Bottom Hole Assembly Design Research Articles

Estimation of Surge and Swab Pressures While Tripping for Minimizing Excessive Drilling Problems

Surge and swab pressures result from pipe movement upward/downward during drill string reciprocation and tripping. surge and swab create costly drilling concerns such well kick, formation breakage, and lost circulation. This study aims to find the optimum pipe tripping speed to avoid surge and swab issues, particularly in lost circulation zones. Also, to determine how drilling factors and well bore geometry affect surge and swab pressures. Mud rheology, mud properties, hole diameters, drill pipe diameter, and bottom hole assembly (BHA) dimensions were also analyzed. Dynamic surge and swab model was employed to simulate two case studies in Rumaila Iraqi oilfield. The findings indicated that the tripping speed is the most effective variable on surge and swab pressures. Annular clearance and BHA design have also a major effect on the surge and swab pressures. For the first case study, it is found that whenever the mud weight is far from the pore pressure and fracture pressure gradients, the 5" drill pipe can be tripped in/out of lost circulation formation (Shuaibba formation) at optimum tripping speed of (80 ft/min) without surge/ swab related problems. The reason is that the generated surge pressures (6110-6300 psi) are below the fracture pressure (7100-7400 psi). The results also showed that tripping 5" drill pipe within a maximum running speed of 80 ft/min in (8.5") open hole section through Tanuma formation till Rumaila formation causes a surge pressures of (4650-5050 psi) which is still below the fracture pressures of formations (4750-5660 psi). the results of the second case study (S-shaped well) revealed that the optimum tripping speed of the drill string in the (12.25") open hole through Dammam and Hartha formations is (90 ft/min). it is also concluded that pulling out of hole (POOH) process must be carried out more carefully than the running process since the mud density is near the pore pressure gradient. The results of this study can be further used to improve the drilling efficiency in Rumaila oil field with decreasing non-productive time (NPT) by employing the appropriate tripping speed and optimal drilling operations.

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.

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.

Vibration-collision mechanism of dual-stabilizer bottom hole assembly system in vertical wellbore trajectory

The lateral vibration of drill string causes well deviation and the collision between drill collar and sidewall, and severe lateral vibration even affects the drilling safety or reliability. In view of the problems above, the lateral vibration characteristics of drill string need to be analyzed. Therefore, a newly vibration-collision model of BHA (bottom hole assembly) with random collision characteristics is proposed in this paper. Firstly, the dynamic model of drill collar with double stabilizer is presented by utilizing the Lagrange equations. Secondly, the dynamic characteristics of drill collar in air and mud drilling is analyzed with different collision frequencies. Subsequently, the displacement and motion trajectory of drill collar under different structure parameters of BHA and mechanical parameters of system are investigated by numerical simulation. Finally, the influence of rotation speed of BHA and length of drill collar on lateral vibration of drill collar is discussed. The results indicate that the lateral vibration of drill collar in air drilling is more serious than that in mud drilling; and the higher the collision frequency, the more severe the lateral vibration. Improving rotation speed of BHA, length of drill collar and WOB (weight on bit) have promoting influence on lateral vibration of drill collar; however, increasing stabilizer diameter has suppressing influence on lateral vibration of drill collar. The research findings give reasonable guidance for structure design of BHA and selection of mechanical parameters of system.

Study on factors affecting vertical drilling bottom hole assembly performance and a new bottom hole assembly design method considering formation uncertainties

Drilling a deep vertical well at a low cost is very important for accelerating the exploration and development of oil and gas resources. Vertical drilling BHA design is the key to drill a vertical well, however the BHA design is still an art not science in some formation. In this paper, a new mechanical model of bent-housing motor BHA is established, a build rate prediction method considering formation properties is presented and a BHA design method considering formation uncertainties is proposed. The evaluation results of vertical drilling BHA show that formation dip, formation anisotropy and hole diameter expansion are the main factors affecting pendulum BHA performance, and formation dip, formation anisotropy, hole diameter expansion and the distance from the upper stabilizer to the bit are the main factors affecting bent-housing motor BHA performance. The case study of the proposed BHA design method demonstrates that hole diameter expansion is very important for vertical drilling BHA performance, and should be taken in to account during the design process. The models and method proposed in this paper is helpful in maintaining verticality and reduce drilling cost.

