Deepwater Open Water Work Drilling Optimization

This paper describes a new Rotary Steerable System (RSS) and results from its field testing program. The RSS has been designed to handle the technical requirements of the most challenging wells, but also to be economical for use in low cost wells. This important feature was achieved by a unique hydraulics and electronic design and through the use of durable but low cost materials. The tool itself consists of three active and independent steering blades placed close to the bit, and a near-bit stabilizer which acts as a fulcrum. The steering blades apply a constant force to the formation. The displacement of the blades is measured to offset the Bottom Hole Assembly (BHA) in the desired direction. The clamping force of the tool in the hole acts to stabilize the lower part of the BHA and remove unwanted vibration and instability from the drill bit. This significantly improves BHA response, borehole quality, ROP and bit life. Since the RSS has a full 3D capability, it can drill constant curvature boreholes in any direction. The tool has been tested in wells in Texas, Louisiana, Oklahoma and the Gulf of Mexico. The results of these tests will be presented in detail. It is shown that BHA optimization can make a significant difference to the quality of directional holes drilled with a RSS. The data obtained during testing have, in fact, lead to an optimized BHA configuration which is unique compared with any other existing RSS. This optimized BHA configuration was determined from test runs in both point-the-bit and push-the-bit modes. Through the course of this exercise, it was shown that point-the-bit technology can provide superior borehole quality, improved Rate Of Penetration (ROP) and consistent Dog Leg Severity (DLS). Finally, the improved performance and time saving obtained with this new RSS will be compared with offset data from directional wells that were drilled with conventional steerable motor assemblies.

This paper presents technical features and associated benefits of a recently developed under reamer technology and its applications in the offshore Norway Oseberg South field to drill 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections. It discusses the results of the operations and demonstrates how the operations benefited from the new technology. In today's drilling operations, expandable reamers are broadly used to support optimized casing and completion programs and to reduce operational risks such as high Equivalent Circulating Density (ECD), drilling troublesome formations and reaming well path conformities. The currently available hole enlargement technologies, such as ball drop and hydraulically activated reamers, carry intrinsic risks and limitations. To address the challenges associated with currently available under reamer technologies, expandable reamer technology was recently developed jointly by a service company and a major operator, and was field tested offshore Norway. The under reamer, which is fully integrated with the company's existing Rotary Steerable System (RSS) Bottom Hole Assembly (BHA), provides unlimited, on-command activation cycles, optimal placement within the BHA in multiple configurations and real-time feedback via mud-pulse telemetry. The feedback from the reamer includes confirmation of blade activation status, health of the tool, and vibration and stick-slip measurements. Because of the flexibility of its placement in the BHA, the reamer can reduce the length of the rat hole to a minimum of 4 m compared to the standard 30 to 70 m in the same drilling run, eliminating the need for a dedicated clean-out run. The reamer also enables reliable and unlimited activation / deactivation cycles with each cycle taking less than 5 minutes, saving operational costs for the operators. The under reamer was successfully deployed to drill challenging 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections in the offshore Norway Oseberg South field. The 2497 m long 12 ¼″ × 13 ½″ section and 900 m long 8 ½″ × 9 ½″ section were both drilled to Total Depth (TD) in one run, with all requirements on directional control and Measurement While Drilling (MWD) / Logging While Drilling (LWD) met. The technology was proven to be a reliable and flexible hole enlargement while drilling solution that elevates drilling performance, reduces operational risks and lowers operational costs.

