bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Trajectory Computational Model Improves Calculated Borehole Positioning, Tortuosity and Rugosity
Authors: Abughaban Mahmoud F. , Bialecki Bernard , Eustes Alfred W. , de Wardt John P. , Mullin Steve 
Published: January 2016

Abstract
Wellbore tortuosity, defined as the degree of wellbore deviation from the smooth trajectory, and wellbore rugosity, defined as the degree of wellbore diameter irregularity, are critical elements in determining torque and drag (T&D) magnitudes in the drilling of long-reach horizontal wells and deep verticals. Current three-dimensional well trajectory models represented by the minimum curvature method (MCM) tends to mathematically smoothen the wellpath between survey-stations creating an artificially low tortuosity expressed as dogleg severity (DLS). This can lead to the miscalculation of the actual true vertical depth (TVD), leading to the underestimation of T&D magnitude. A robust three-dimensional trajectory model, the Advanced Spline-Curve (ASC) model, has been developed by the Colorado School of Mines to overcome these limitations. The ASC model provides realistic results and accurately calculate the spatial course of the wellpath.
The principal method proposed using the ASC model is a step toward more accurate representation of wellbore trajectories, as compared to other methods using constant curvature, minimum curvature or tangential calculations. This curve has continuous derivatives up to the third order (C3) along the entire wellpath. It is fairly straight-forward and has the robustness and flexibility to calculate complex, three-dimensional wellbore trajectories.
In this paper, various applications of the ASC model are presented and its results have been validated using two approaches: (a) an academic wellbore example of a known trajectory path, and (b) the use of high resolution continuous gyroscopic (HRCG) survey data recorded at one survey per foot. The calculated trajectory utilizing ASC model guarantees continuity along the entire wellpath with significant better accuracy as compared to MCM. These findings allow better wellbore positioning, more realistic tortuosity and the introduction of a rugosity measurement. This helps to evaluate drilling equipment and procedures while drilling highly deviated wells and extended verticals.
A HRCG survey recorded at one survey per foot provides a high level of wellbore positioning, tortuosity and rugosity accuracy; however, this is usually after the wellbore had been drilled and thus an improved calculation method such as the ASC model brings operational value.
Benefits of Using Downhole Vibratory Casing Tools in the Niobrara/Codell Formations
Authors: Warner Matthew , Hall Ryan A. 
Published: January 2016

Abstract
In recent years the construction of horizontally drilled wells has become commonplace. The horizontal sections of these wells have continued to increase in length as equipment and methods used in constructing these wells have improved. As lateral lengths have increased, so have the challenges associated with drilling and completing these wells. The high TMD/TVD ratios seen in many wells often presents challenges during the installation of casing and liners. The primary issue is the friction associated with horizontal well profiles and the absence of adequate vertical casing weight.
In order to combat the problems associated with getting casing/liners to bottom, operators are increasingly using downhole vibratory tools to aid these operations. Vibratory downhole tools primarily help by breaking the static friction between the workstring and wellbore or casing. These tools are commonly used in horizontal well drilling operations but more recently these tools have also begun to be run on casing strings with great success.
In this paper, the results of field tests using a downhole vibratory casing tool on a group of wells in the Niobrara and Codell formations are presented. Eight (8) wells were considered during the study. A vibratory casing tool was run in four (4) wells. Casing was run in four (4) additional wells in which no vibratory tool was used. The wells involved in the testing were completed with 4-1/2″ 13.5# P-110 liner in 2-section laterals. Evaluation of the data shows a 121% average increase in running speed while rotating the liner in the hole when using the vibratory casing tool, resulting in an average of a 23 hour (55%) decrease of rig time per run. Additionally, less torque at higher rotary speeds was seen on the wells in which the vibratory tool was run. The associated physics, operating methodology and effectiveness of these tools will also be presented.
Planning, Collaboration and Optimized Drilling Performance for Drilling Extended Reach Wells in the Bakken/Three Forks
Authors: Nair Vakkeyil Naveen , Bitzan Paul , McRobbie Neil 
Published: January 2016