Case Study: Space-Age Directional Drilling Improves Efficiency, Economics

Directional drilling has been used in oil and gas operations since the 1930s when onshore drillers employed the technology to reach offshore reservoirs. Over the years, technologies have been introduced to improve precision and control and at the same time have allowed multiple reservoirs to be produced through a single well, which reduces drilling costs and minimizes the environmental impact of the drilling process. In designing drilling plans, operators have considered economics when deciding whether to employ the traditional process of rotating the drillstring to control well trajectory or use more precise directional drilling techniques, but an either/or approach is not always the best one. The introduction of software that analyzes drilling conditions and determines the most appropriate drilling solution is changing the status quo, streamlining the drilling process and changing the playing field for drillers. The Evolution of Directional Drilling The widespread adoption of horizontal drilling from narrowly spaced slots on a centralized pad location has led to the introduction of complex wellbore geometry intended to maximize field development while minimizing geographical footprint. The growing need for precise execution of complicated well trajectories increased the demand for directional drilling expertise. Using a steerable bottomhole assembly (BHA) comprising a mud motor with a bent housing, an experienced directional driller can orient the bend of the motor in the direction prescribed on the well plan to steer the well on the intended trajectory in a process known as sliding. When the well trajectory is intended to remain relatively straight, the entire drillstring is rotated from surface in a process referred to as rotating. Experience and research have shown, however, that the well trajectory is rarely straight during periods of rotation due to rotational tendencies, a combination of systematic and random influences from BHA design, drilling parameters, and geological formation characteristics that can cause a significant divergence from plan. Rotational tendencies, along with designed well plan deviations, often require sliding to ensure the well follows the planned trajectory. All else being equal, it might seem that sliding should be applied across the board, but there are two reasons that sliding is not the default solution.

When Slick Is Not Smooth: Bottomhole Assembly Selection and Its Impact on Wellbore Quality

Summary Appropriate selection of a bottomhole assembly (BHA) is critical to the success of a drilling operation. In US land drilling, these assemblies are often selected using local heuristics rather than rigorous analysis. These heuristics are frequently derived from the incentives of the directional contractor as opposed to incentives for the operator. Large motor bends enable more rotation through the curve and reduce the possibility of tripping for build rates. Unstabilized motors are believed to aid sliding and tool face control. Both of these practices lead to drilling a more tortuous wellbore and may cause problems later in the well’s life. This study quantifies the impact of these practices and proposes alternatives that can balance the needs of directional companies with the desire of operators for high-quality wellbores. More than 60 conventional motor assemblies used to drill curves in the Eagle Ford and Permian basins were analyzed for directional performance using commercial drillstring analysis software. The sliding and rotary tendencies were modeled through the curve across a range of potential drilling conditions. Expected build-rate models were validated by comparison to the maximum achieved doglegs in the directional surveys. When available, additional validation was performed using motor yields calculated from slide sheets. The validated models were compared to the dogleg severity (DLS) requirements for each assembly’s respective well plan. Comparisons of slide ratios and slide/rotate tendencies of the BHAs were used to estimate the impact on wellbore quality using the tortuosity metric proposed by Jamieson (2019). Typical well plans for both basins had curves of 10° per 100 ft with no well plan greater than 12° per 100 ft. Typical BHAs were capable of >15° per 100 ft under normal sliding conditions, with some assemblies capable of >20° per 100 ft of build. Predicted build rates were validated by slide sheets and observed DLSs. Common characteristics among assemblies with excess capacity were high-bend angles (≥2°) and minimal stabilization. These understabilized assemblies exhibited unstable rotary tendencies across a range of drilling parameters. The combination of high-build rates with rotary drop masks the true level of tortuosity in a wellbore, leading to an underestimation of unwanted curvature. A minority of the assemblies used a lower motor bend angle (<2°) combined with multiple stabilizers. These assemblies had a more consistent directional capability throughout the curve and exhibited stable behavior in rotation. The success of these assemblies confirms that there is potential for tailoring BHA designs to improve wellbore quality without compromising the technical objectives of the well. As increasing attention is afforded to the topic of wellbore quality, it is important to have methods available to technically achieve high-quality wellbores. In addition to the management of drilling practices, it is also important to have an appropriate BHA design that can enable those practices