Surface casing jet-in and drill-ahead have become a common practice for deepwater drilling operation around the world. The main objective of the jet-in and drill-ahead operation is to set the surface conductor casing which is typically 36-inch in size and drill ahead the next hole section with the same bottomhole assembly (BHA). This paper reviewed 25 jet-in and drill-ahead BHA runs for deepwater drilling operations in Malaysia, with the intention to share the experience and findings. It is aimed to highlight the pertinent operating procedures needed for a successful jet-in and drill-ahead operation for future deepwater drilling operations, both in Malaysia and in other parts of the world. Multiple designs of BHAs in various sizes were imperative to achieve an optimum outcome for the jet-in and drill-ahead operation. The bit size, jet-in procedures, jetting speed, bit extension (stick out), assembly type, flow rate, formation and survey procedures are among other key aspects for a successful deepwater jet-in and drill-ahead operation. While all the deepwater jet-in and drill-ahead operations in Malaysia were performed with a mud motor BHA, a recent deployment of a rotary steerable system BHA in an ultra deepwater drilling operation had achieved a faster, verticality improvement to ±1°, a value-added outcome.

With the current market's high prices for drilling units and sophisticated directional and formation assessment services, low systems reliability or poor directional performance in the execution of complex wells (ERD, HPHT, Deep Water applications) can spell costly Non Productive Time (NPT) for operators. Over the past two decades, many Bottom Hole Assembly (BHA) models have been developed to address the directional performance issue, but their application in an operational environment has generally failed for lack of strong associated BHA analysis methodologies. This paper presents a unique automated methodology for Post Analysis of BHA directional behaviour. It is based on modern 3D analytical models, combining BHA, BIT and formation effects with highly flexible data management. Implemented in user-friendly BHA management software, it can be used to define a BHA run segmentation and to determine the influence of the BHA settings in particular geological formation blocks. The Post Analysis clearly displays the final results of the BHA (objectives and performances versus prediction window), highlighting any problematic intervals drilled. Already, the methodology has solved challenging directional performances issues, generating significant savings and optimising the learning curve process. The field applications referred to in the paper have demonstrated that, without a proper methodology, a model offers little added value. The examples discussed here from Total E&P affiliates deal respectively with Rotary, Rotary Steerable System (RSS) and Steerable Motor (SM) directional BHAs. Case studies have led to BHA and bit design modifications. The results were well beyond expectations, ensuring good well positioning through the reservoir by improving BHA stability and manoeuvrability. Efficient drilling (reduced sliding, improved hole quality) was also achieved with a single SM BHA in 17 1/2" applications during kick-off, and successive build-up and slant drilling intervals. The methodology and its associated BHA Management® software have proved an undeniably valuable tool for the drilling community. The model is also run at the well Pre Engineering stage to check BHA design proposals by making multiple sensitivity analyses and by fine-tuning solutions to the operational context. Finally, in an industry with high personnel turnover, the software's global data management system ensures good capitalization of know-how and ongoing learning curve benefits.

