Bottom Hole Assembly Design Research Articles

Key technologies for well drilling and completion in ultra-deep sour gas reservoirs, Yuanba Gasfield, Sichuan Basin

The Yuanba Gasfield is a large gas field discovered by Sinopec in the Sichuan Basin in recent years, and another main exploration area for natural gas reserves and production increase after the Puguang Gasfield. The ultra-deep sour gas reservoir in the Yuanba Gasfield is characterized by complicated geologic structure, deep reservoirs and complex drilled formation, especially in the continental deep strata which are highly abrasive with low ROP (rate of penetration) and long drilling period. After many years of drilling practice and technical research, the following six key drilling and completion technologies for this type reservoir are established by introducing new tools and technologies, developing specialized drill bits and optimizing drilling design. They are: casing program optimization technology for ROP increasing and safe well completion; gas drilling technology for shallow continental strata and high-efficiency drilling technology for deep high-abrasion continental strata; drilling fluid support technologies of gas–liquid conversion, ultra-deep highly-deviated wells and horizontal-well lubrication and drag reduction, hole stability control and sour gas contamination prevention; well cementing technologies for gas medium, deep-well long cementing intervals and ultra-high pressure small space; horizontal-well trajectory control technologies for measuring instrument, downhole motor optimization and bottom hole assembly design; and liner completion modes and completion string optimization technologies suitable for this gas reservoir. Field application shows that these key technologies are contributive to ROP increase and efficiency improvement of 7000 m deep horizontal wells and to significant operational cycle shortening.

Improvements in Root-Cause Analysis of Drillstring Vibration

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IADC/SPE 178819, “Improvements in the Root-Cause Analysis of Drillstring Vibration,” by Jeremy A. Greenwood, SPE, Halliburton, prepared for the 2016 IADC/ SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed. Drillstring vibration is a leading cause of downhole-tool failure and premature wear of downhole equipment. The main challenges faced during drilling include performing rapid analyses to determine the root cause of the vibration, clear identification of the active mechanism, and implementation of the appropriate corrective action quickly enough to prevent failure. This paper describes a comprehensive methodology created to identify root causes, vibration mechanisms, and methods to reduce or eliminate drillstring vibration. Introduction A bottomhole assembly (BHA) and drillstring have six degrees of freedom and three dominant modes of vibration: axial, lateral, and torsional. This movement is used to describe the different vibration mechanisms such as stick/slip; bit bounce; bit whirl; BHA whirl, both forward and backward; torsional resonance; bit chatter; modal coupling; and lateral shocks. Data are collected from downhole and surface sensors, as well as cuttings analyses, that measure modes and magnitudes of vibration, tension, compression, and bending within the BHA; drilling parameters; fluid properties; and lithology and rock properties. The methodology uses some or all of these factors to identify the root cause and is enhanced by the ability to summarize the distribution of vibration levels across a run, by histogram analysis, and by the ability to filter across time or depth ranges and filter further on the basis of rig-activity codes. A combination of factors generates or influences drillstring vibration, including the energy inputs of weight on bit and torque; bit type; BHA design and stabilization; lithology type; geological structures; bit/lithology interaction; borehole and BHA size; hole trajectory; back-reaming or rotating off-bottom; hole enlargement; the rig’s electrical system; and, on offshore floating vessels, rig heave.

Finite Element for Simulating BHA-Casing-Rock Interactions

The Bottom Hole Assembly (BHA) design is consider a very important subject in the planning of any oil and gas well, and any mistake in BHA design will lead to additional increase in drilling cost, due to corrections needed in well trajectory.This study was intended to predict the trajectory path, by analyzing the tendency of the BHA to build, hold, or drop the angle of inclination. The other task of this work was to measure the effect of formation strength on wellbore trajectory. In this work finite element model (FEM) results are evaluated and verified using lab data supported with results obtained from some published analytical and numerical solutions and also verified with worldwide utilized software in Oil Industry (Landmark). The FE results significantly match with tubular mechanic lab data. The BHA model permits prediction of wellbore curvature based on both BHA mechanical behavior and geological influences.