Temperature modeling for wellbore circulation and shut-in with application in vertical geothermal wells

This paper presents the development and application of a numerical model to predict the temperature distribution of the vertical borehole system during circulation and shut-in conditions. The presented model can simulate the transient temperature disturbances of the drilling fluids, the drill string, the casing strings, the cement behind the casing, and also the surrounding rock formation. The transient temperature profiles resulting from the presented model are compared with a CFD (Computational Fluid Dynamics) model using ANSYS-FLUENT. A good agreement between the results of both models is found. However, the developed model has a great advantage over the CFD model in terms of computation time and power. In addition, a comparison with field results showed a good agreement between the simulated temperature and the experimental data using the presented model. Moreover, a sensitivity analysis on the influence of the size and length of the bottom hole assembly (BHA) on the temperature of the borehole is performed. The analysis is performed for both static and dynamic conditions. The results showed a significant influence of the BHA size on the static and dynamic bottom hole temperature. However, the length of the BHA only affects the dynamic bottom hole temperature. • We present a transient numerical model for wellbore system temperature simulation. • Prediction of wellbore temperature during flowing and shut-in conditions. • Feasible for complex wellbore with multi-casing and drill-string sizes. • Application and comparison with field temperature log data. • Effect of the BHA design on the bottom hole temperature.

Study Recognizes and Assists in Mitigation of Bottomhole Assembly Lateral Vibration Chatter

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197231, “Recognition and Mitigation of the Bottomhole Assembly Lateral Vibration Chatter Mode,” by Jeffrey R. Bailey, SPE, and Harshit Lathi, ExxonMobil, and Matthew T. Prim, SPE, ADNOC, et al., prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Lateral vibration modeling of certain bottomhole assembly (BHA) designs has shown great sensitivity to the proximity of stabilizer blades. This paper explores the nature of the vibrational dysfunction known as BHA chatter. A field-proven frequency-domain model illustrates the cause of the dysfunction, its rotary-speed dependence, and mitigation methods and results. The complete paper provides three case studies exploring this phenomenon, one of which is included in this synopsis. Introduction The authors first describe the similarities and differences of a BHA and a stringed instrument. The string of a violin, for example, typically has two fixed nodal points: the first at the bridge, which does not change, and the second at the position of the musician’s finger, which is moved along the fingerboard in order to play notes of different frequencies. The finger pressing on the string causes it to have zero displacement at that location, which defines a nodal point. Additional nodal points may occur in the motion of the string as harmonics of the fundamental mode, but these are not considered to be fixed nodes because the amplitudes of the harmonics vary. The string is relatively flexible, so it can be described adequately with a second-order differential equation. Significantly, a BHA typically has more than two nodes. A lateral wave propagating along the BHA must satisfy the nodal point constraint of zero lateral deflection at all these locations. These nodes typically are placed without regard to the frequency of the wave traveling along the string, which is governed by the rotary speed and the type of lateral excitation. The geometric compatibility requirement that the pipe has zero displacement at the fixed nodes has ramifications. The nodal point constraints force the pipe to adapt to the locations of these nodes through contact forces that literally push the pipe back into position to honor the constraints. In some scenarios, this process requires large forces. One consequence of large forces pushing the pipe to maintain geometric compatibility is that these forces are applied to the outer diameter of a body that is rotating, so this response may also generate torque and associated wear of the contacting surfaces. This observation applies to both static and dynamic forces but most commonly is recognized in the static domain. It is not typically recognized in dynamics as applied to BHA design.

