Bottom Hole Assembly Research Articles

A New Bottom-Hole Assembly Design Method to Maintain Verticality and Reduce Lateral Vibration

Well deviation is a prevalent problem in deep oil and gas exploration, leading to a significant increase in drilling costs. The conventional bottom-hole assembly (BHA) anti-deviation design method does not consider the impact of the BHA structure on lateral vibration. This paper proposes an integrated BHA design method that takes into account both anti-deviation and vibration reduction. This method evaluates the BHA’s anti-deviation ability using the drilling trend angle. A negative value of the drilling trend angle indicates that the BHA can correct well deviation. A finite element linearized dynamics method is used to evaluate the lateral vibration intensity of the BHA. This method involves calculating the bending displacement caused by mass imbalance and then determining the magnitude of the bending strain energy based on this displacement. The structural factors affecting the anti-deviation ability and potential lateral vibration intensity of pendulum BHAs and bent-housing mud motor (BHMM) BHAs were studied, and field tests were conducted for verification. The research shows that for pendulum BHAs, the factor that has the greatest impact on anti-deviation ability and vibration intensity is the distance from the stabilizer to the drill bit. For BHMM BHAs, the length of the short drill collar has a significant impact on the vibration intensity. Compared with current design methods, the mechanical specific energy (MSE) of the single stabilizer pendulum BHA decreased by 12%, while the MSE of the BHMM BHA decreased by 26.4%. Both decreases indicate a reduction in vibration intensity. This study will help to further increase drilling speed while preventing well deviation.

Drilling of horizontal wells in Western Turkmenistan

This scientific work summarizes the experience of drilling horizontal wells at abnormally high reservoir pressures in the Western part of Turkmenistan. The article describes in detail the choice of the layout of the bottom-hole assembly (BHA), drilling methods, the area of the angle set and the stabilization interval of the zenith angle, and also notes the importance of the quality of drilling mud when drilling horizontal wells. The work performed proves that drilling of horizontal wells is possible both at an early and late stage of field development and their drilling should be provided for when creating technological development schemes at the level of the field development project. Such work will find application for drilling deep horizontal wells with abnormally high reservoir pressures and will lead to an increase in hydrocarbon production, as well as organizational restructuring of horizontal drilling on a scientific basis. Keywords: oil recovery; geological structure; deviation; zenith angle; borehole; communication channel.

Uncertainty analysis method for the output force vector control on the rib of the orienter in coiled tubing drilling

This work addresses the uncertainty associated with downhole parameters in coiled tubing drilling and proposes a new method for controlling the output force vector on the ribs of the orienter, enabling more precise control of the actual wellbore trajectory. Based on the principles of longitudinal and transverse bending beams, we construct a 3D mechanical model of the Bottom Hole Assembly (BHA) used in coiled tubing drilling. We then analyze the spatial geometry relating the force direction on the orienter's rib and the tool face angle, establishing a comprehensive steering resultant force vector model. Applying the principle of minimum energy, we explore traditional control schemes for the output force on each rib and reveal its intricate variation patterns. We conduct a statistical analysis to investigate the randomness distribution state and sensitivity of the experimental parameters, allowing us to derive the probability density and cumulative probability functions for the two-dimensional random variables linked to the output force on the ribs. Confidence interval models are constructed to predict the output forces with a predetermined level of certainty. Finally, we experimentally verify the proposed uncertainty control method in real-world coiled tubing drilling. Our results show that the randomness of weight on bit (WOB) and the tool face angle of rib 1# are the main factors influencing the uncertainty of the output force control. When the output forces vector on the ribs exceeds the uncertainty confidence interval, the actual wellbore trajectory significantly deviates from the designed one. Conversely, when the output forces vector falls within the confidence interval, the error between the actual and designed wellbore trajectories is significantly smaller. This validates the rationality and effectiveness of the proposed uncertainty analysis method, providing valuable guidance for implementing wellbore trajectory control in coiled tubing drilling.