Research on BHA Load Transfer Considering Drill String Transverse Vibration

With increasing difficulty of reservoir development and harsh geological conditions, higher drilling technology meets lots of challenges, especially in the large displacement wells and ultra-deep wells. For Limit Extension Well, not only good drilling equipment is needed, but also drilling technology and basic theory are acquired. Bottom hole assembly (BHA) load transfer rule has important influence on Limit Extension Well. Therefore, on the basis of previous research, BHA load transfer rule is studied which considers the influence of drill string transverse vibration, and sensitivity analysis based on affecting factors of BHA load transfer rule. Research results show that transverse vibration of drill string has greater influence on the axial force and torque transfer. With the increase of friction coefficient and azimuthal variation, friction and torque of BHA increases linearly; with the increase of weight on bit (WOB), friction and the rate of torque of BHA also goes up. The application of model considers drill string transverse vibration, which will not underestimate values of loads like previous dynamic models. It will support optimal BHA design and prevent early drill string failures. Therefore, the influence of transverse vibration cannot be ignored on load transfer in large displacement wells. Key words: Drill string; Transverse vibration; Bottom hole assembly; Load transfer; Limit extension well

The Design of BHA and the Placement of Magnetometer Sensors Influence How Magnetic Azimuth Is Distorted by the Magnetic Properties of Drilling Fluids

Summary The magnetic property of drilling fluid is one of the substantial error sources for the determination of magnetic azimuth for wellbores. Weight material, cuttings, clay, and other formation material in addition to metal filings from tubular wear may distort the magnetometer readings. This effect is obviously linked to the amount and kind of magnetic material that is in the drilling fluid, and the development of corrective means has therefore highlighted the drilling fluid. The problem has been studied by laboratory experiments and analyses of downhole-survey data. However, there are several inconsistencies in the results, and the phenomenon is not understood fully. We focus on the geometric properties of the bottomhole assembly (BHA) and the magnetic directional tool in this study. The influence on directional measurement while drilling (MWD) from drilling fluids has been studied using finite-element modeling techniques. The simulations have been performed for several cases with realistic representations of MWD-tool geometries and varying location of BHA vs. the wellbore. One important result is that for situations with perfect axial symmetry, the magnetometer readings are attenuated proportionally to the square of the magnetic susceptibility. Because the magnetic susceptibility is a small number, the effect on magnetometer readings is generally negligible. However, if the symmetry is broken, the distortion on the magnetometer readings can be increased significantly. This means that segregation of cuttings, metal filings, or weight material can have a strong influence on the strength of the measured magnetic fields. With a collar-based tool that is asymmetric by nature, the model shows a complex distortion picture. The influence varies with the tool-face angle and shows both attenuation and amplification. The distortion maxima and minima for the two crosssectional magnetometers do not coincide. These findings underline how difficult it will be to find a straightforward corrective action. The results from the simulations give increased knowledge about the influence from the magnetic properties of the drilling fluid. This is essential for accuracy estimation and multistation analysis of magnetic-survey data. Furthermore, the results demonstrate the importance of considering the geometry of the BHA and the tool and of the sensor placement when performing the mechanical design.

Mitigating Torsional Stick/Slip Vibrations in Oilwell Drilling Through PDC-Bit Design: Putting Theories to the Test