Well Deviation Problem: A Case Study in an Iranian Gas Well Drilling

Unexpected well deviations can bring the drilling projects lots of financial and technical damages. As a result, investigation of the Bottom Hole Assembly (BHA) tendency and prediction of the probable mechanical behavior of the drilling string, especially when a new configuration is running in the hole, is critical to prevent unexpected failures. In this paper, a drilling project in an Iranian gas field which ended in a catastrophic well trajectory is going to be studied in more detail. Here, we try to answer three main questions. The reasons for the unusual well trajectory and the possibility of predicting this behavior is the first issue. The second question is about the signs of this failure during the operation and the ways that we could detect it earlier. In the third question, the alternative plans that can prevent this problem are examined by studying different BHA configuration and drilling parameters. The major sources of our information are the daily drilling reports, well log data, related published articles, and numerical simulations in WELLPLANTM software of Landmark package. According to the simulation results, BHA design is one of the most effective factors in this case study and its effect could be predicted using BHA tendency analysis before starting the drilling operation. During drilling of this well, some anomalies have been observed in drill string mechanical parameters such as hook load, rotation torque and up and down drags. Simulation of torque and drag charts for some probable well trajectories shows completely different trends for the expected well trajectory and the actual one. The observed data during the drilling operation are similar to the ones simulated for a highly deviated well and are completely unlike the trend of the near-vertical well path. Hence, it was possible to detect the wrong situation if we had simulated the mechanical behavior of the drill string and compare it with the actual observations during the operation. Finally, examination of various BHAs reveals that using an in-gauge stabilizer 10 meters above the bit instead of the one that is 20 meters above the bit could provide better well path control. It is completely obvious from the different build and walk rates which resulted in about 19 different BHA configurations. Moreover, the suggested BHAs demonstrate a good tolerance in case of changing WOB in the desired range. In the end, besides from being careful and alert during the drilling operation, the application of credible drilling simulators is strongly recommended in order to prevent unforeseen situations and also to be prepared if some happen.

Nonlinear Dynamic Model and Characterization of Coiled Tubing Drilling System Based on Drilling Robot

Due to the uncontrollable dragging force and velocity of the drilling robot, the weight on bit (WOB) and rate of penetration (ROP) can not be controlled. So, there is not an application of in the drilling engineering even through downhole robots have been developed for many years. Dynamic characteristics are the theoretical basis for controlling WOB and ROP. In this paper, the power source of the driving force of the drilling robot is found, which is the pressure difference between inside and outside of the drilling robot. The calculation model of the dragging force of the drilling robot is obtained. On the basis, a fluid–solid coupling nonlinear dynamic model (CT-drilling robot-hydraulic motor-bit-rock-drilling fluid) is established. The nonlinear dynamic characterization is simulated by Runge–Kutta method. The nonlinear dynamic model of the coiled tubing drilling system introduces the characteristics of drilling fluid, rock mechanics and ROP for the first time. The effects of robot position, friction coefficient, displacement fluctuation of drilling fluid and WOB fluctuation on the dynamic characteristics of drilling system are studied. It is found that the displacement of drilling fluid, position of drilling robot and friction coefficient are the main factors affecting the dynamics of the CT drilling system based on drilling robot. This paper finds out power source of the drilling robot, which is the pressure difference between the internal and external of the drilling robot. The acquisition of dynamic characteristics will provide a theoretical basis for the control method of downhole robot, rock breaking mechanism based on drilling robot, bit selection and design of bottom hole assembly, etc. It will also promote the development of downhole robots and solve the bottleneck problem of coiled tubing “buckling” and “locking”.