TURBOCALIBRATOR FOR CONSTRUCTION OF INCLINED AND HORIZONTAL WELLS IN CONDITIONS OF UNSTABLE ROCK FORMATIONS

Horizontal and directional wells drilling allows to cover larger surface areas of the field with a less dense well grid. However, such wells constructing has its own specific challenges, one of which is the proper development of the drilled intervals to prevent cave-in.
 It is proposes a design of a turbocalibrator, characterized by the rotation of the calibrating component through the hydraulic drive system without rotating the column itself.
 This proposed technical solution will significantly reduce time of well construction, as it enables simultaneous drilling and calibrating of the wellbore, reduces the number of development operations and tripping operations, especially in cases where rotating the bottomhole assembly is prohibited.

Autodrillers, Rig-Control Systems, Driller Procedures Reduce BHA Failures

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214997, “The Role of Autodrillers, Rig-Control Systems, and Driller Procedures in Reduction of Bottomhole Assembly Failures,” by Pablo E. Barajas, SPE, Paul Pastusek, SPE, and Aaron Lacey, ExxonMobil, et al. The paper has not been peer reviewed. _ Reducing bottomhole-assembly (BHA) failures has been this operator’s focus in US land intermediate and lateral sections to reduce cost per foot. BHA failures can be mitigated with better autodriller processes, improved rig-control-system technology, and drilling-mechanics-based procedures. The operator, rig contractor, and BHA service providers engaged in an intensive continuous improvement process for 18 months to help two rigs in Oklahoma reduce the number of BHAs used per well. The goal was to determine how to best tune the autodriller and standardize set-point practices. Introduction The operator has found that rig-control systems, particularly the autodriller, can be unstable in many drilling situations. The operator and contractor laid out the framework to measure autodriller dysfunction suspected to affect rate-of-penetration (ROP) and BHA integrity. The team engaged in a structured and intensive continuous improvement process with the following objectives: - Understand if end-user tuning and set-point practices from the contractor were being applied consistently at the rig floor level - Evaluate if the tuning practices were appropriate or effective in mitigating dysfunction in different formations - Increase subject-matter experts’ support and involvement in proactively identifying when rig-control systems were not behaving as designed to reduce impact on ROP and the BHA - Evaluate whether the operator’s drilling roadmaps and BHA safety-limit protections were being properly integrated into autodriller control loops - Use downhole sensors to understand how surface controls induced dysfunctions and confirm when they were mitigated - Propagate learnings across all rigs and crews in the basin to reduce the number of BHAs required to drill each well Observations Autodriller Dysfunction Identification. Standardizing the identification of dysfunction patterns to be avoided was a step based on physics of the system, bit-run performance and dulls (Fig. 1), directional tool damage, high-frequency (1,024 samples per second) downhole data, and high-frequency (six samples per second) surface data. Currently, the focus is to quickly identify and mitigate autodriller dysfunction by the rig teams, including the types of dysfunction described in this section. Stick/Slip. The operator developed a test to run the autodriller in different control loops to determine when stick/slip was initiated or intensified by the autodriller. Restarting drilling in ROP mode with the rig’s torsional dampening system active eliminated the autodriller as the source of stick/slip. It was determined that excessive weight on bit (WOB) used to pass the tool joint through the rotating head in the managed-pressure-drilling’s rotating control device (RCD), combined with low rotational speed, were key factors in initiating stick/slip. WOB Dysfunction. Any significant WOB variation can drive enough torque variation to drive stick/slip. This is particularly true if the WOB variation has a frequency close to the natural torsional frequency of the system.

