Step-Change Performance Improvement in Wellbore Sidetrack Operations: A Kuwait Dual-Casing Exit Case Study

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189910, “Operational Improvements Using a Coiled-Tubing-Telemetry System for a Complex Milling Operation in Shut-In Conditions,” by P. Correa, D. Parra, S. Craig, SPE, S. Livescu, SPE, A. Yeginbayev, and Z. Nadirov, Baker Hughes, a GE Company, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. When a new horizontal well in Asia was incapable of unassisted flow, coiled tubing (CT) was selected for the perforation and stimulation intervention. Mechanical isolation was required to ensure that the stimulation fluids entered only the new zones. Accurate depth control was required for three runs: setting two composite bridge plugs (CBPs), deploying CT-conveyed perforating guns for opening two intervals, and milling out the two CBPs without taking returns to surface. For the first time, a tension, compression, and torque (TCT) subassembly was used to improve the milling operation. Introduction CT telemetry (CTT) systems have proved to be effective in enhancing operations by providing real-time monitoring of downhole data including depth, pressure, temperature, force, and torque. For data transmission from downhole sensors to surface, these telemetry systems can use either insulated wire or optical fiber. With insulated wire, power can be transferred from surface to the downhole sensors. With optical fiber, downhole batteries are required in the bottomhole assemblies (BHAs) to power the downhole sensors. When compared with braided systems using the 0.125-in. insulated electrical cable (Fig. 1), the main advantages of the CTT system are its low weight and the fact that balls can be pumped through the CT. A small wire has a minimal effect on the CT cross-sectional area. Balls up to 7/8 in. in diameter do not become stuck, and there is a minimal effect on the CT fluid pressure drop. Description of the Wire CTT System The 0.125-in.-wire CTT system has several components, such as surface hardware and software; the ⅛-in. insulated electrical conductor inside the CT string; and a BHA with different sizes, including 2.125, 2.875, and 3.5 in. The 2.875-in. BHA with three subassemblies is shown in Fig. 2. The 2.875-in. sensor assembly has the following components: Tubing end connector Head that secures the wire downhole, seals the exterior of the wire, and provides downhole electrical connection 0.875-in. ball-operated wire-release mechanism Double-flapper check-valve housing Electronic module with a casing collar locator (CCL) and pressure/temperature sensors (internal/external) Motorhead section, where a ¾-in. ball-release mechanism is located followed by a circulating port activated with 0.625-in. balls Burst-disk section enabling 0.5-in. balls to pass through to activate downhole tools

The paper presents two intelligent intervention systems, deployed on drill pipe and coiled tubing respectively, and showcases how these systems improve intervention efficiency, reduce operational risks and optimize production in mature asset. Interventions are more challenging than ever, driven by the increased well complexity and reduced margin for error. The conventional intervention approaches, which are mostly experience based and involve significant amount of guesswork, are inadequate. Two new intervention systems, enhanced by real-time downhole insights and deployed on drill pipe and coiled tubing respectively, were developed to overcome these challenges. Three cases are presented in this paper: 1) optimize plug & abandonment (P&A) and slot recovery operations with smart intervention system in North Sea, 2) increase well life by employing intelligent coiled tubing enabled intervention services in Caspian Sea, and 3) Optimize re-entry stimulation with intelligent coiled tubing system in Middle East. The intelligent intervention systems were proven to be critical and valuable to the success of above-mentioned intervention operations. For a P&A and slot recovery operation in an aging, deep and highly deviated well in North Sea, the drill pipe deployed smart intervention system was used in 4 different runs to deliver real-time insights to mitigate risks and ensure operational success. Equivalent Circulating Density (ECD), Weight on Bit (WOB) and torque readings increased confidence in making real-time decisions to respond to encountering total loss and obstruction during packer milling and wellbore cleanup operations. For the casing exit operation, real-time Casing Collar Locator (CCL) service enabled optimal whipstock placement, and WOB, torque and vibration data ensured a smooth and efficient casing window milling process, delivering a successful 7-in casing exit at 14,993-ft and 65 degree inclination. The intelligent coiled tubing system enabled an otherwise challenging and highly risky intervention operation to increase the life of a well in Caspian Sea. Uneven gravel packing in several sections allowed incoming sand to damage the screens and begin filling the wellbore. The intelligent coiled tubing intervention system not only assisted in setting a bridge plug at the depth of 13,481-ft, but was critical in enabling the setting of six expandable steel patches over two different intervals. Downhole readings, such as CCL, pressure, temperature, tension, compression and torque were critical to the success of the job. Total time to perform the entire operation was 286 hours with no Non Productive Time (NPT) and sand production was reduced significantly to an acceptable level. Finally, the intelligent coiled tubing system was employed in a rigless Thru-Tubing remedial stimulation operation in a horizontal well in Middle East to selectively target, isolate, and treat each Inflow Control Device (ICD) with an acid wash solution, re-establishing connectivity with the production zones. Real-time CCL helped to establish precise bottom hole Assembly (BHA) placement, and real-time parameter controls enabled more efficient system control and verification of inflatable element inflation and deflation. 13 successful Inflatable Straddle Acidizing Packer (ISAP) stages were achieved in a single coiled tubing (CT) trip and the total operation lasted only 21 hours, treating 11 intervals with flawless execution and zero no NPT.