A Dynamic Model with Friction for Comprehensive Tubular-Stress Analysis

Summary A new model technique is described for comprehensive dynamic stress and displacement analysis of wellbore-completion tubulars, including friction loads with history. A dynamic model of tubing forces is necessary to predict local pipe velocity, which in turn determines the magnitude and direction of localized frictional contact. By tracking dynamic changes in axial force starting from the initial running state, a complete load history can be simulated for the installed casing and tubing through the service life of the well. The dynamic friction model subdivides the casing or tubing string joint by joint and uses an elastic pipe-momentum balance. Pipe velocity is related to axial force by the elasticity equation. Dynamically determined velocity is necessary to predict the magnitude and orientation of local node-friction vectors. Damping for the dynamic analysis is provided by annular fluid viscosity. The elastic equations are solved as a set of algebraic equations in terms of past and future values of pipe axial force and velocity. Key model inputs such as pressure, temperature, fluid, and wellbore-friction coefficients can be changed at each successive load step. Running loads and packer setting with slackoff or pickup loads determine the initial tubing-stress configuration. Given the initial configuration, each subsequent load case is calculated starting from the prior load and resultant friction state, allowing for full history dependence. The surface velocity profile of running individual stands is a key input. Unexpected magnitudes of downhole transfer of surface load are demonstrated. A change in the operation-load sequence is shown to produce significant differences in tubular axial loads, indicating that special attention to load history should be considered when performing a tubular-stress analysis. For slackoff, overpull, or packer-setting events, the model can track dynamic load response at downhole points, such as a packer or cement top. An example well with a deviated profile and a planned sequence of life-cycle operations including stimulation, production, and shut-in was simulated for a variety of load sequences. The model has been validated against field data using the actual hookload plot during installation of a single-trip, multizone intelligent completion in an offshore highly deviated extended-reach-drilling (ERD) well. Example calculations are given for a high-pressure/high-temperature (HP/HT) subsea well and a horizontal unconventional well. The dynamic friction model allows for the seamless integration of running loads with friction into a fully sequential stress analysis of subsequent well life-cycle loads for landed completion strings. Although dynamic analysis has been extensively applied to complex drilling phenomena such as drillstring vibration or bottomhole-assembly design, current industry models for completion tubulars such as casing and tubing separate the installation state from the in-service life envelope or attempt to solve the problem with a static analysis. This represents a critical deficiency in the current industry state of the art for completion tubulars, which the present work proposed herein strives to address. From a comparison with appropriate static analytic solutions and industry-standard drag-and stress-models, dynamics were found to affect friction-force directions and magnitudes, suggesting that tubular dynamics cannot be neglected.

DECISION SUPPORT SYSTEM ОF DESIGNING BOTTOM-HOLE ASSEMBLY FOR DIRECTIONAL WELL DRILLING

Background The authors study the development of decision support system (DSS) for designing the bottom-hole assembly (BHA) while drilling, as well as the development of software that implements the DSS. DSS includes expert system, knowledge base, analytics and modeling subsystem, database of drilling equipment. The analytics and modeling subsystems contain algorithms for drilling calculation of the optimal BHA parameters in accordance with the requirements for the well profile, rate of penetration and reduction of sticking danger. The authors discuss how to use the developed expert system as part of an automated control system for directional well drilling. The studied drilling equipment consists of: drill bits, calibrators, downhole screw motors, drilling jar, heavy-weight drill pipes and heavy-wall drill pipes. Analyzed the main parameters of drilling equipment affect sticking danger, rate of penetration and well trajectory. The developed database structure of drilling equipment allows you to calculate the above parameters. The result of the work of the decision-making software is a report defining the types and sequence of installation of the necessary downhole drilling equipment. Aims and Objectives For DSS development for the BHA designing while drilling is necessary to develop an expert system, a knowledge base, analysis and modeling subsystem, a database of drilling equipment to implement this DSS as a part of an automated control system for directional well drilling. Results The authors developed an ontological model for describing and choosing effective BHA design by the Protege software based on evaluation and analysis of the main attributes of BHA selection experience. The authors also developed the drilling equipment database structure for BHA equipment selection based on deductive inference mechanism for decision rules of the knowledge base.

