standard torque-drag model, the drillstring shape is taken as the wellbore shape. However, given that the most common method for determining the wellbore shape is the minimum curvature method, this assumed wellbore shape forces the bending moment to be discontinuous at survey points. This defect is dealt with by neglecting the bending moment.A different approach assumes that the drillstring position corresponds with the minimum curvature wellbore only at discrete points. The obvious choice for these discrete points is at the positions of the tool joints in the drillstring. While these tool joints are fixed in position, they are allowed to rotate within the wellbore. These extra degrees of freedom allow solution of the bending moment problem, for continuity of bending moment can now be assured at each tool joint. Further, experimental studies of actual drillstrings have shown the potential to develop contact forces for lateral buckling that are significantly larger than predicted by smooth-pipe models. Thus, by the discrete-point assumption, we resolve two problems: bending moment continuity and underprediction of lock-up.This paper gives a complete description of the drillstring calculation. Typical torque-drag problems are studied to compare the two torque-drag formulations. These studies give comparisons in drag forces and torques for the two models, and for the new formulation, the magnitude of the bending moments.

The Integrated Under-Reamer (IUR) was developed in 2007 in a joint project between an Operator and Service company. The tool was designed to allow for unlimited opening and closing of the tool to provide selective hole opening in unstable formations e.g. unstable shale or swelling salt. Furthermore the tool should be able to close for pull out of hole (POOH) while keeping the circulation continuously on. To accommodate for this the tool was designed to be fully integrated into the modular bus structure of the downhole BHA. Electronics were developed to activate and deactivate the tool from downlink commands sent downhole and distributed via the communication bus to the IUR. Sensors in the IUR detect the status of the tool: such as position of the cutter blades and the health of the tool. This data is transmitted to surface using the MWD pulser. The data is displayed in real-time for immediate review by the drilling team. Additional diagnostic data are stored in memory for post run analysis. Advanced autonomous fail safe control was designed to make sure the tool can always be closed either by downlink or other procedures to allow unrestricted pulling out into smaller hole or the casing shoe. In the case of communication problems a procedure is available for back-reaming with automatically closing the blades. A case history is presented where a water injection well needed increased clearance to run 6 5/8" completion screens. Using the IUR, the well was opened up while drilling from a 8 ½" pilot hole to 9.05". The IUR was de-activated and re-activated successfully several times during drilling the section. The operational procedure is described, and caliper data are presented. The well was completed on plan. At the end an outlook will be given on future reaming on demand applications.

Statfjord Field is one of the largest and oldest fields on NCS (North Sea Continental Shelf) and operates with three platforms Stafjord A, B and C. In recent years, slot recovery to drill more wells has posed big challenges to deliver wells with Gas Lift design due to extensive and cost/time consuming P&A and casing cut and pull operations. In addition to these technical challenges, improving operational excellence has driven the concept of innovative casing design with 11 ¾-in liner. This design eliminates the time spent on extensive casing retrieval operations. This reduces time and risks associated with drilling 17 ½-in section that requires changing from 13 5/8-in to 21 ¼-in BOP, higher flow rates for hole cleaning, larger volume of cutting injection, and waiting 13 3/8-in casing hangers that are crucial long lead items. Installation of 11 ¾-in liner at required depth and cementing, potential collapse of Hordaland formation due to extended time exposure, high flow rates for hole cleaning and minimizing well collision risks with producers in 8 ½-in were identified as high priority design goals in the early planning phase. To address aforementioned challenges and meet design goal in time and cost efficient way, innovative ideas were fundamental necessity. This paper discusses the integration of novel drilling approaches used in accomplishing a new gas lift well design that has opened redundant well slotson Statfjord field for drilling. Operational highlights leading to successful well delivery are: First use of dual reamer RSS BHA in 12 ¼ x 13 ½-in to minimize the rat hole and exposure time across “creeping” Hordaland formation in one run and helped 11 ¾-in liner to reach gas lift formation strength depth. Use of new generation RSS technology to drill ~930m 8 ½-in section to widen the operational flow range for hole cleaning and steering in high stick slip and collision environment. Use of modern surveying technique and magnetic ranging technology to drill 8 ½ -in section in potential collision environment. This was first ever use of dual reamer point the bit RSS BHA in North Sea and New generation RSS and special surveying technique on Statfjord.