Improvement Plan Using Fatigue Analysis Minimizes Jar Twistoff

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210723, “Service Quality Improvement Plan Using FEA Fatigue Analysis Minimizes Jar Twistoff in Challenging Applications,” by Chaouki Boufama, SPE, Baozhong Yang, and Sultan Alfaraedhi, Schlumberger, et al. The paper has not been peer reviewed. _ Jar twistoff is a well-known service quality issue for some applications, especially in relatively large borehole sizes such as 22 and 16 in. The jar is one of the weakest points in the drillstring because of moving parts, which include complex shapes, resulting in stress concentration. The complete paper presents results of a study focusing on placing the jar in the bottomhole assembly (BHA) to reduce bending moments and bending stresses on the jar connections. As a result, the risk of twistoffs during drilling is minimized, while the effectiveness of the jar is maintained if a stuck event occurs. Introduction Jars traditionally are placed between drill collars in the applications described in this study. These applications include 22- and 16-in. vertical holes with simple BHA designs, either rotary or with positive displacement motors. In cases of lateral vibration that creates high bending stress, this design is likely to cause the jar to experience extreme stress levels. The design concept of placing the jar between other components with lower weight and stiffness appears to be the most logical approach. This design would have to be validated with finite element analysis (FEA) dynamic modeling simulations to confirm lower stress at the jar and that a new weak point has not been introduced in the string. Impact and impulse also must be evaluated to confirm the effectiveness of the jar in the case of a stuck-pipe condition. The study is based on the work flow shown in Fig. 1 of the complete paper. Statement of Theory and Definitions A more in-depth analysis was performed on a 22-in. vertical drilling application with nonhomogeneous formations. A downhole real-time recording tool was added to the drillstring above the BHA to evaluate and verify the magnitude of vibration and bending moments acting on the BHA during drilling operations. The 22-in. vertical section was selected because it was determined to be the most challenging section. The following key observations were made during the drilling run when the circulation was lost to the formation: - Significant lateral vibration levels - Chaotic whirling motions - High bending moment Mechanical specific energy (MSE) and drilling parameters were controlled during the run to alleviate vibration. Vibration severity could have been influenced by the absence of the mud column as well as the borehole quality because of formation washout and an oversized hole. However, this was never verified using a caliper log. The string entered a state of chaotic whirl as the loss of circulation fluid began. The parameters, and thus the MSE, were reduced, but the severe vibrations persisted. Even though the run did not cause any jar-component failure or crack, multiple previous incidents showed similar failure modes in the same downhole conditions. These failures, which included the fractured face of each of the parted components, were analyzed and evaluated (Fig. 1). The slanted fracture indicated a high combined stress-related fracture. In addition, beach marks present near the fracture area also indicated fatigue-induced damage.

Technology Focus: Bits and Bottomhole Assemblies (December 2023)

As bottomhole-assembly and drill-bit design and operation have embraced new technologies such as artificial intelligence, new materials and manufacturing techniques, and improved design software, the industry continues to research methods of optimizing delivery and understanding of already globally used technologies. It is this approach that has long allowed service companies, operators, and drilling contractors alike to improve drilling performance, as highlighted in the papers summarized here. In the first of these papers, paper SPE 210723, finite element fatigue simulation has been used to minimize the risk of twistoffs in jars, something that many of us in the drilling community have experienced. This paper can help us reduce those unplanned events and lost time. Many rigs worldwide have moved to using autodriller-type control systems, and, in many cases, these systems have shown improved performance. In the second paper, paper SPE 214997, the optimization of these systems is discussed in the review and modification of driller procedures to minimize damage to bottomhole assemblies and the drill bit during drilling. Finally, while many papers have discussed high-frequency torsional oscillations and their effect on the bottomhole assembly and drill bit from an operational or a theoretical view point, the final paper, paper SPE 212566, discusses full-scale laboratory experiments to qualify the drill bit’s influence on this effect. All three of these papers highlight increased understanding in the operation and evolution of existing technologies to improve drilling delivery. In the evolving world of drilling where the final objectives and uses of wells are changing—whether for repurposing; carbon capture, use, and storage; or geothermal uses—these approaches to optimizing existing technologies in conjunction with the introduction of new technologies can help oilfield drilling teams pivot into this adjacent energy environment to deliver successful wells. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212438 Building a System To Solve the Challenges of Drilling Hot Hard Rock for Geothermal and Oil and Gas by Anthony Pink, NOV, et al. SPE 212559 Machine Learning-Based Drilling System Recommender: Toward Optimal BHA and Fluid-Technology Selection by Gregory Skoff, SLB, et al. SPE 212109 World’s First Application of Steel Body Bit in High-Chloride Formation With Water-Based Mud by Bekbolat Uandykov, Zhigermunaiservice, et al.