Summary High-torque, low-speed drilling mud motors are typically used to drive rotary-steerable systems (RSS) to improve the rate of penetration (ROP) of the RSS bottomhole assemblies (BHA). Downhole drilling dysfunctions are common when powered RSS BHAs are pushed to the limit for maximum drilling performance. High-frequency (HF) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box of the RSS, slow-rotating housing (SRH) of the RSS, bit box of the mud motor, and top subassembly (sub) of the mud motor to better understand drilling conditions in different shale plays throughout North America. Embedded sensors placed on the outer diameter of the BHA vs. centerline-mounted sensors give a different measurement response and a different vision of the actual dynamics being experienced in the BHA. The HF sensors were deployed in the in-house developed push-the-bit RSS and mud motors, allowing us to model the motor-assist RSS BHAs with analytical models and finite-element analysis models to predict the HF torsional oscillation (TO) and axial oscillation (AO) frequencies. The derivation of the high-frequency axial oscillation (HFAO) and TO analytical equations is detailed in the paper. In one of the example motor-assist RSS BHA analyses, the simulation results reveal that the fundamental high-frequency torsional oscillation (HFTO) frequency is 11.1 Hz whereas the fundamental HFAO frequency is 32.9 Hz, which is approximately three times higher than the fundamental-mode HFTO frequency. A good correlation was observed between the simulation result and the field data gathered from the HF accelerometer and gyro sensors embedded in the RSS and mud motors. Two new types of HF axial drilling dynamics with a polycrystalline diamond compact (PDC) bit—(1) the third-order-mode HFAO and (2) the harmonics of the HFTO coupled to the longitudinal axis—were discovered and reported in detail. One example in this paper shows that the dominant HFTO frequency shifts occurred in the middle of drilling a stand with no connection involved and no surface parameter changes. The examination of the time-domain signal reveals that (1) the “baseline” HFTO-induced tangential accelerations are due to the mud motor output revolutions per minute (RPM) (2) the variation of the HFTO-induced peak tangential accelerations comes from the drillstring stick/slip, which is transmitted to the drill bit through the mud motor, and (3) the 76 and 114 Hz HFTO-induced accelerations are both approximately in a sinusoidal waveform, except in the 3-second transition period, where the mixture of both frequencies is observed. The 114 Hz-HFTO-induced tangential acceleration measured at the bit box is coupled with the 0.16 Hz drillstring stick/slip oscillation. The analytical equation is provided to describe the HFTO coupled with stick/slip as an analogy to communication theory. In addition, the extensive modeling and field measurement of the HFTO and HFAO lead to the mitigation measure of the harmful HF drilling dynamics in motor-assist RSS BHAs. The proposed HFTO mitigation mechanism is modeled, simulated, and demonstrated in the paper. The latest-generation embedded HF drilling dynamics sensors are placed on the outside diameter of the BHA, as well as along the centerline of the BHA. The different responses of the sensors due to their placement are reported and analyzed. The quality of 1000 Hz continuous-sampled gyro data are discussed, comparing against low-frequency-sampled gyro data. Additionally, this paper shows the downhole HFTO-damping mechanism and lesser known drilling dynamics, such as HFAO with a PDC bit in detail. CORRECTION NOTICE: This paper has been updated from its original version to correct the provenance statement. In addition, the equation numbering on pages 567 and 568 has been corrected from Eqs. 9, 10, and 11 to Eqs. 5, 6, and 7.

Generally, deep gas workover/re-entry wells in Saudi Arabia are kicked off in the Sudair formation through a whipstock because the overlying base Jilh dolomite can flow with high pressure, which jeopardizes well control. Whipstocks are set deep in the 9 5/8-in. casing, after which the 8 3/8-in. and 5 7/8-in. holes are drilled to access the target Lower Carbonate and Sand reservoirs. Deeper kickoffs also avoid contact across the water-bearing Carbonate A, aiming for displacement across Carbonate B or C reservoirs. Isolation from Carbonate A is important for multistage fracturing completions as they are still not proven for the long-term isolation of water-bearing zones. Regardless of the deeper whipstock setting, the high dogleg requirements exceed the capabilities of conventional rotary steerable systems (RSS). Conventional steerable motors with high-bend housing and 70 to 80% of the sliding mode of drilling has been the only option to achieve such high dogleg severity (DLS/100ft). Drilling medium-radius wells with a conventional motor assembly requires multiple runs, wiper trips to clean the hole, and multiple reaming trips before running the liner. These operations result in poor drilling efficiency due to slow penetration rates and bit trips. A high build rate rotary steerable system (HRSS) was introduced as a solution for such challenges in the 8 3/8-in. and 5 7/8-in. sections. While the HRSS technology has been used before, this was the first time the HRSS kicked off vertically from a whipstock in Saudi Arabia or worldwide. The new technology allowed the kickoff point to be pushed further into the Sudair formation near the Sudair dolomite, reducing the risk from Jilh pressure and associated cost. The step change provided the option to slim the hole by eliminating the 8 3/8in. hole size, and kickoff was done in the 7-in. liner. Deployment of the HRSS allowed directly kicking off from a whipstock set vertically, eliminating the need for a dedicated steerable motor assembly run. Direct kickoff also meant eliminating the need for gyro tool for steerability, because conventional RSS tools could only be used outside the zone of magnetic interference, once sufficient separation from the mother bore was achieved. Consistent doglegs of more than 14°/100 ft were recorded; and the maximum dogleg was 17.44°/100 ft. Since then, this concept has been applied to other vertical re-entry wells and at an existing inclinations successfully in the 8 3/8-in. and 5 7/8-in. sections in Saudi Arabia and worldwide. The scope of the paper is limited to wells in Saudi Arabian deep gas wells only. The average rate of penetration (ROP) across this build section shows a 137% improvement over the ROP for conventional motor bottom-hole assemblies (BHA) for similar build sections. Eliminating the 8 3/8-in. section, avoiding the hazards of drilling in Jilh and Sudair formations, saving the motor trip to kick off from the whipstock, and improving ROP resulted in significant savings. This step change in drilling performance was realized by a thorough understanding of local drilling conditions and indepth analysis that enabled efficient execution.