Dynamic Reliability Analysis of Rotary Steering Drilling System

Abstract. Vibration and high shock are major factors in the failure of downhole tools. It is important to study the causes of vibration and shock formation to prevent failure of the drillstring and bottom hole assembly (BHA). At present, it is generally recognized that the vibration of drillstring is the main reason for the failure, especially the lateral vibration. In this paper, the bottom tool of Rotary Steering Drilling System (RSS) calculation model was established based on the secondary development of ABAQUS software. Starting from the initial configuration of drilling tool, considering the contact impact of drilling tool and borehole wall, the dynamic excitation of guide mechanism and the drilling pressure, torque, rotational speed, gravity, buoyancy, drilling fluid damping. The dynamic characteristics of the inherent frequency and dynamic stress of the bottom hole assembly (BHA) were calculated and analyzed, and risk assessment method based on the quantitative vibration intensity was established. The reliability of typical drilling tool is evaluated, which provides a reference for the optimization design of BHA of Rotary Steering Drilling System.

Technology Focus: Bit Technology and Bottomhole Assemblies (December 2018)

Technology Focus Rock characterization, with regard to determination of mechanical and geologic properties, is critical for performance drilling. This consideration ensures appropriate offsets analysis. Additionally, it promotes several benefits in project planning and execution, with regard to bottomhole-assembly (BHA) design and compliance analysis, drive-system evaluations, bit selections, hydraulics considerations, drilling-parameter ranges, and anticipation of operational dysfunctions. Performance drilling, when deployed holistically, contributes to cycle-time and project-cost reductions. In most instances, hardness is considered to be the most critical rock property in bit-selection discussions. Field performances, and results from this classification, have not been consistent with this claim. Recent research shows that, in addition to hardness, other rock properties, such as lithology types, heterogeneity, and abrasiveness, have equal importance in bit evaluations. Consequently, the discussion must move from rock-strength analysis to rock-drillability analysis, which is more inclusive. BHAs must achieve their expected functional roles without creating vibrations or conditions that compromise project success. Vibration events commonly have been tied to BHAs or drill bits. Efforts aimed at addressing vibration challenges through bit and BHA changes have not produced the desired results. Researchers have identified additional influences (e.g., drilling parameters, drilling fluid types, rock-drillability factors, stabilizer types and geometries, reamers, wellbore trajectory, and drive systems) that also serve as vibration sources. Consequently, strategies or solutions aimed at addressing vibration challenges must target their sources to ensure effectiveness of such solutions. Performance consistency, aided by effective bit-wear predictions, promotes cycle-time reduction. Improvements in rock-drillability analysis, bit selection, BHA design, drilling-parameter selections, and vibration remediation, coupled with the industry’s advancements in downhole-tool development and data analytics, must ensure appropriate monitoring and prediction of bit wear. Research must delve into the different bit-failure modes—wear and impact, different wear stages, and the totality of factors that drive the wear process. Recommended additional reading at OnePetro: www.onepetro.org. IADC/SPE 189697 Real-Time Downhole Data Resolve Lithology-Related Drilling Behavior by Christopher Viens, Nabors Drilling Solutions, et al. SPE 187445 Real-Time Bit-Wear Prediction Using Adaptive Data Analytics by Vikrant Lakhanpal, University of Houston, et al. SPE 188427 Experimental Investigation of the Effects of Rotational Speed and Weight on Bit on Drillstring Vibration, Torque, and Rate of Penetration by Vimlesh A. Bavadiya, University of Oklahoma, et al.

Numerical Modeling of Dynamic Behavior and Steering Ability of a Bottom Hole Assembly with a Bent-Housing Positive Displacement Motor Under Rotary Drilling Conditions

Fully rotary drilling is one of many useful technologies used for the exploitation of petroleum and geothermal resources, but fully rotating drill-strings are extremely complicated. Therefore, according to the Hamilton principle, a non-linear coupled bottom hole assembly (BHA)-bit-formation-wellbore model is proposed for BHAs with bent-housing positive displacement motor using the finite element method to investigate the dynamic behavior and steering ability under fully rotary drilling. The impact force, acceleration, axial loading, torque, and dynamic stress were simulated, and factors influencing the dynamic steering forces were investigated. The results indicate that the impact force, acceleration, axial loading, torque, and dynamic stress under fully rotary drilling are much higher than under conventional drilling. The numerical simulation and field test in well B confirmed that the rotation of the drill-string is conducive to the hold-on of the deviation angle. With the increase in the weight-on-bit, bend angle, and stabilizer height, the deflecting force on a drill bit increases. Conversely, with the increase in stabilizer diameter, the deflecting force on the drill bit decreases; the lower the deflecting force, the better the effectiveness of hold-on. With increasing deviation angle, the deflecting force on the drill bit first decreases and then increases. The present model can provide a theoretical basis for wellbore trajectory control and optimization design of BHA.