Best Practices to Achieve Optimal Geothermal Drilling Performance in A Cost-Effective Manner: Case Study of the Fastest Geothermal Well Drilling in Java and Sumatra

Indonesia, recognized for possessing substantial geothermal energy potential, is working towards harnessing the resource to achieve numerous objectives. Among the primary challenges encountered is the considerable expense of geothermal drilling. One of the most significant obstacles to achieving this objective is the high drilling cost, which constitutes 35-40% of the total cost of geothermal energy development. The drilling cost is mainly affected by the time needed to drill one well because the faster the time, the lower the cost. Therefore, this research analyzed drilling activities, identified the fastest and most effective methods for optimal geothermal drilling performance, and reduced costs. The research also determined the factors that contributed to the sustained status of Well X as the fastest well drilled in the past decade. The methodology comprised literature review, data collection through adequate background on well and geothermal field, and data analysis. The result showed that the fastest drilling operation of a geothermal well in Indonesia in 2012 occured in West Java (Well X) for only 9.9 days with 1736.5 meters (mMD). Meanwhile, in 2021, Well Y in Sumatra spent 21.74 days to reach a depth of 2200 mMD. The use of a single-run and clean-out Bottom Hole Assembly (BHA) throughout the entire section affected the drilling duration and significantly reduced the inner side cleaning time, respectively. The cost of Well Y drilling, achieved using the best performance of two wells, reduced drilling costs by 19.2%.

Guest Editorial: The Engineer of the Future

Recently, at the SPE Annual Technical Conference and Exhibition, I was asked a question about the ‘engineer of the future.’ As we take a pause to turn the page to next year, I believe now is a prescient time to contemplate what’s next for petroleum engineering. Throughout my career, I’ve been able to witness great change in our industry as the shale revolution took hold making horizontal drilling and hydraulic fracturing commonplace, diagnostic and modeling tools improved in access and cost, and data became more timely and readily available. This led to a tremendous period of US energy supply growth and decades-long productivity improvements. Looking forward, I believe there are three trends that engineers should consider: 1) applying “new” tools to solve “old” problems, 2) connecting the dots via hybrid engineering, and 3) organizing, directing, and inserting data predictions into their workflow. These are not only my views but also the views of Devon’s talented engineers. Old problems will meet new solutions. The past decade has been dominated by unconventional horizontal development that was first pioneered in the Barnett Shale for natural gas and shortly thereafter transitioned into oil-focused development in the Bakken and Eagle Ford. Today, the Permian Basin continues to grow in total supply as the stacked pay is developed. Engineers should take stock of the tool set we have acquired during this era with a mindset to deploy these methodologies to tier II unconventional extensions, previously developed or bypassed conventional formations, offshore and international opportunities, enhanced recovery projects such as EOR and refracturing, and new energy opportunities like geothermal. To make these future opportunities competitive and meet the global demand for energy, we will likely need a combination of price, technology, and cost improvements. Engineers are critical to the latter two. To better illustrate these points let’s utilize examples. Drilling rig specification improvements have been coupled with material science and design improvements in bottomhole assemblies. The outcome is improved topdrives and mud pressure systems to power more durable and efficient downhole motors and bits, thus reducing failures, enhancing the efficiency of a rig’s daily footage, and enabling longer laterals. If we pivot to the completion space, our diagnostics for frac geometry have gone from limited and costly to a menu of options that provide fit-for-purpose diagnostics and costs. Devon deployed its first permanent fiber diagnostics in unconventional shale in 2012. Today, the same system is readily available but for a much lower cost. However, more frequently Devon has supplemented this tool with dip-in fiber and a proprietary methodology called sealed wellbore pressure monitoring to gather more frequent data points for frac geometry and design. As our team conducted, in cooperation with the US Department of Energy (DOE), a novel Eagle Ford project capturing horizontal core and completion diagnostics, we recognized that our designs have tremendously improved in efficiency but still have potential to capture more of the resource via initial and secondary fracturing efforts.