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146561, ’Mitigation of Torsional Stick/Slip Vibrations in Oilwell Drilling Through PDC-Bit Design: Putting Theories to the Test,’ by Jayesh R. Jain, SPE, L.W. Ledgerwood III, SPE, Olivier J. Hoffmann, SPE, Thorsten Schwefe, SPE, and Danielle M. Fuselier, SPE, Baker Hughes, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Stick/slip vibration of drillstrings is gaining renewed interest as operating parameters for polycrystalline-diamond-compact (PDC) bits move into the stick/slip regime of higher bit weight and lower rotary speed to enhance drilling performance. The main objective of this investigation was to determine the influence of bit design on stick/slip behavior of the drilling system. Pairs of PDC bits were designed and manufactured. Each pair had a bit with a standard design and one that embodied a stick/slip theory. Full-scale tests were performed under controlled conditions with a research drilling rig. Introduction Drilling vibrations can result in failure of bits and bottomhole-assembly (BHA) components. Axial and torsional vibrations are prominent with roller-cone bits. With PDC bits suffering catastrophic failure caused by backward whirl, the focus has been on lateral vibrations. Much attention has been given to combating backward whirl by use of antiwhirl bit designs. Meanwhile, cutter technology progressed dramatically with thermally stable PDC cutters that are more impact and abrasion resistant. Consequently, operating parameters for PDC bits have shifted to higher weight on bit (WOB) and lower rotary speed to enhance drilling performance. This parameter combination also avoids the low-WOB and high-rotary-speed regime (Fig. 1) in which backward whirl can destroy bits after drilling only a few feet. Unfortunately, higher WOB and lower rotary speed instigate torsional instability that matures into stick/slip vibrations. It has been shown in the field that for a surface rotary speed of 60 rev/min, the measured downhole rotary speed reached 400 rev/min during the slip phase. Lateral vibrations during the slip phase correlated well with observed damage. More-severe cases of measured stick/slip have been reported in the literature when the bit experienced reverse rotation at the end of the slip phase before coming to a standstill. A desirable solution for mitigating stick/slip is an inherently stable sys-tem that expands the stable-operating zone through improved bit and BHA/drillstring design to allow drilling at more-efficient operating parameters of high WOB and low rotary speed. The BHA design and the geometry (size and number) of drillpipe and drill collars can have a substantial effect on the stick/slip behavior of the system. Although larger drillpipe can mitigate stick/slip and enable more-efficient drilling, its availability and cost may limit its effectiveness as a solution. Prevailing industry perceptions were reviewed, and five leading theories regarding the root cause of stick/slip were identified.

Development of a Numerical Tool for Design of the Bottom Hole Assembly (BHA) Using Artificial Neural Networks

This paper describes the use of Artificial Neural Networks in developing a design tool for calculating BHA (Bottom Hole Assembly) parameters. The program streamlines and simplifies BHA design calculations for a planned well curvature by calculating half-wave lengths using nomograms developed by Lubinski-Woods and Muzaparov. Nonlinear normalisation of data was applied on nomogram data to significantly improve accuracy of the modelling and design. The design data calculated by the program were compared with the real data and have been verified on deposits in the Aktobe region in Kazakhstan. It is concluded that the proposed tool provides more accurate results in a shorter time, allowing designers to compare and analyse the influence of design parameters on calculations of half-wave, loading and well curvature.

Research and Application of Drilling Technology of Extended-reach Horizontally-intersected Well Used to Extract Coalbed Methane

The extended-reach horizontally-intersected well used to extract coalbed methane (CBM)can increase reservoir contact area, extend the influence scope of drainage-pressure drop and the district of CBM desorption. Furthermore, the extended-reach horizontally-intersected well can enhance unit well output and create favorable conditions for future workover. With the support of Major Projects of National Science and Technology, the research on key technologies of extended-reach horizontally-intersected well is done through theoretical analysis and experiment, the concrete research content includes selection of target formation and design of casing program, choice of survey instruments, research on the bottom hole assembly design and technique of steering wellpath, research on drilling fluid and extended-reach horizontally-intersected technology. As engineering examples of popularization and application of extended-reach horizontally-intersected well, a “U” shape well group located in Sihe mine field of Qinshui Basin and a “V” shape cluster well group located in Dafosi coal mine of Binchang mining area have been constructed successfully by using the integrated technologies.