Horizontal well completions are often equipped with Inflow Control Devices (ICDs) to optimize flow rates across the completion for the whole length of the interval and to increase the oil recovery. The ICD technology has become useful method of optimizing production from horizontal wells in a wide range of applications. It has proved to be beneficial in horizontal water injectors and steam assisted gravity drainage wells. Traditionally the challenges related to early gas or water breakthrough were dealt with complex and costly workover/intervention operations. ICD manipulation used to be done with down-hole tractor conveyed using an electric line (e-line) cable or by utilization of a conventional coiled tubing (CT) string. Wellbore profile, high doglegs, tubular ID, drag and buoyancy forces added limitations to the e-line interventions even with the use of tractor. Utilization of conventional CT string supplement the uncertainties during shifting operations by not having the assurance of accurate depth and forces applied downhole. A field in Saudi Arabia is completed with open-hole packer with ICD completion system. The excessive production from the wells resulted in increase of water cut, hence ICD's shifting was required. As operations become more complex due to fact that there was no mean to assure that ICD is shifted as needed, it was imperative to find ways to maximize both assurance and quality performance. In this particular case, several ICD manipulating jobs were conducted in the horizontal wells. A 2-7/8-in intelligent coiled tubing (ICT) system was used to optimize the well intervention performance by providing downhole real-time feedback. The indication for the correct ICD shifting was confirmed by Casing Collar Locator (CCL) and Tension & Compression signatures. This paper will present the ICT system consists of a customized bottom-hole assembly (BHA) that transmits Tension, compression, differential pressure, temperature and casing collar locator data instantaneously to the surface via a nonintrusive tube wire installed inside the coiled tubing. The main advantages of the ICT system in this operation were: monitoring the downhole force on the shifting tool while performing ICD manipulation, differential pressure, and accurately determining depth from the casing collar locator. Based on the known estimated optimum working ranges for ICD shifting and having access to real-time downhole data, the operator could decide that required force was transmitted to BHA. This bring about saving job time while finding sleeves, efficient open and close of ICD via applying required Weight on Bit (WOB) and even providing a mean to identify ICD that had debris accumulation. The experience acquired using this method in the successful operation in Saudi Arabia yielded recommendations for future similar operations.

Objectives/Scope Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a >90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5″ liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%. Methods, Procedures, Process The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew. Results, Observations, Conclusions An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore. In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint. Novel/Additive Information Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.