Coupled drillstring dynamics modeling using 3D field-consistent corotational beam elements

Drilling is essential to extract subsurface hydrocarbons and geothermal energy, or store waste fluids/gases underground. Drilling efficiency directly affects the economics of well construction, and is to a large extent determined by the non-productive time (NPT) associated with downhole tool failure, bit wear/damage, unexpected drillstring vibrations, and insufficient surface-to-bottom energy transfer. Various models have been developed since the 1960s to understand and mitigate undesired drilling system oscillations to ensure efficient drilling operations and help optimize the well design. Significant recent advancements in drilling engineering technology, sensor development, and data science make it possible to develop and apply a faster and more comprehensive drilling system dynamic model that can be used for real-time drilling optimization and automation.In this study, a novel control-oriented physic-based drillstring dynamic modeling framework is developed using 3D field-consistent corotational beam elements with an updated Lagrangian formulation. The structure and element kinematics are firstly derived in global and local coordinate systems respectively, based on which the system dynamics are formulated by integrating the element stiffness, damping, and mass matrices. Different drilling boundary conditions and forms of external loads, including bit-rock interaction, wellbore-drillstring contact, stabilizers, bottom hole assembly (BHA) eccentricities, and gravity/buoyancy are defined within the modeling framework. The numerical accuracy of the model with linear/quintic beam elements is discussed and verified in four different static/dynamic loading cases, which are typically used for beam analysis. Simulations of different drilling scenarios, including dynamics during the pipe connection process, bit on/off bottom process, and pipe rocking during slide drilling, are conducted for an actual L-shape well configuration with comparison to field data. The simulated drillstring tri-axial vibrations exhibit diverse characteristics and patterns in terms of oscillation amplitudes, frequencies, and modes at varying depths, generating valuable understanding of potential drilling dysfunctions and insights for real-time drilling optimization and automation.

Distributed model for the drill-string system with multiple regenerative effects in the bit-rock interaction

In this paper, an integrated model is presented to study the axial–torsional dynamics of a distributed drill string. The coupled axial and torsional drill string dynamics typically lead to severe phenomena such as bit-bounce and stick–slip, which are the main causes of failure and efficiency reduction. The top-drive dynamics and the Bottom Hole Assembly (BHA) dynamics are interconnected through the drill pipes. In order to preserve the infinite-dimensional feature of the drill pipes in the mathematical modeling, a distributed model in terms of Delay Differential Algebraic Equations (DDAE) is proposed to represent the dynamics of the drill string. The bit-rock interaction, which consists of the cutting and the frictional components, is responsible for the coupling between the axial and torsional dynamics. A rate-independent bit-rock interaction law is employed for both cutting and frictional components. In order to capture the global bit motion, including multiple regenerative effects, the well-bottom depth function is used to determine the depth of cut. The well-bottom pattern evolution is formulated through algebraic equations rather than Partial Differential Equations (PDEs). A new formulation for the linearized drill string system in terms of Neutral-type Delay Differential Integral Equations (NDDIEs) is proposed to investigate the initiation of the oscillations around the nominal operation. By this formulation, the local stability of the distributed system is studied by determining the right-most eigenvalue of the linearized dynamics. A simulation-based case study reflecting real-life scenarios is presented to investigate the dynamical behavior of the system under different operating conditions.

An approach for optimization of controllable drilling parameters for motorized bottom hole assembly in a specific formation

This study focuses on optimizing drilling parameters when using Positive Displacement Motors (PDMs). In drilling operations involving mud motors, weight-on-bit (WOB) alterations lead to variations in the system's parasitic pressure drop. Consequently, this affects the optimum flow rate and the hydraulic power of the bit. Also, if the flow rate changes, the bit's rotations per minute (RPM) also change. In other words, using PDMs creates a link between the hydraulic system and the drilling speed, such that changing drilling parameters such as the WOB causes changes in the hydraulic system's performance. Therefore, one possible way to optimize the drilling parameters is to consider the drilling rate and hydraulic system simultaneously using a multi-objective approach. This study used an integrated approach encompassing data mining and mathematical modeling, employing a multi-objective framework to identify optimal parameters. The approach was applied to Dariyan Formation drilling data. The data mining approach revealed a well-distributed data set covering optimal and suboptimal zones suitable for optimization. In data mining, the identification of optimal conditions included a WOB of 11500 lb, a rotation speed of 105.8 rev/min, and a flow rate of 843 gpm, leading to an ROP of 44.23 ft/h. In multi-objective optimization, the optimal parameters consisted of a WOB of 14480 lb, a rotation speed of 115 rev/min, and a flow rate of 920.8 gpm, resulting in an ROP of 40.49 ft/h. Comparing optimal results with the drilling data shows a substantial MSE reduction of over 35 %. The results show the good performance of this approach in detecting the optimal and non-optimal drilling variables.

