TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe combination of the large number of rotary-steerable systems (RSS) currently available and the variety of well trajectories in which they are applied requires a customized range of drill bits to optimize system performance. A clear understanding of the specific tool operation, combined with in-depth modeling and physical testing, is the ideal approach for determining the demands placed on the drill bit and thus deriving its key characteristics.This paper describes a series of tests that were performed at a purpose-built drilling facility to examine the variation in directional response with different bit features. Steerability is one of the key criteria involved in RSS bit design, but stability is of equal importance, particularly in ensuring good-quality, gauge borehole for maximum steering potential. To monitor the testing, a proprietary downhole dynamics recorder was used. The recorder consists of a small, sophisticated electronic measuring device that can be either housed in a sub or positioned in a specially modified housing within an existing drillstring component. The recorder was used to gather actual downhole data at a high frequency sample rate to determine both the lateral and torsional stability of the drill bit and RSS assembly with different wellbore trajectories and parameters.Results identified that specific gauge features are crucial to the directional response of the RSS tool. In addition, the dynamics recorder allowed quantitative assessment of stability versus steerability of the critical drill bit features tested. Lessons learned from this laboratory testing have been taken to the drilling environment with excellent field results, demonstrating that matching the bit to a specific RSS tool as part of the system delivers proven drilling success.

This paper describes how extensive testing has allowed the determination of a link between cutting structure geometry, gauge pad configuration, and achievable hole curvature or steerability. For a specific point-the-bit system, the tests have shown that steerability of the bit is not substantially dependent upon the cutting structure geometry; rather, the nature and extent of gauge pad features are crucial to the directional response of the system. Gauge pad bearing efficiency must be high while simultaneously allowing the cutting structure to tilt as directed by the rotary-steerable system (RSS). The several case histories presented, from operations in the North Sea and offshore Indonesia, verify the results of laboratory tests regarding the relationship between design features of fixed cutter bits and steerability of a point-the-bit RSS. Furthermore, these case histories demonstrate that a point-the-bit RSS, together with an optimized bit design, can lead to improved drilling efficiency in providing good directional response, high rates of penetration (ROP), excellent-quality wellbore smoothness, improved logging-while-drilling (LWD) log response, and ease of completion. Introduction Whether an RSS is a point-the-bit or a push-the-bit system, the choice of bit for it is critical to optimize performance because each system operates differently. To match a bit to an RSS, all of the key characteristics of a bit design must be considered; but probably the most important criteria are stability and steerability. Durability and aggressivity, specific to the properties of the lithology, must be considered as well. Compromise is needed in this selection and is of particular importance in view of the focus on bit stability that more sophisticated real-time downhole measurement systems have generated. An understanding of contributors to stable drilling is paramount for improvement of drilling performance. RSS Features Recently an 8 1/4-in. collar sized RSS (the RS 825) has been developed and added to a family of rotary-steerable tools. These systems use point-the-bit drilling technology, incorporating a near-bit stabilizer to orient the drill bit axis with that of the intended hole trajectory. The operating principle of these tools consists of a non-rotating sleeve through which a rotating drive shaft passes. Through the actuation of a hydraulic system, the drive shaft can be deflected away from the centerline of the wellbore.1 The Revolution® RSS contains a high-accuracy rotations-per-minute (RPM) measuring device. The key component of the measuring device is a toothed timing device, containing 24 teeth, that rotates with respect to a stationary sensor. The sensor, in turn, measures the time interval between teeth passing the sensor. These data are used as part of the control mechanism of the the RSS and allow the accurate measuring of the differential RPM between the rotating shaft of the tool and the non-rotating outer sleeve. As long as the non-rotating sleeve is stationary, the differential RPM measurement is equivalent to the downhole drillstring RPM, providing the ability to monitor stick-slip events downhole and control the RSS accordingly. The measured downhole RPM and a calculated stick-slip function are stored in the engineering memory of the RSS and transmitted in real time to the surface, along with other rotary-steerable and LWD measurements, via the measurement-while-drilling (MWD) mud-pulse telemetry system. The engineering memory within the RSS can be configured to record these measurements at varying sample rates, depending on requirements, and the RPM and stick-slip data communicated to surface are used by the field engineer in optimizing drilling parameters. Testing As part of the plan for the integrity testing program for the new RS 825 system, controlled test holes were to be drilled through large concrete blocks to evaluate the directional response of the system. Earlier tests2 and field experience with other sizes of RSS had highlighted the requirement to evaluate the response of different styles of polycrystalline diamond compact (PDC) bit on directional performance; therefore, the decision was made to conduct a series of laboratory tests to investigate the effect of bit geometry on RSS stability and steerability while simultaneously development testing the RS 825.