This paper evaluates the use of real-time telemetry systems in coiled tubing (CT) operations to improve performance in extended reach and multilateral wells. The objective is to reduce downhole uncertainty, such as unknown Weight on Bottom Hole Assembly, Tool Pressure, and Depth location by integrating downhole sensors with reliable surface-to-downhole data transmission. These technologies are key for navigating complex extended well paths and improving decision-making during interventions. The study focuses on conductor-based telemetry systems that use insulated wire inside CT to send data and power between downhole tools and the surface. Case studies include jobs using extended reach tools (ERT), hydraulic multilateral tools (HMLT), and sensors such as gamma ray (GR), casing collar locator (CCL), tension, and pressure gauges. These systems were tested in high-vibration and long-reach environments. The setup enabled accurate depth tracking, lateral entry, and real-time response to downhole events, such as sticking or pressure spikes, through live monitoring of tool behavior and formation interaction. Field and Technical results show that combining telemetry with advanced downhole tools improves CT operations in complex wells. In extended reach wells, the telemetry system reliably transmitted data even when ERTs were creating strong vibrations. This helped maintain continuous tool feedback and supported depth tracking using CCL and GR tools. In multilateral wells, telemetry-enabled HMLTs allowed operators to accurately enter specific lateral branches, reducing risk of wrong entry or tool deviation. Real-time readings of tension and pressure allowed early detection of downhole problems like pipe sticking or fluid losses, enabling quick adjustments. Across several jobs, this setup reduced non-productive time and improved the success rate of interventions, especially in long horizontal sections and branched wells. The system also improved confidence in tool positioning, making it easier to perform tasks like stimulation, cleanout, and re-entry. These benefits show that reliable telemetry can extend the reach of CT operations and help teams manage difficult well geometries more safely and effectively. This paper presents new field-based evidence on how real-time telemetry, combined with mechanical and sensor tools, improves CT performance in complex well environments. The approach provides better control, safer operations, and improved results in extended reach and multilateral interventions offering a practical upgrade to traditional CT systems and filling a key gap in current well intervention practices. extended reach and multilateral interventions, making them invaluable in all oil and gas environments.

This paper describes and analyzes the development and ongoing field trials of a Real Time MWD Coiled Tubing Drilling System. The new system holds great promise for advancingthe state of coiled tubing drilling for certain applications. The system is designed for through-tubing, short radius re-entry and drilling highly deviated wells as horizontal laterals to a geologic target with minimum wellbore tortuosity. Currently, 4- 1/2' production tubing is the smallest re-entry candidate. Real time MWD and Bottom Hole Assembly (BHA) control is achieved by the use of a combination hydraulic and electric umbilical internal to the coiled tubing (CT), allowing continuous data collection and selective surface control of the BHA components, This communication line allows orientation in 10' increments (or less) while drilling, applies weight-on-bit and operates a reusable circulating valve. In addition, the umbilical provides real-time monitoring of weight-on-bit, circulating pressures of the drilling fluid internal and external to the BHA, dedicated hydraulic system bottom hole pressure, downhole temperature and survey data from logging equipment. Introduction In. June of 1992, Cameo Products & Services formed a coiled tubing drilling team that consisted of engineering representives from Reed Tool Company, Hycalog. Cameo Coiled Tubing Services and Cameo Products & Services. The team's objective was to investigate the technical and economic viability of drilling with CT. Invitations were extended to experts and consultants with experience in slim-hole and CT drilling to address the team on existing and potential problems. The major technical difficulties identified were:CT bucklingpipe fatiguelack of real-time dataweigh t-on-bitreactive torquedependable emergency release from the BHAability to drill under balanced Key to solving these technical difficulties is the ability to provide hydraulic and electric power to the BHA via an umbilical installed in the CT, The umbilical allowed the development of hydraulically and electronically powered down hole tools and instrumentation that comprise the BHA. Purpose built surface equipment designed specifically for the BHA was developed to provide surface power and selective controls. After conceptual drawings of the BHA were completed, Cameo and BP Exploration (Alaska) began a development project for specific application at Prudhoe Bay, where CT drillingtechnology is considered to be a very valuable tool. Many of the existing wells at Prudhoe Bay could potentially benefit if replaced with horizontal completions. CT drilling offers the potential of achieving horizontal sidetracks without pulling the existing tubing. This offers a significant cost advantage over conventional sidetracks.