Managing Drilling Vibrations Through BHA-Design Optimization

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13349, ’Managing Drilling Vibrations Through BHA Design Optimization,’ by J.R. Bailey, SPE, ExxonMobil Upstream Research Company, and S.M. Remmert, SPE, RasGas Company Ltd., originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. Significant performance improvement has been achieved by managing drilling vibrations through bottomhole-assembly (BHA) redesign. This effort has resulted in increased footage per day and reduced tool damage. Previous literature has described improvements in operating practices to manage vibrations as a key component of this rate-of-penetration (ROP) management process. Dynamic modeling of the BHA has identified the key design changes leading to these improvements. The redesigned BHA has lower calculated vibration indices than the standard BHA. Introduction The appendix of a previous paper comprises a detailed mathematical description of the basics of a frequency-domain lateral-vibrations mode. The full-length paper illustrates the application of these methods to a new set of BHA-design problems in a joint study. The modeling process begins with an input panel that is populated with mechanical dimensions of the components of the BHA, usually up to the heavyweight drillpipe (HWDP), with approximately the same level of detail as a fishing diagram. It is important that the positions of the contact-point constraints be entered correctly and that the stiffness and inertial properties of the assembly be a proper representation of the subject BHA. Then, the desired operating parameters for drilling need to be provided, including the anticipated ranges of weight on bit (WOB) and rotation rate (rev/min). The linear modeling process considers a dynamic perturbation about the static state. The model uses two vibration modes to compare and contrast the response of each candidate BHA design: lateral bending and twirl. In the lateral-bending vibration mode, an identical reference bit-side-force input is applied to each design, and the magnitudes of the response at other locations along the BHA are compared. In the twirl mode, an identical mass eccentricity is applied to each model element to investigate the stability of the BHA to eccentric-mass and centrifugal-force effects. Simulation results are plotted for multiple BHA designs simultaneously in 2D or 3D displays of state vectors. Index values have been designed to summarize dynamic performance and are displayed for selected configurations to identify operating “sweet spots” immediately and to indicate which design configuration may be preferred. The indices include “BHA strain energy” and “transmitted strain energy” to represent the dynamic bending strain in the BHA and HWDP, the “stabilizer-side-force” index to quantify the dynamic wall-contact interaction forces, and the “endpoint-curvature” index to represent bending at the top of the model in response to excitation at the bit. A sensitivity analysis is completed in which multiple possible node locations are considered at the top end of the model, and the results are processed to identify average and “worst-case” conditions.

Technology Focus: Bit Technology and Bottomhole Assemblies (December 2010)

Technology Focus Performance Drilling—System Approach Will Yield Sustainable Improvements The industry continues to develop new tools, technologies, and processes to help drive down drilling costs. This commitment to improve drilling efficiency and reliability, through effective questioning of relevant data, also has strong positive effects on drilling operations. Strides have been made, but there is more to be done. In most instances, efforts to understand and develop sustainable-improvement strategies tend to isolate and focus on specific components [e.g., drill bit, drilling fluid, bottomhole assembly (BHA), and drive system]. In relating to these components, we usually are guided by past experiences and “rules of thumb.” Without a doubt, it is clear that the effect and value of our experiences are immeasurable. However, we need to shape our data-questioning processes around our experiences to challenge the rules of thumb. We have tools that will speed up this process. First, we need a system approach to performance drilling. Extensive research has contributed to the development of high-performance positive-displacement motors and turbines. In addition, development of rotary-steerable tools has been extended successfully into slimhole applications. Earlier limitations of these tools, in terms of torque vs. revolutions-per-minute relationship, as well as product reliability, have seen tremendous improvements. What usually is missing is the selection analysis from a drilling-system perspective rather than as an individual component. BHA design and modeling, a critical part of the system approach, must be practical and field driven. Negative effects of vibrations, with regard to downhole-tool life, borehole quality, and overall drilling performance, have been clearly established. As a means to vibrations mitigation, sources and specific modes must be identified. BHA design, as part of the system approach, must be cognizant of the drilling system’s functional requirements. In addition, performance-improvement discussions must focus on practical aspects of the application. System-based solutions will ensure consistent and sustainable improvements. We have the key, let’s open the door. Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org SPE 128767 • “Decoupling Stick/Slip and Whirl To Achieve Breakthrough in Drilling Performance” by Sean Xianping Wu, Smith Technologies, et al. SPE 128211 • “High-Frequency Downhole Dynamic Measurements Provide Greater Understanding of Drilling Vibration in Performance-Motor Assemblies” by Andrew D. Craig, SPE, NOV, et al. SPE 134488 • “Downhole-Vibration Measurement, Monitoring, and Modeling Reveal Stick/Slip as a Primary Cause of PDC-Bit Damage in Today’s Applications” by L.W. Ledgerwood III, SPE, Baker Hughes, et al.