Underbalanced Coiled Tubing Drilling: Delivering Well Production Safely in High H2S and Tight Gas Reservoirs, UAE

Summary United Arab Emirates (UAE) is seeking to become self-sufficient in gas supply by 2030. This has led the country to initiate several exploratory and appraisal projects to achieve this goal. This study covers one such pilot project targeting production from tight gas reservoirs in three wells through a coiled-tubing (CT) underbalanced drilling (UBD) project in ADNOC Onshore. CT pressure control equipment (PCE) was rigged up on top of production trees with wells already completed and cemented. A CT tower was used to accommodate the drilling bottomhole assembly (BHA) and eliminate risks related to its deployment. CT strings were designed to reach target intervals with sufficient weight on bit (WOB), suitable for sour environments, and able to withstand high pumping rates with mild circulating pressures. To address the hazards of H2S handling at the surface, a custom-fit closed-loop system was deployed. The recovered water was treated on the surface and reused for drilling to decrease the water consumption throughout the operations. The plan was to drill 3 3/4-in. horizontal laterals in all candidate wells. Each well was completed with a combination of a 4 1/2-in. and a 5 1/2-in. tubing and a 7-in. liner. Five laterals were drilled across the three candidate wells targeting carbonate reservoirs with each lateral having an average length of ~4,000 ft. The achieved rates of penetration varied significantly from 15 ft/min to 30 ft/min while drilling through the various formations. Over the course of the pilot project, several challenges had to be addressed, such as material accretion on the CT string during wiper trips, treatment of return fluids having high H2S content and rock cuttings, and ensuring the integrity of the CT pipe while operating in severe downhole environments. Solutions and lessons learned from each well were implemented subsequently in the campaign, such as the use of increased concentrations of H2S inhibitor to coat the CT string, the use of nitrified fluids based on changing well parameters to maintain underbalance, thorough pipe management through real-time CT inspection, and adding a fixed quantity of fresh water to the drilling system every day to avoid chemical reactions between the drilling fluid additives and hydrocarbons. The wells completed with this method exceeded production expectations by 35–50% across the project while reconfirming the value of the technology. The use of CT for UBD is still considered a challenging intervention worldwide. Such cases in high H2S environments are rare. This study outlines best practices for a CT UBD and a setup that can be replicated in other locations to implement this methodology with high H2S and when rig sourcing is a concern.

Combining Magnetic and Gyroscopic Surveys Provides the Best Possible Accuracy

Summary A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding a collision with nearby offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying tools and technologies taken individually is insufficient. This high level of wellbore positioning accuracy is achieved by combining two independent wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic measurement-while-drilling (MWD) definitive dynamic surveys (DDS). The accuracy of the MWD DDS can be further improved by minimizing error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, the use of localized geomagnetic reference, using high-accuracy accelerometer sensors, and a high-accuracy gravity reference. Furthermore, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the rotary steerable system. A first wellbore position is calculated from the magnetic MWD DDS after applying in-field referencing (IFR), multistation analysis (MSA), bottomhole assembly (BHA), sag correction (SAG), and dual-inclination (DI) corrections to improve both azimuth and inclination accuracy. A second wellbore position is calculated using gyro-MWD (GWD) technology. The results and comparisons of multiple combined survey runs are presented. The highest accuracy of wellbore positioning had been proved in this successful case study by penetrating a very small reservoir target on an extended-reach well that was unfeasible using either the most accurate enhanced MWD DDS or GWD technology individually. The presented case study shows how the wellbore objectives of penetrating a very small reservoir target had been confirmed by logging-while-drilling images and the reservoir mapping interpretation of the client subsurface team. This gave a high-accuracy wellbore position during drilling and provided higher confidence in wellbore placement to maximize reservoir production without colliding with nearby offset wells. Wellbore survey accuracy limits a borehole’s lateral and true vertical depth (TVD) spacing, constraining reservoir production in those sections. In the top and intermediate sections, wellbore survey accuracy limits how close the wellbore can be drilled to other offset wells due to collision concerns. This directly impacts the complexity of the directional work and the cost per section. Combining independent wellbore surveys unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy that can be achieved to date compared with the latest magnetic MWD surveys after correcting all known errors or compared with GWD.