Directional Control and Rathole Elimination While Underreaming Depleted Formations With a Rotary-Steerable System

Summary An oil and gas operator in the Gulf of Mexico (GOM) planned to drill a deepwater well section in one run by concurrently drilling and enlarging a 12¼- to 14½-in. hole while deviating from 60 to 30° inclination and crossing expected depleted formations. At section total depth (TD), the rathole below the underreamer needed to be eliminated to help ensure successful cementing of the liner. A bottomhole assembly (BHA) was designed to allow achieving these objectives in one run, and the field results obtained with the system are described. The first step in determining the best BHA design was to compile drilling experiences through the target formations and perform a review of all pertinent offset-well information. Weaker zones had been encountered in the 12¼ × 14½-in. section, and an at-bit reamer (ABR) had to be included in the BHA to allow the liner to be set on the bottom of the section, rather than leaving an 85- to 135-ft rathole. Because the ABR placement in the BHA is between the bit and the rotary-steerable-system (RSS) tool, it was important to ensure that directional control could be maintained in the section and make certain no interference existed between the ABR and the wellbore that could compromise control. Stabilization and placement of the underreamer were also crucial to ensure that the necessary directional performance was obtained without overstressing the BHA components, and modeling was performed to optimize the design. Hydraulics and torque-and-drag modeling ensured that the BHA design could drill the depleted zone without premature activation of either reamer. The modeling and analysis of offset performance resulted in successfully drilling the section and opening the rathole in one run. The BHA was steered to the final desired angle, and reached the section TD without incident and at the desired rate of penetration (ROP). After the section TD was reached, the ABR successfully opened the 12¼-in. rathole to the desired 14 in., allowing the liner to be set 3 ft from the bottom. Normally, this type of operation would require a separate dedicated hole-opening run. Using the new design eliminated the additional trip and the time necessary to open the hole, which was estimated at 56 hours. A BHA solution was developed through modeling that allowed the operator to not only maintain the steerability needed to achieve directional requirements with an ABR between the bit and the RSS while drilling depleted formations but also to concurrently perform underreaming.

The design of bottomhole assembly with two rock cutting tools for directional drilling

On the basis of the theoretical analysis and practical studies of hole drilling of large diameter, a method for designing the BHA with two rock cutting tools is proposed, taking into account the geological and technical factors that have an impact on the formation of the trajectory. The calculation of BHA with two rock cutting tools and a different number of supporting and centralizing components for different geological conditions of drilling is carried out and the analysis of their work in the process of drilling is conducted. The graphic dependences of the deviation intensity variation and the inclination angle with the sinking of borehole of the large diameter for the BHA that can be used for the drilling of vertical and directional wells.