There are four key technical issues to be addressed when drilling directional wells with steerable bits and bottom hole assemblies: maximizing hole quality, addressing tool face control, eliminating bit and assembly vibration, and predicting hole curvature or build rates. Hole quality1 and tool face control2-7 have been covered in several previous SPE papers, as has bit and assembly vibration elimination8-9. This paper covers the recent development of a fundamental model for the prediction of hole curvature based on measured bit response and modeled bottom hole assembly behavior. Bit side cutting is a nonlinear function of side force, gauge design, rotary speed, rate of penetration, rock strength, and cutter dull state. To characterize the bit's side cutting response, a series of tests are run in a full scale drilling simulator10 under a variety of drilling parameters and sideloads. Axial and lateral bit trajectories are measured and a response curve is generated. The bit side cutting angle measured in the lab, is equivalent to bit tilt calculated on a bottom hole assembly (BHA). Several hundred tests have been run to measure the response of numerous bits. These response curves are then used to relate bit performance to BHA response. The BHA is modeled with a finite element analysis program over the range of hole curvatures and tool settings which define the operating envelope for the tool. The result of the analysis is a bit side force to bit tilt response surface for the tool over its operating range. The response curve for the bit and the response surface for the BHA are then plotted on the same set of axes. The intersection of the two graphs represents the steady state response of the system and is used to predict the achievable hole curvature of the bit-BHA system. This work shows that bits often selected for rotary steerable systems are more laterally aggressive than required of the BHA to achieve the desired hole curvature. The model has been verified with full scale field tests. While this work was originally developed for PDC bits and rotary steerable systems, the fundamental model can be applied to all types of bits and drilling systems. It has also been applied to motor and vertical drilling systems with PDC and Impregnated bits.

The bottom hole assembly (BHA) of a modern drill string for directional drilling mainly comprises a drill bit, a rotary steerable system, and a measurement while drilling tool. The tools and subs used on a BHA are screwed together through rotary shouldered threaded connections. Each connection is made up with a pin and a box. These connections are the weakest links when the BHA undergoes a large number of revolutions in a curved well section. When the fatigue life of a connection is consumed during a drilling job, a twist-off would occur, which could result in an enormous amount of non-productive time and possibly loss of the bottom BHA section in the hole. Cold rolling has proven to be able to improve fatigue resistance of a threaded connection by pressing a rolling wheel against the thread root and generating a layer of compressive residual stress at the root. Understanding how cold rolling improves fatigue resistance of a threaded connection is important for optimization of the rolling parameters and prediction of the BHA service life in a given drilling condition. In this paper, a predictive method is presented for fatigue life of a cold rolled threaded connection. A finite element model was developed to simulate the cold rolling process. The resulting deformation and stress states at the root were carried over through makeup of the pin and the box as well as through cyclic bending of the connection. The fatigue life predictions were found to be in favorable agreement with the experimental measurements from full-scale fatigue tests at different bending moment levels applied.