Real-time rate of penetration prediction for motorized bottom hole assembly using machine learning methods

Drilling rate of penetration (ROP) is one of the most important factors that have their significant effect on the drilling operation economically and efficiently. Motorized bottom hole assembly (BHA) has different applications that are not limited to achieve the required directional work but also it could be used for drilling optimization to enhance the ROP and mitigate the downhole vibration. Previous work has been done to predict ROP for rotary BHA and for rotary steerable system BHA; however, limited studies considered to predict the ROP for motorized BHA. In the present study, two artificial intelligence techniques were applied including artificial neural network and adaptive neurofuzzy inference system for ROP prediction for motorized assembly in the rotary mode based on surface drilling parameters, motor downhole output parameters besides mud parameters. This new robust model was trained and tested to accurately predict the ROP with more than 5800 data set with a 70/30 data ratio for training and testing respectively. The accuracy of developed models was evaluated in terms of average absolute percentage error, root mean square error, and correlation coefficient (R). The obtained results confirmed that both models were capable of predicting the motorized BHA ROP on Real-time. Based on the proposed model, the drilling parameters could be optimized to achieve maximum motorized BHA ROP. Achieving maximum ROP will help to reduce the overall drilling cost and as well minimize the open hole exposure time. The proposed model could be considered as a robust tool for evaluating the motorized BHA performance against the different BHA driving mechanisms which have their well-established models.

Chaotic Effect-Based Array Duffing Systems with Improved Nonlinear Restoring Force for Weak Signal Detection in Dynamic MWD.

In the process of dynamic Measurement While Drilling (MWD), the strong vibration and rapid rotation of the Bottom Hole Assembly (BHA) lead to multi-frequency and high-amplitude noise interference in the attitude measurement signal. The weak original signal and extremely low signal-to-noise ratio (SNR) are always the technical difficulties of dynamic MWD. To solve this problem, this paper uses the chaotic effect of the Duffing system, which takes the expression (-x3 + x5) as a nonlinear restoring force to detect the weak characteristic signal of downhole dynamic MWD. First of all, in order to meet the limit condition of the chaotic phase transition of the system output, the frequency value of the characteristic signal is reconstructed and transformed based on the variable scale theory. Then, in order to solve the influence of the initial phase of the characteristic signal on the detection accuracy, a detection model based on the array Duffing system is presented, and a frequency-detection scheme with all-phase coverage is given. Finally, another array Duffing system is designed for the parameter estimation of the characteristic signal. The critical value of chaotic phase transition is determined by adjusting the amplitude of the driving signal of the array Duffing system, and then the amplitude and phase parameters of the characteristic signal are synchronously estimated. The experimental results show that the proposed method can effectively extract the weak characteristic signal within the strong noise, and the SNR of the characteristic signal can be as low as -21 dB. Through the attitude calculation for the extracted characteristic signal, it can be seen that the proposed method can improve the accuracy of the inclination of the drilling tool significantly, which proves the feasibility and effectiveness of the method proposed in this paper.

Evaluation of distributed damping subs with active control for stick–slip reduction in drilling

Drill string vibrations can cause damage to the equipment and reduce drilling performance. There are two primary methods to address this issue: top drive control or the use of specialized tools near the bottom hole assembly (BHA). Another previously published idea is to have several torsional damping sleeves along the drill string, adding viscous damping to the system. The sleeves are designed to be non-rotating, held in place by static friction, but if the combination of braking coefficient and relative pipe velocity gets too high, the sleeve will slip. This paper examines the effectiveness of active control of the braking coefficient, using an On–Off-based control scheme with proportional control. Stability maps are employed to assess the effects of this control scheme on the system for various combinations of top drive feed rates and revolutions per minute (RPM) set points. Such maps allow for a performance comparison of passive sleeves and active sleeves. The results show that active control can improve the drill string behavior both when drilling and when rotating off-bottom, by reducing the slippage of the sleeves. The settling time is reduced to up to a third of the settling time of the passive sleeves.