A smooth torque response is widely regarded as one of the greatest challenges when drilling with a drill bit on a directional assembly. Aspects such as toolface control and stick-slip are both proportional to the torque generated by the bit, and by nature, fixed cutter (FC) drill bits are capable of generating high levels of torque. If large changes in downhole torque are produced while drilling, these will cause rotation of the drill string, and loss of toolface orientation. This results in inefficient drilling and increases risk of bit and downhole tool damage. This paper reviews the field performance of a number of drill bits within the Canadian Rockies on directional assemblies. Particular focus is placed on the torque response and its resultant effect on both the steerability and stability of the assembly. The analysis includes comparison of conventional FC drill bits and roller cone (RC) designs, and also documents performance of specific FC designs that are equipped with torque controlling features. These features, in combination with specific cutting structure layouts, are engineered to provide predictable torque response while being optimized for high rates of penetration. The bit designs also include a unique gauge geometry that was engineered to reduce drag and deliver improved borehole quality. The field performance review includes downhole dynamics data analysis. The recorder used gathers drilling dynamics data at a high frequency sample rate, enabling lateral stability and the variance in downhole rotation of the drill bit to be accurately determined. Evaluation between the different drill bit concepts revealed that use of FC designs with specific torque control features provided toolface control equal to or greater than a RC design. Steerability and stability were improved when compared directly to conventional fixed cutter designs, with resultant increase in penetration rates. Successful application has resulted in significant time and cost savings to operators. Introduction Directional drilling using steerable systems has advanced considerably since the mid-twentieth century, where directional control was attained with rotary assemblies and deflection devices such as whipstocks. The development of the positive displacement motor (PDM) in the early 1980's provided the ability to make course corrections and counteract formation tendencies on a continuous basis. This drove drill bit manufacturers to design and develop FC designs that are optimized to maximize the drilling efficiency of these tools. The key design challenge relates to the difference in aggressivity required for the two operating modes of a motor assembly; sliding and rotating. A steerable motor employs a sufficient bend angle to achieve the planned trajectory in sliding mode. The relative downhole location of this bend (tool face) is held stationary by non-rotation of the string. Rotation of the bit is provided by the mud motor that converts the hydraulic energy of the mud pumped through it to mechanical energy in the form of torque and RPM output to the drill bit. The reactive torque produced by an aggressive FC bit can cause the drill string to twist unpredictably, resulting in loss of tool face. This leads to wasted drilling time associated with reestablishing the desired tool face. It may also lead to stalling of the motor, which can ultimately result in premature failure. However, in rotating mode, the bit is being turned from rotation of both the string and the downhole rotation provided by the mud motor. There are no tool face control concerns thus an aggressive design can be utilized to maximize penetration rate.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractThe oil industry is increasingly interested in drilling dynamics as a primary cause of drilling inefficiency. It has become ever more important to be able to both accurately predict and detect downhole vibration/instability throughout the entire drill string. The drill bit is often assigned as the cause, and frequently bears the scars of dynamic drilling problems. Historically bit manufacturers have used a combination of dull grades and surface data to speculate on cause and effect of downhole events with insufficient attention to what may be occurring in between.A small vibration logging tool has been employed in hundreds of applications worldwide. This paper discusses the implementation of this device and its flexibility for placement of multiple tools in various locations, such as specific built subs and/or existing tools, within the drillstring. The versatility of this tool design offers the possibility to be run with any type of bit, fixed cutter or roller cone, regardless of manufacturer thus making it transparent to drilling operations throughout the entire drilling assembly.Specific field cases will be presented including; validation of pre-run dynamics modeling software, rotary steerable tools, concentric and eccentric hole opening tools, and response of different BHA configurations. This type of data is important to further the understanding of drill bit, drillstring component, and overall drillstring dynamic performance.

The Horn River Basin is a natural shale gas play located in North Eastern British Columbia, Canada. However, these wells require advanced horizontal drilling techniques and extensive hydraulic fracturing to make them economically attractive. This paper details how a major operator, working in cooperation with a key drill bit supplier, has been able to make radical improvements in drilling performance in this area, leading to significant cost reductions.A typical well consists of a main hole interval that has a vertical section, build section (taking the bore from vertical to horizontal), and a final horizontal leg. When the operator started this project in 2008, the objective was to drill this entire main hole in just three bit runs; one for each directional leg described prior. In actuality, twelve to fourteen bits were utilized, averaging over forty days from drill-out to section TD. This made the economic viability of further development questionable.The team approach of operator and bit supplier enabled bit design modifications and improvements to be implemented in a controlled, continuous, and closely monitored program. A key component of this was the development of a unique flexible bit design developed specifically for directional applications in coordination with a leading supplier of motors. These bits contain novel features that allow rapid design modifications to be performed locally, significantly reducing response time, and allowing the program to proceed at a much faster pace than previously possible. Prior to any alterations, a full analysis of the drilling data of the previous iteration was undertaken. Any proposed changes were then discussed in detail with the drilling operations team, prior to implementation.By July 2009, this systematic cooperative approach enabled the operator to achieve the initial objective of drilling the interval in 3 bit runs, but also their subsequent objective of drilling the interval in just two bit runs. Days to drill this section were drastically reduced from over forty to less than twelve days. The savings produced by this huge improvement in drilling performance has greatly assisted the economic viability of continued Horn River Basin development.