In an extended-reach and horizontal well drilling environment, stick-slip becomes increasingly problematic with smaller-diameter and longer drillstring. Surface detection of the bottom-hole assembly stick-slip and vibration becomes ever more difficult. A Real-time Stick-slip and Vibration Detection (RSVD) system was incorporated into a rotary-steerable system (RSS), to increase drilling efficiency in deep wells and to protect the RSS and the MWD/LWD tools from harmful vibrations. Bit/BHA instability often results in excessive vibration and stick-slip problems, which lead to BHA component failure, poor directional results and excessive wear/damage to bits. This system is a unique near-bit vibration sensor integrated into the RSS, featuring detection of the three principal modes of drillstring vibration: torsional, lateral and axial. The sensor system sends the detected stick-slip severity to the surface in real time so that operators can change drilling parameters if harmful downhole conditions are detected. Additionally the real-time drilling data were remotely available to a multi-disciplinary drilling optimization team consisting of engineers and researchers. This sensor system has been extensively tested and proved to be effective with the 8 ½-in.-hole-size RSS in various wells, including vertical and horizontal, both onshore and offshore. This paper reviews the harmful stick-slip and vibration conditions in smaller-hole-size wells and how the RSVD system improved penetration rate and prolonged the optimum performance of the drill bit, bottom-hole assembly (BHA), MWD/LWD, and RSS in various situations. Through the integrated sensor and team approach, the ability to detect poor borehole conditions and/or BHA instability due to vibration allows RSS operators to take timely remedial action before downhole RSS failure occurs. As a result, the performance and survivability of the RSS has been remarkably improved.

The offshore project in Egypt East Mediterranean delivering complex deepwater wells. Because of geological conditions there is a need to set two casing strings in between 20-in. surface casing and 9 5/8-in. production liner. This cannot be done with conventional drilling of hole sections with bit size diameter. The hole enlargement was required in both sections to accommodate 16-in. intermediate liner and 14-in. production casing. Besides, the reservoir section drilled below 9 5/8-in. production liner also required hole enlargement due to completion design. Complex deepwater well architecture called for advanced bottom hole assembly design and advanced engineering during planning and execution phase. There were three sections that required hole enlargement which could be done in different ways. However, different ways have different risks and execution time. The simplest way is the drilling the bit size diameter hole and make additional trip to perform hole enlargement has the longest execution time as well as undesired risks with not properly stabilized bottom hole assembly (BHA) while performing underreaming only operation. A more complicated way of delivering enlarged hole section is to use one underreamer in BHA placed above measurement and logging while drilling (MLWD) tools. This technique requires very short distance of risky underreaming only operation since the entire section is drilled and underreamed simultaneously, however this technique also requires additional trip to perform rathole elimination. The most complex approach delivering enlarged section and performing rathole elimination in a single trip is utilizing two underreamers in BHA. This technique introduces additional BHA complexity and operational risks; however, it can be successfully implemented with proper job planning and execution in place which was done in current project. Additional project challenges such as directional performance in soft unconsolidated formation of 3D well profile were successfully resolved by introducing point-the-bit rotary steerable system (RSS). The dual underreamers BHA technique in which ball activated underreamer placed above MLWD tools and indexing type (flow activated) underreamer placed between MLWD tools and RSS worked well. 17 ½ × 20-in., 14 ¾ × 17 ½-in. and 8 ½ × 9 7/8-in. hole sections successfully delivered intersecting all well geological targets within required tolerance and saving a trip per section in extremely expensive deepwater operations. This technique was accepted for future deepwater projects in Egypt. The successful implementation of this technique in recent deepwater campaign with the 68 % drilling performance improvement shows the benefits and qualitative acceptance for other Mediterranean offshore projects. The knowledge and lessons learnt from the project can be applied to other worldwide projects with identical or similar casing design requirements.