Managing Drilling Vibrations Through BHA Design Optimization

Summary Significant performance improvement has been achieved by successfully managing drilling vibrations through bottomhole-assembly (BHA) redesign. This effort has resulted in increased footage per day and reduced tool damage. Prior literature has described improvements in operating practices to manage vibrations (Dupriest et al. 2005; Remmert et al. 2007) as a key component of this rate-of-penetration management process. In a parallel work activity, BHA redesign efforts have provided additional performance improvements of approximately 36% in one drilling application. Dynamic modeling of the BHA has identified the key design changes leading to these improvements. The redesigned BHA has lower calculated vibration indices than the standard BHA. The BHA design evaluation process uses a frequency-domain lateral dynamic model in both predrill forecast and post-drill hindcast modes. BHA lateral vibrations are characterized such that alternative BHA configurations may be developed and compared directly with a proposed baseline assembly. In the hindcast mode, the BHA model can be operated at the recorded weight on bit (WOB) and revolutions per minute (RPM) to generate corresponding model results in time or depth, and these values can be compared with the measured performance data. In one case study, the redesign of a BHA with downhole motor and roller reamer is described, with corresponding field data for four original BHAs and four redesigned assemblies. In a second application, model and field drilling results for two rotary-steerable assemblies are compared to evaluate the predictive ability of the model in smaller hole size and with different BHA types. Finally, the utility of the model to identify preferred rotary-speed "sweet spots" is demonstrated in a motor BHA operating in larger hole.

Technology Focus: Bit Technology and Bottomhole Assemblies (December 2008)

Technology Focus Performance Drilling—Taking the Next Big Steps Drilling continues to be pushed into harder, deeper, and sometimes depleted environments. In addition, well profiles have become more complicated. As a result, footage drilled per bottomhole assembly (BHA) and rate of penetration (ROP) usually are low. These issues, if left unattended, will drive up drilling costs exorbitantly. Solutions are needed that will increase both footage drilled and ROP. Researchers focusing on these issues have identified three key findings. First, performance improvement is a drilling-system problem (i.e., drill bit, BHA, and drive system) and is less dependent on individual components. Second, optimization of performance qualifiers (specifically footage, ROP, vibrations control, directional effectiveness, and borehole quality) is not an exclusive process. Third, real-time identification and remediation of drilling dysfunctions are critical to the drilling process. The design and selection of drill bits must evolve from a feature-based approach to a technology-driven process. Drill-bit manufacturers need to move away from the current "me, too" approach, when it comes to product development. Local field knowledge, in terms of dips and behaviors, is critical and must be incorporated into BHA design. The BHA-design process must be fast, practical, and reliable. Drive systems (e.g., rotary-steerable types, mud motor, and turbine) must be selected on the basis of their effectiveness and relevance to project success. In this effort, rig specifications, operational hydraulics, formation drillability, and well profiles must be considered also. Offset performances should guide, but not drive, decisions made for subsequent wells. Real-time data acquisition and interpretation are critical for the industry's next big steps in drilling performance. These data will guide the drilling process, in terms of anticipated formations, identification of dysfunctions, and parameter selections. As an industry, we have all the pieces—we need to bring them together quickly, to solve the puzzle. Bit Technology and Bottomhole Assemblies additional reading available at the SPE eLibrary: www.spe.org SPE 112647 • "A Systematic Approach to a Better Understanding of the Concentric-Hole-Opening Process Utilizing Drilling-Mechanics and Drilling-Dynamics Measurements Recorded Above and Below the Reamer" by Ian Thomson, Baker Hughes, et al. SPE 112731 • "Optimization of Deep-Drilling Performance With Improvements in Drill-Bit and Drilling-Fluid Design" by Alan D. Black, SPE, TerraTek, et al. SPE 115395 • "The Use of the Industry's First 3D Mechanical-Caliper Image While Drilling Leads to Optimized Rotary-Steerable Assemblies in Push- and Point-the-Bit Configurations" by Junichi Sugiura, SPE, PathFinder Energy Services, et al.