Integrating Managed-Pressure Drilling Into HP/HT-Well Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188335, “Integrating Managed-Pressure Drilling Into HP/HT-Well Planning,” by Michael Cadd, Lewis Steven, and Robert Graham, Shell; Fedderik van der Bos, Nederlandse Aardolie Maatschappij; Craig Leggett, Blade Energy Partners; and Emil Stoian, Weatherford, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Managed-pressure drilling (MPD) is an increasingly common technique in narrow-margin high-pressure/high-temperature (HP/HT) wells. However, MPD is sometimes viewed as a bolt-on technology, only added after much of the planning work has been carried out and all other alternatives have been exhausted. The decision to use MPD should be made at the earliest stage of well planning. An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. Overview Project 1. For an HP/HT field redevelopment in the UK North Sea, seven side-track wells were drilled from a jack-up over an existing platform. MPD was used from the beginning, but the full benefits of MPD were not realized until later in the project. MPD was initially included to hold surface backpressure (SBP) across two connections to mitigate borehole-stability risk in an un stable shale. However, once the system was operational, further benefits continued to be identified and the scope of MPD operations grew significantly. At the same time, more knowledge of the subsurface was being gained, and it became clear that some of the planned wells would not be drillable without MPD because of a significantly reduced drilling window in the overburden. MPD became a key part of the design philosophy for later wells, where managed-pressure techniques were used to set and cement casings significantly deeper than would have been possible conventionally. MPD successfully mitigated classical HP/HT issues so that problems with losses and gains, handling of elevated gas levels, and mud-weight-selection issues were all virtually eliminated. Project 2. For a standalone HP/HT exploration well drilled from a jack-up offshore the Netherlands, MPD was initially selected because of the extremely narrow margins between the pore and fracture pressures in the 8½- and 6-in. sections. Conventional drilling would not have been possible without inducing losses and spending significant time circulating to adjust mud weights, as seen in a key offset well. Taking advantage of the learnings from Project 1, MPD was selected at an early stage of the planning process and was fully integrated into the well design and operations. Mud weight, drilling parameters, and bottomhole-assembly design were all tailored to suit MPD operations. Integrated HP/HT and MPD procedures were developed on the basis of traditional HP/HT techniques but were modified to make full use of the additional functionality provided by MPD. A combined HP/HT and MPD training course was developed, and key personnel were trained in HP/HT and MPD techniques. Rig modifications were made well in advance, and MPD was implemented one hole section earlier than required to familiarize all crews with the new equipment and procedures. The result was a potentially extremely challenging well that was drilled without any of the conventional HP/HT problems observed in the offset wells.

How To Design a Bottomhole-Assembly Rotary-Speed Sweet Spot

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18836, “How To Design a BHA Rotary-Speed Sweet Spot,” by Jeffrey R. Bailey, SPE, and Andrius Minkevicius, SPE, ExxonMobil; Alexander Bolzan and Victoria R. Wilkins, Hibernia Management and Development; and Joshua S. Pokluda, Esso Exploration and Production Nigeria, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Correct placement of the rotary-speed sweet spot of a bottomhole assembly (BHA) provides multiple benefits toward achieving the ultimate goal of drilling to section total depth in a single trip. The process of BHA redesign and tuning for the desired operating parameters provides greater control over the drilling process. Vibration minimization through proper design and operation of the BHA facilitates drilling objectives that include reaching section depth in fewer trips and providing acceptable borehole quality to run casing to depth. Introduction A musician understands the basic principle of a stringed instrument: The frequency of the note made by the instrument varies with the length of the string span. Other parameters play a role, including the string properties and tension. However, once the instrument is tuned and the concert has begun, the musical notes are played principally by changing the length of the vibrating string. As the finger position is changed on the fingerboard, the pitch of the note changes. Although this is a basic concept to a musician, it is not common today in the oil and gas industry for engineers to apply this concept to BHA design selection. A BHA is a beam that may be rep-resented by a fourth-order differential equation. Model calculations proceed by subdividing the BHA into elements comprising short sections of pipe in a lumped-parameter model. A 2D model uses a state vector at each mass node comprising the lateral displacement in a plane, tilt angle relative to the center-line, bending moment, and beam shear load. In the lateral bending flex mode, a dynamic side force is applied at the bit at integral multiples of the rotary speed. In the rotary twirl mode, offset mass elements are used to investigate the stability of the BHA to eccentric mass and centrifugal forces. The dynamic response is considered to be a perturbation from the static solution. The bending strain energy is related to the square of the bending moment in the beam, and calculating the length-averaged BHA bending energy provides a BHA bending-strain-energy vibration index. Lower values of vibration indices are sought because the dynamic response to a reference input is then minimized (i.e., lower vibrations are then predicted by the model). All such modeled designs are perturbed by identical inputs, and the model results may then be compared on an apples-to-apples basis.