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 conventional drilling approach of employing a drillstring and bottomhole assembly with bit for drilling purposes and eventually running a casing string includes several tripping operations that leave the wellbore open for extended periods of time as an alternative to drilling-with-casing operations where the bottomhole assembly is attached to the casing. This eliminates additional drillstring tripping as drilling and running casing are performed simultaneously. This type of application reduces the number of string trips needed to complete a section, thus saving operational time and associated costs. As the diameter of a casing is larger than a drillstring, this method generally increases the Equivalent Circulating Density (ECD) as pressure losses increase owing to the reduction of the open hole and casing string annulus area. Casing directional drilling operations provide a much narrower drilling window with regards to restrictions in the annulus thus increasing the chances of reaching fracture pressure compared with conventional drillstring operations. To negate the resultant increase in ECD, the rheological profile of the drilling fluid must be designed appropriately. This paper discusses a unique oil-based drilling fluid system weighted with treated micronized barite slurry (TMBS) that has more recently been developed and used successfully in the Eldfisk field of the Greater Ekofisk area, Norway. The drilling fluid system provides low viscosity and a relatively low flat rheology, reduced torque values, and superior sag stability, thus delivering a fluid of low ECD contribution, low-pressure peaks, very effective hydraulics performance and static stability. These exceptional fluid characteristics make the system an excellent solution for drilling sections where the difference between pore pressure and fracture pressure is narrow. This was particularly so in this case where the stability of the fluid from sag potential was crucial for the improved success of the drilling-with-casing operation. Any solids sag onto the latching tools or bottomhole assembly (BHA) with the casing could have caused interference. The system had been used before for differing hole conditions including managed-pressure drilling and extended-reach wells, in high-temperature, high-pressure (HTHP) wells, and now with competence in a casing directional drilling operation.

For more than 50 years, coiled tubing (CT) has been an intervention technology primarily used to maintain or increase production. In the last 10 years, CT telemetry systems have been used for such applications as milling, stimulation, well cleanouts, gas lifting, camera services, logging and perforating, increasing certainty, improving safety and efficiency, and reducing time and cost. In this paper, a review of a CT telemetry system with 2 ⅛-in. tube wire, including the technology development and field application, is presented for the first time. Unlike conventional CT for which surface-measured parameters, such as CT weight and length and pumping pressure, are the only parameters available to monitor the operation's progress, CT telemetry systems provide real-time monitoring of downhole data such as pressure, temperature, depth, etc. The CT telemetry system described in this paper consists of the surface hardware and software, a 2 ⅛-in. tube wire inside the CT connecting the surface equipment and the downhole tools and sensors, and a versatile bottomhole assembly, designed in three sizes (i.e., 2 ⅛-, 2 ⅞-, and 3 ½-in.). The 2 ⅛-in. tube wire has the dual purpose to power up the downhole sensors and to transfer the real-time downhole data to surface. The sensors available are a casing collar locator (CCL), two pressure and temperature transducers (capable to measure downhole data inside and outside of the tool), and tension, compression, and torque gauges. In addition, cameras with front and lateral views and flow-through capabilities could be used. One of the advantages of this CT telemetry system is its versatility: switching between applications is as simple as only changing parts of the bottomhole assembly, significantly reducing the operational time and cost and increasing safety. Another advantage stems from the downhole data certainty in real time, as the CT field crew can promptly intervene based on dynamic downhole events. A state-of-the-technology review of the 2 ⅛-in. tube wire CT telemetry system is presented for the first time. The many benefits of the real-time monitoring of the downhole parameters during such CT applications as logging, zonal isolation, collapsed casing identification, scale removal, cleanout and perforation, milling, confirmation of jar activation during fishing jobs, etc., are also summarized. Many of these applications were performed together and the real-time monitoring of downhole data increased the job efficiency, control and safety and reduced the operational costs by simplifying the operational procedures and equipment. The paper summarizes the results stemming from 10 years of global experience with the 2 ⅛-in. tube wire CT telemetry system. A new case history involving the 2 ⅛-in. tube wire CT telemetry system and a vibratory tool is presented for the first time. As currently there is a strong inertia to automate the drilling operations, all details presented in this paper show that the CT telemetry systems are poised to become standard technologies for all CT operations in the not-so-distant future.