The objective of pilot testing was to optimize horizontal well construction cycle by decreasing the number of casing strings. The testing involved drilling of 13 wells, in which only production casing was run in hole instead of intermediate casing and a liner. The key issue during drilling was failure of measurement tools due to high vibration. This paper covers decisions and actions being made to get a well with new casing design successfully drilled. To mitigate the issues, the bottom hole assembly (BHA) behavior was modeled using a proprietary software for static and vibration analysis. Relevant diameters of stabilizers and drilling modes were selected. The interpreted computations were successfully used for drilling further wells. For comprehensive approach, an optimal bit design was selected vibration mitigation wise. Three-axis vibration sensors installed in the BHA enabled selecting of optimal drilling modes in real time. Drilling of triple casing wells showed reduction in actual well construction time compared to quadruple casing by 20% on the average. The record-setting well was drilled in 8.6 less days compared to a similar 4-string well. Furthermore, BHA with mud motor was used, which is less expensive compared to a BHA with Rotary Steerable System (RSS). The three-string design was used at the fields in question for the first time. The accumulated experience makes it possible to use this technology at other fields, where horizontal wells are drilled.

Slick-slip (SS) and lateral shocks are harmful to many expensive downhole tools such as rotary steerable systems, and downhole measurement and logging tools. Due to this concern, an asymmetric vibration damping device has been engineered to reduce these specified vibrational modes. This tool is uniquely specialized that, when placed and ran with the recommended drilling parameters, reduces stick-slip tendencies as well as dampen lateral shocks by placing the drill string near the tool in Forward Synchronous Whirl (FSW). As a result of placing the BHA (bottom hole assembly) into FSW, other harmful vibrational modes such as chaotic whirl and backward whirl are prevented from occurring. Stemming from the exclusive geometry of the tool, the tool will interrupt harmonic modes during rotation that can lead to harmful shocks and SS. Extensive research has been performed in laboratory and field testing using the vibration damping tool, and its success has been proven in multiple deep water applications (primarily with hole opening BHA’s), but also on land with bi-center bits. Recently, a new approach was undertaken, utilizing two vibration damping tools in a single BHA. This was intended to control vibrations and reduce shocks that were causing extensive damage to Rotary Steerable System (RSS) horizontal applications in North America. The initial trial wells used the dual placement within the vertical and horizontal sections, drilling into the Cotton Valley formation in North Louisiana. These applications have historically seen very high vibration levels due to both the trajectory and challenging formations.

Directional drilling in the Highlands of Papua New Guinea is extremely challenging, especially in the intermediate 12!" hole section. 12!" drilling is through medium strength claystones, where severe tectonic breakout occurs. This results in an extremely poor quality, ledged, ovoid, over gauge wellbore. Traditionally positive displacement motor (PDM) bottom hole assemblies (BHAs) were used to directionally drill in these difficult hole conditions. Drilling performance was far from ideal. Steering penetration rates were typically 50–80% less than those obtained when rotating, even at low inclination, with weight stacking, hang up and motor stalls becoming progressively worse with depth. Additionally, the motor pressure drop placed a hydraulic limitation on flow rates. This limitation handicapped hole cleaning optimisation, which was critical if the abundant large 1–3" cavings generated by wellbore breakout were to be removed from the hole. An initial attempt to introduce a rotary steerable system to improve penetration rates and hole cleaning had been unsuccessful. It was only with the innovative introduction of a rotary steerable system originally designed for soft formations that success was obtained. Modifications to the original system specific for this new environment brought further performance improvements. Performances will be analysed from a series of wells in Papua New Guinea to demonstrate the improvement obtained by the introduction of this new directional drilling technology. ROP improvement, dogleg capability and improved drilling hydraulics will be presented.