Through-Tubing Rotary Drilling From Njord Floating Platform

Summary The densely-faulted Njord reservoir in the Norwegian North Sea is considered one of the most complex reservoirs in the world. The field is developed from a semi-submersible platform with 15 subsea-completed wells drilled in a pre-drilling campaign in 1996 to 1997 and two major platform drilling campaigns, one in 1997 through 2000 and the other in 2002 to 2003. Drilling of two conventional sidetracked oil producers in the last campaign was challenging and costly. As the field matures, the need for a cheaper way of drilling sparsely located smaller undrained compartments became essential. This led to initiate an ambitious campaign called the low-cost infill targets (LIFT) for identifying and drilling those targets using a cheaper drilling technique called the through tubing rotary drilling (TTRD). TTRD is a hugely demanding task especially, from a floating platform as any economic rationale will be lost if completion accessories and well integrity are compromised through TTRD. To the best of our knowledge, no TTRD operations have previously been executed from a floater. The severity of depletion, especially with depletion and re-pressurization (Huff'n Puff) of parts of the reservoir provides a significant technical test and challenge for TTRD on Njord. The relative movement of the floater also presents extra operational challenges, which requires accurate measures to prevent damage to the tubing hanger, Christmas tree (XMT), downhole-safety valve, and existing completion string. Issues related to bottomhole assembly design to meet drilling and production needs, mud rheology, equivalent circulating density (ECD) management, rock mechanics, and completion techniques are critically analyzed and risk-reducing or eliminating measures are put in place through extensive research and development for each of the prospective targets. This paper is intended to give a comprehensive description on the technological challenges of the TTRD technology from a floating platform, research and development activities to qualify the technology on Njord, screening of drilling targets and the drilling experiences from two TTRD wells on Njord.

Magnolia Deepwater Development- Striving for Best-in-Class Drilling Performance

Summary ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM) (see Fig. 1). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The well-construction strategy included drilling six additional development wells from a mobile offshore drilling unit (predrilling) before the installation of the TLP. Drilling the new wells consisted of two phases: batch-setting all six wells through 20-in. casing, followed by deepening the wells to a total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50° to 60° maximum hole angles. This paper examines the application of drilling best practices used to deepen the wells to TD after batch-setting operations were complete (Eaton et al. 2005). To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-in-Class performance requires detailed planning, documenting, and implementing of results and lessons learned; effective communications; equipment quality control; and implementation of a team environment with all the companies involved in the drilling program. The complex high-angle wells require employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to enable trouble-free tripping of the bottomhole assembly (BHA), running of casing, and obtaining primary cement jobs. The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design (Eaton et al. 2001); hole cleaning; and torque and drag monitoring. The paper also discusses activities that reduced the number of required trips and activities conducted out of critical path, such as moving the subsea blowout preventor (BOP) from wellhead to wellhead with an innovative BHA, a BHA to run and retrieve wear bushings, subsea guidebase installation by way of a winch and remote operated vehicle (ROV), off-critical-path makeup of BHA components, and drillstring management.

Application and Analysis of Simultaneous Near Bit and Surface Dynamics Measurements

Summary Axial, torsional, and bending vibrations are all present in a bottomhole assembly (BHA) while drilling. The dynamic response of the BHA depends on many variables, such as drilling parameters, BHA design, hole condition and inclination, and formation properties. Events, such as bit bounce, forward and backward whirl of the BHA and the bit, and drillstring resonance can occur during drilling. Some of these events are very detrimental and can cause drillstring component failures, twist-offs, etc. This paper deals with the analysis of measured drilling vibration data from a field test that used both downhole- and surfacevibration measurement devices. Surface sensors included dynamic axial and torsional strain gauges and accelerometers and a singleaxis magnetometer, all mounted in the drillstring above the rotary table. Downhole sensors included an axial accelerometer, two orthogonal bending-moment strain gauges, dynamic weight-on-bit (WOB) and torque strain gauges, and two orthogonal magnetometers, mounted in a measurement while drilling (MWD) sub. The field test involved several drilling runs that included drilling and reaming with polycrystalline diamond compact (PDC) and tricone bits in rotary and motor assemblies. The analysis described in this paper involves the determination of axial and torsional wave velocities in the drillstring; their use in predicting resonant frequencies; a comparison of predicted and measured resonant frequencies; inference of downhole dynamics with surface measurements (surface noise cancellation), including a comparison of results with measured downhole data; an example of the detection of BHA whirl with downhole data; an example of the detection of bit bounce with downhole axial data; and an examination of precession of the trilobed bottomhole pattern generated by a tricone bit. The advantages of using either surface or downhole dynamic measurements in identifying different drilling problems are demonstrated as well as the inference of downhole dynamics with surface measurements. Once drilling dynamics problems are identified, remedial action can be taken to reduce tool and bit failures while drilling, thus optimizing the drilling process.