When drilling operations commenced in Sao Francisco basin, the operator knew the exploratory well campaign would present a major investment. However, as operations progressed the well costs and time exceeded assessments mainly drilling the 8½″ production hole section through two hard and abrasive formations. Due to the unconventional nature of the reservoir, well costs must be held to a minimum in the exploration phase to ensure each project is economically viable. To accomplish the objective, several tool technologies were analyzed and proposed with the aim of reducing down-time and tool failures. One of the main issues identified was the high level of shock and vibration (S&V) observed while drilling the Macaubas and Paranoa formations. The environment had a negative impact on drilling efficiency and contributed to tool failures and excessive wear on BHA components leading to additional trips and preventing the operator from achieving higher ROP and run lengths. After an engineering analysis, the drilling team determined the root cause was BHA/bit whirl while along with several other contributing factors related to the challenging hard and abrasive formations. Based on this information, the provider recommended using a roller reamer in the bottom hole assembly (BHA), to mitigate shock and vibration and improve drilling efficiency. Results were positive and the roller reamer reduced NPT and overall well costs in this economically sensitive play. Roller reamers are currently part of standard packed BHA and are being used as a reference for operators experiencing the same type drilling dysfunctions.

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.

This paper provides insight on planning and equipment-selection processes to successfully ream and drill in 9 5/8-in. casing through a water-sensitive shale formation, followed by a two-stage cement job to isolate lost-circulation zones. Proper placement of cement all the way to surface would be essential for providing an additional annular barrier to prevent casing-to-casing annular gas migration. Selection of the equipment is dictated by the operation to be performed (i.e., drilling new hole versus reaming a tight section), the type of reamer or drill shoe used, selection of specialized drilling tools and centralizers, along with stage cementing tools with integral packing elements, among many other requirements. Current drilling with casing (DwC) applications allow for plastering cuttings to the wellbore wall, creating a barrier that minimizes fluid losses. It also reduces the annular clearance between the casing and the wellbore wall, thus improving velocity and hole cleaning compared to conventional drilling practice. And, by introducing a stage cementing tool with an integrated packer, the annular barrier can be set inside the previous casing string to facilitate two-stage cementing, thus enabling full circulation, with cement to surface. Currently, 23 wells have been completed using this approach. A few of these jobs stand out. In one case, the casing string was reamed 501-ft (153-m) for 7.75 hours at speeds between 20 and 25 rpm using an eccentric nose shoe with carbide cutting structure on the exterior. Following the first stage of cementing (with zero returns received at surface), the team inflated the packer element of the stage cementing tool and initiated the second stage of cementing. During a second bottoms-up circulation, returns at the surface indicated successful setting and a successful second-stage cementing job in a reamed hole. In another case, the string was reamed 316 ft over 3.75 hours with 20 RPM rotation, until the bottom of the conventionally drilled hole was reached. Using a specialized drilling shoe, the string was then drilled 301 ft over 14.75 hours with 20 to 50 RPM rotation to the desired depth. Based on the broad success of this technique, the service provider built a detailed database of field jobs. This database provides a better understanding of the parameters and recommendations for this application. These insights include how to improve standoff and minimize damage to the element while rotating by using rigid centralizers, implementation of shouldered connections to allow torque transmission without compromising thread integrity, recommended RPMs and torque based on internal and external components of the tool, among others. This well construction technique has saved hundreds of hours of rig time by enabling operators to drill with the two-stage cementer (with integral packer in the string) instead of having to continue drilling a problematic open hole with a conventional assembly and run casing afterwards. By performing successful two-stage cement jobs, the need to perform top cement jobs due to total losses is eliminated. And finally, the technique eliminates the need for conditioning the hole to allow casing placement at TD, an operation that would require an additional trip with a dedicated bottom hole assembly (BHA).

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.