This paper outlines the development of a gas field in a mature carbonate reservoir via an onshore Extended Reach Drilling (ERD) well in Abu Dhabi, featuring a 24,000-foot lateral section. The operator aimed to achieve a drilling rate of 1 mile per day. However, both the landing and lateral sections presented significant drilling and geological challenges, including subsurface uncertainty, rig limitations, high downhole temperatures, and Effective Circulating Density (ECD) management. In addition, maintaining 100% reservoir contact required frequent well path adjustments via manual geosteering, introducing performance variability and human error. These challenges constrained the rate of penetration (ROP) and increased overall well costs. This paper presents a customized drilling and subsurface solution combined with a downhole drilling automation system that enabled 100% reservoir contact and saved 4.6 drilling days. A new Intelligent Rotary Steerable System (RSS) was deployed in combination with an Ultra High Torque Motor to maintain consistent weight on bit (WOB) and differential pressure (>500 PSI while drilling) along with compatible bit to achieve target ROP. Deep Reservoir Mapping tools were critical in navigating the thin carbonate reservoir, enabling real-time identification of formation dip changes and reservoir boundaries above and below the wellbore, contributing to higher ROP. Autonomous downhole directional drilling tools allowed continuous well-path adjustments, enhancing placement precision within the reservoir. Integration with automated geosteering software reduced decision-making cycle time from ∼15 minutes to <5 minutes. The closed-loop automation also minimized RSS setting changes, promoting smoother wellbores and facilitating efficient deployment of the production Bottom Hole Assembly (BHA), while reducing invisible lost time. Vibration mitigation was achieved through the combined use of Motorized RSS and Anti-Stick Slip tools. The well reached total depth (TD) at 34,127 feet Measured Depth (MD) successfully with 23,095 feet of 8½" lateral section drilled, and 100% reservoir contact achieved. A record onshore daily footage of 4,076 feet was attained in the UAE. This marked the global debut of the new 6¾" Motorized RSS. Integration of the autonomous downhole directional drilling system with the Motorized RSS and Deep Reservoir Mapping enabled precise control throughout the lateral section. The solution reduced RSS control interventions, improved ROP by 47%, and significantly enhanced the speed and accuracy of geosteering versus offset wells. The successful integration of automated and customized drilling technologies represents a transformative step in ERD well execution, significantly reducing well time and increasing drilling efficiency. The scalable and repeatable nature of this autonomous downhole drilling solution offers a robust framework for future field development in similarly complex environments.

Summary High-frequency torsional oscillations (HFTO) continue to be a challenge for rotary steerable system (RSS) performance. While ruggedization of downhole tools has improved significantly over the years and has enabled tools to survive these violent events, excessive vibrations can still lead to drilling inefficiencies, shortened lifespans of components (increased replacement rates during tool servicing), or occasionally errors in sensor readings. This study shares some key observations during HFTO events including relationships between other vibration modes, behavior with other commercially available vibration mitigation tools, mitigation strategies, and practical limitations. Case histories are presented highlighting HFTO behavior and what this vibration mode looks like within drilling data. Real-time, log, and high-frequency data are all examined to illustrate the differences and variability of each. Mitigation strategies are addressed in detail, looking at parameter adjustments, changes to the bottomhole assembly (BHA), and different types of dedicated vibration mitigation tools. Benefits and shortcomings are shown for each. The results show the benefit of planning for this type of vibration event and illustrate how the specific drilling application can impact the dynamic response of the BHA. Some unique dynamic characteristics have been observed and are discussed. One such behavior that has been noted is the presence of a torsional beating phenomenon when utilizing a torsional spring-like type of vibration mitigation tool. The physics of this behavior is further examined through detailed modeling and simulation, accurately replicating the observed field measurements. General HFTO observations over the years have also led to the development and implementation of a new at-bit viscous damper type of HFTO mitigation device. Due to the success of this at-bit mitigation device, it has been integrated directly into the rotary-steerable system (RSS), removing the need for additional tools or connections in the BHA, and is now a standard technology on all RSS deployments. The data presented in this study is the first documented case of a torsional beating phenomenon during an HFTO event. In addition to this, general HFTO observations are shown in a concise format to share the knowledge gained thus far with this type of vibration. The success resulting from the implementation of the only at-bit HFTO mitigation device is also highlighted.