Elimination of Drillstring Failures

Drillstring failures can be prevented by drilling a straight, useful hole free of severe doglegs with larger-than-normal drillstring components. The maximum drill-collar diameters shown in the Lubinski tables in the IADC Drilling Manual, Sec. P1,1 for straight-hole drilling are essential for drilling a straight, useful hole and preventing drillstring failures. When dogleg limits are maintained, drillpipe fatigue and associated hole/casing problems are prevented. Rate of penetration (ROP) can be greatly improved by controlling dogleg severity. Operators have reported drillstring failures more than 50% of the time when drilling 6 3/4-in. and smaller hole sizes with conventional, fishable drillstring components. Conventional drillstrings, especially for slim holes, are torsionally weak, limber, and lightweight and have a small-restrictive bore. The lack of a stiff, heavy bottomhole assembly (BHA) for deviation control and sufficient bore size for adequate hydraulics reduces ROP and increases the probability of hole problems and drillstring failures. Larger-than-normal drillstring components run pin-up with a fishing neck below the pin provide fishability and increased torsional strength, stiffness, weight, and bore size. The low-stress-level pin-up drillstrings have proved to be strong, heavy, and stiff enough to drill straight holes without accumulating fatigue. The larger-than-normal drillpipe connections are 40% to 60% stronger torsionally, and the drillpipe tubes have a bore that is more than 1/2 in. larger. The larger-than-normal drill collars are stronger, stiffer, and heavier. The resulting improvement in deviation control, hydraulics, and failure prevention increases ROP and the successful drilling of slim holes with 8 1/2- through 3 3/4-in. diameters. Smith Intl. performance bulletins document the increases in ROP and deviation control obtained during the last 6 years with no fatigue failures. The correctly packed BHA consisting of three stabilization zones in the first 65 ft above the bit using one or two large-diameter short drill collars will drill a straight, useful hole and is the only recommended BHA design (Fig. 1). There is no assurance that a straight, useful hole can be drilled with a pendulum. Large-OD drill collars provide the maximum weight and stiffness to control hole deviation with a packed BHA and the maximum restoring force and drift diameter with a pendulum. Crooked holes cause fatigue damage to drillpipe tubes, OD wear and heat checking of the tool joints, and casing wear. The Lubinski curves in API RP 7G2 show the dogleg severity that will cause fatigue damage of the drillpipe tube and wear/heat checking of the tool joints. The correctly packed BHA restricts hole-angle changes to below the critical value where fatigue damage and/or wear occur. If doglegs develop that exceed the limits, the logleg area should be renamed to reduce the severity of the hole-angle change. Casing wear results when casing is set in a crooked hole with the lateral force on the tool joints high enough to cause casing and/or tool-joint wear. The correct low-stress-level drillstring will not accumulate fatigue in a hole drilled with the correctly packed BHA. Fatigue accumulates only when the drillstring components are weak and the stress exceeds the endurance limit of the steel. Drilling a crooked hole and destroying a drillstring is inexcusable because the knowledge of how to prevent these problems has been available for years. The daily cost of the well might be slightly higher for the correctly packed BHA and the correct low-stress-level drillstring. The daily cost of this insurance is insignificant compared with the cost of rig time for fishing operations, lost hole sections, lost/damaged drillstring components and frequent inspections. Most downhole drillstring problems are predictable and preventable. Inspection will ensure the integrity of the drillstring but inspection will not prevent the accumulation of fatigue/failures in a weak drillstring.

HORIZONTAL DRILLING IN AUSTRALIA: THREE CASE HISTORIES

Three horizontal wells with horizontal sections of up to 331 m were drilled successfully during the development of the marginal North Herald and South Pepper oil and gas fields, which have relatively thin oil columns (6 to 12 m) at a depth of some 1200 m sub-sea. A steerable motor system was used to maintain directional control within the design parameters. This system proved to be successful from the start and no major changes to the bottom hole assembly design were required to drill all the wells. Average drilling time including running and setting the seven inch liner amounted to 12 days. The wells were tested with rates up to 7500 BOPD through a one inch choke.

Vibrations Increase Available Power at the Bit

Drillstring vibrations are generally considered to be detrimental to downhole drilling equipment because they produce cyclic or fatigue loading. Tool joint failures, tubular washouts, and bit breakage are often fatigue related. On the positive side, dynamic forces applied to roller cone rock bits have the potential to increase penetration rate. This paper quantifies the available vibration energy at the bit and shows how to control the level of energy through bottom hole assembly design and rotary speed.