A drill collar is a thick-walled tubular component that provides a passage to pumping drilling fluids and a mechanical protection for sensing, power supply, communication, and control devices. Multiple collars can be screwed together along with other downhole tools to make a bottomhole assembly (BHA). Radially oriented ports are often used in the wall of a collar for various reasons. These ports could be susceptible to fatigue-induced failures when a BHA has to undergo a large number of revolutions in a curved well. A cracked port could result in leakage, thereby causing flood damage to the internal devices, which are supposed to be protected from drilling fluid. Understanding the risk of fatigue cracking of a collar port is an important part of BHA design and well planning. The total fatigue life of a port can be considered as a summation of the crack initiation life, which is consumed to nucleate a dominant crack with a minimum detectable size, and the crack growth life, which is measured as the crack grows from the minimum detectable size until it reaches the seal. Prediction of the initiation life is expected to be conservative due to the many uncertainties involved. As a result, solely relying on the predicted initiation life to retire a port and the entire collar is not cost effective. A more economical way of port fatigue management is to compute the crack growth life based on a minimum detectable crack size and use this life as the inspection interval. If a crack is detected during an inspection, a port is declared as failed because a cracked port cannot be repaired with the same strength. Otherwise, the port can last at least until the next scheduled inspection. In this study, a fracture-mechanics-based method is developed to predict the fatigue crack growth (FCG) life of a collar port subjected to constant-amplitude cyclic bending. It is assumed that a prescribed corner crack with a minimum detectable size lies in a plane perpendicular to the collar axis. It intersects with the collar outside surface and the port wall surface. The crack front follows an elliptical function. The stress intensity factors (SIFs) along the crack front are numerically computed with finite element analysis (FEA) at the two endpoints, respectively. A response surface of the SIF is generated by assigning a set of predetermined crack fronts based on incrementally advancing positions of the two endpoints. It is then used to determine the SIFs at these points throughout all crack growth increments. The Paris law is utilized to describe the FCG rate of the collar material, whereby, along with the SIFs computed, the crack growth life and the associated crack front shape are incrementally determined. To validate the newly developed method, a test apparatus is developed to apply constant-amplitude cyclic bending to a collar specimen that contains a through-hole in the middle. The predicted growth rate for the crack on the collar outside surface agrees favorably well with the test data. The computed crack front before rupture is also in good agreement with the experimental measurement.

Operators of Gulf of Mexico (GOM) wells frequently reported overtorque issue of bottomhole assembly (BHA) connections when drilling the 26-in. section through salt. Such overtorque often leads to costly tool damage beyond repair (DBR), additional trips, and high nonproductive time (NPT). The average DBR cost per BHA can be as high as USD 1 million. Combined with a complete BHA roundtrip, it can easily cost more than USD 3 million for operators if such failure happens. This has been a problem for several years and has caused significant damage: In 2014, of 15 26-in. PDC bit runs in salt, 40% had overtorque connections and 20% led to DBR. This paper discusses how an integrated multidisciplinary team identified the root cause of and the solution to the overtorque problem. Torsional vibration was believed to be the cause of such failure. Comprehensive drilling dynamics simulation software that is based on empirical bit design knowledge was used to design a new bit to reduce the vibration. A newly developed high frequency downhole recording tool used in the 26-in. section recorded high-frequency torque, acceleration, and RPM fluctuation downhole. This dataset became the key to understanding the downhole vibration in detail because it provided information that cannot be acquired by a traditional MWD tool. Field-recorded data were fed into drilling dynamics simulations to accurately calibrate the drilling dynamics model. The simulations resembled downhole drilling conditions and clearly identified the root cause. The simulations precisely predicted the torque along the entire drillstring and identified why overtorque is present in only a certain part of the drillstring. The calibrated model was used to compare old and new bit designs. The newly designed bit showed much lower torque amplitude with similar torsional vibration frequencies. The simulation indicated that the newly designed bit can significantly alleviate the overtorque issue. Implementation of the new bit mitigated the overtorque issue immediately. As of May 2016, there have been 18 runs with the new bit. Only one run had a slight overtorque issue whereas the rest showed no sign of overtorque connections. DBR and NPT related to overtorque were eliminated. As a byproduct, the average on-bottom rate of penetration increased by 9%. This case demonstrates the effectiveness of the integrated approach to solving drilling challenges.