Motion Simulation Analysis and Experimental Verification of Drill String Rotation Controller

Abstract Conventional directional drilling mainly relies on the sliding of screw motor and drill string to realize the change of wellbore trajectory, so the friction force is large. The use of friction reduction tools that generate axial force to change the friction state can only achieve partial friction reduction, and drill string is still in a sliding state during directional drilling. These problems are solved by using rotary steerable drilling system, which can achieve directional drilling when drill string rotates. But its use cost is high. Considering the principle of high efficiency and economy, a new friction reduction tool called drill string rotation controller is proposed, which is also used to reduce friction during directional drilling through drill string rotation. By adjusting the pump pressure, the meshing state of spline module of drill string rotation controller is changed to realize the conversion of drilling mode. In rotary drilling mode, upper drill string, drill string rotation controller, and bottom hole assembly rotate together. In directional drilling mode, upper drill string rotates and drill string rotation controller slides with bottom hole assembly. The function of the tool is verified by field experiment, and motion simulation of the tool is carried out. The results show that when the driving torque is set to 25,000 N · m, more reverse torque can be overcome in the directional drilling mode, and the drilling fluid pressure is set to 25 MPa, which can be converted to the rotary drilling mode faster.

Calculation method of the build-up rate of the internal push point-the-bit rotary steering tool

The internal push point-the-bit rotary steering tool is a new type of dynamic point-the-bit rotary steerable system. This paper comprehensively uses the mechanical and trajectory method to calculate the build-up rate of the tool to evaluate its build-up ability and realize accurate control of the wellbore trajectory during the directional drilling process. The influence of tool structure, wellbore geometric parameters, drilling process parameters, bit-cutting anisotropy, and formation characteristics on the build-up ability are considered. The tool deflection force, the structural lateral force on the bit, and the formation deflection force were calculated respectively, and the calculation model for the build-up rate of the internal push point-the-bit rotary steering tool is established according to the relationship between force and cutting displacement. In order to study the variation of the build-up rate of the tool in different well slope sections under the conditions of fixed bottom hole assembly and formation parameters, the build-up rate simulation calculation was carried out. The calculation results show that the maximum build-up rate of the tool under stable and controlled conditions increases with the increase of the well inclination, which means the internal push point-the-bit rotary steering tool is suitable for extended reach wells and horizontal wells. The research results provide a theoretical basis for the design of bottom hole assembly and the optimization of drilling process parameters when using the internal push point-the-bit rotary steering tool for directional drilling.

Cuttings transport: Back reaming analysis based on a coupled layering-sliding mesh method via CFD

Inadequate hole cleaning is one of the main reasons for inefficient operations in extended-reach drilling. The mechanism of cuttings transport under the back reaming operation, which is frequently adopted to remove the cuttings, has been investigated in this study. To this end, a coupled layering-sliding mesh method with the Eulerian-Granular approach has been established innovatively. The dynamic layering method has been employed to simulate the axial motion of the pipe, whereas the sliding mesh method has been used to simulate the pipe rotation. The back reaming operation of a connector-furnished pipe has been simulated, and the sensitive parameter analysis has been conducted. The results thus obtained demonstrate that the increase in the initial bed height, inclination, and the diameter and length of the connector causes a significant increase in the cuttings concentration. In addition, the cuttings concentration is observed to decrease significantly with the pipe rotation speed. Furthermore, two main factors contribute towards the cuttings accumulation around the connector, namely, the difference in the cross-sectional area and the pushing effect of the connector—like a “bulldozer”. The “bulldozer” effect of the connector dominates when the tripping velocity is significant compared to the velocity of the cuttings. Conversely, the effect of the difference in the cross-sectional area becomes the leading factor for cuttings accumulation. The “bulldozer” effect of the connector causes a more severe impact on hole cleaning. In both cases, increasing the tripping velocity only mildly affects the cuttings concentration. It is therefore suggested that the tripping velocity should be slower than that of the sand during the back reaming operation. Furthermore, increased fluid velocity might lead to a higher accumulated cuttings concentration around the connector when the cuttings bed has not entirely passed through the connector. A significant flow rate can be safely applied after the cuttings have passed through the connector furnished with a large diameter, such as the bottom hole assembly. This exploration serves as an essential guide to predicting and controlling tight spots while back reaming.