Abstract
This paper discusses the methodology involved in evaluating the risks associated with drilling extended-reach wells using conventional drilling tools and adopting a stepped approach towards the drilling optimization of 25,000-ft total depth wells, with horizontal legs exceeding 14,000 ft. Extensive planning was carried out over the following areas of the project: well-trajectory design, torque and drag, the fluid program, drilling practices, drillstring design and integrity, hydraulics management, drilling optimization tools, and bottomhole assembly (BHA) design.
The objective was to drill two horizontal wells in the Bakken and Three Forks formations in North Dakota and to use the lessons learned to drill three extended-reach wells with 50% percent longer laterals. The first two wells of the project were studied to calibrate torque-and-drag models for hole friction, drillstring dynamics with the effects of fluid in-hole drag, effects on rate of penetration with regards to weight transfer while sliding, hydraulic effects of the fluid system, motor output, vibrations analysis, drilling practices through transitions, and parameter optimization while drilling through formation markers through the horizontal leg of the well.
The first two wells were drilled using a drilling-optimization downhole tool placed above the motor that measures the weight, torque, and bending moment across the sub. The pressure-while-drilling tool was also used. Tri-axial vibration sensors were used to measure and transmit data in real time to optimize drillstring dynamics and make improvements in the drilling system post run. The improvements in the system and lessons learned were used for three additional extended-reach wells with measured depths over 25,000 ft. Drillstring dynamics from the downhole sub were studied to identify ways to overcome friction. The data validated the effectiveness of certain friction-breaking tools and proposed areas for improvement to orient drill with conventional motors further into the lateral. The limitations with the current system were identified with the first two horizontal wells. Wellbore-trajectory design and pipe placement were optimized to aid in transferring weight to the bit beyond the 10,000-ft lateral horizontal leg. Alterations in the drilling program were subsequently made to drill further into the lateral based on lessons learned from downhole optimization tools and surface sensor data.
Three wells were drilled beyond a 25,000-ft total measured depth, with the horizontal leg exceeding 14,500 ft in the lateral. Continuous improvements were made to the system to drill to the limit with conventional motors and to pick up sophisticated rotary steerable tools to drill the last 1,500 ft of the lateral. The approach proved more cost effective to optimize within the constraints of the drilling system before using sophisticated rotary steerable tools.
Modeling and Simulation of Annular Pressure Buildup (APB) Mitigation Using Rupture Disk
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng 
Published: January 2016

Abstract
Manufactured to burst/collapse at a specific pressure difference and installed in the casing wall, a rupture disk is a common device used to mitigate annular pressure buildup (APB) and to protect casing strings. This paper focuses on the modeling and simulation of the effects of a rupture disk burst/collapse event on APB in casing/tubing annuli.
After the rupture disk bursts (or collapses), fluid will move through the open disk from one annulus to another, resulting in changing pressures. In this work, three pressure balance models (piston model, miscible fluid model, and immiscible fluid model) were established to calculate the annulus fluid pressure and volume changes after the rupture disk opens. The piston model, assuming no fluid exchange between two annuli, provides the simplest solution. It is accurate if the two annuli contain nearly identical fluids. The miscible fluid model is intended for annuli with the same fluid type, but with different density values. The immiscible fluid model is intended for annuli with different immiscible fluid types, such as oil-based mud in the internal annulus and water-based mud in the outer annulus.
The pressure balance models were implemented and integrated into a commercial casing and tubing design software platform. A numerical approach was used for trapped and connected annuli; an analytical approach was used for connected annuli with at least one ventilation or leakoff point. This combination provides optimized simulation performance and accuracy. When multiple annuli are connected with open rupture disks, global pressure equilibrium is reached through iterations of handling two connected APB regions at a time.
In a case study in which the casing ballooning effect is negligible, numerical simulation results were found to be consistent with the results of analytical calculation; the difference is within 0.1%. The application of the rupture disk for APB management was also demonstrated in another case study using field data. The simulation results show that the rupture disk is a viable and cost-effective option for APB management.
A Step Change in Drill Bit Technology with Self-Adjusting PDC Bits
Authors: Jain Jayesh R. , Ricks Gregory , Baxter Benjamin , Vempati Chaitanya , Peters Volker , Bilen Juan-Miguel , Spencer Reed , Stibbe Holger 
Published: January 2016

Abstract
Since they were first introduced to the market decades ago, polycrystalline diamond compact (PDC) bits have undergone numerous technological improvements. One such example is depth-of-cut (DOC) control technology. Introduced in early 2000s, this technology emerged as an effective means to mitigate torsional vibrations by managing bit aggressiveness. Today, however, the drilling industry faces the task of drilling diverse sections of the well with a single bit. This is a significant challenge for fixed PDC bits, requiring a compromise that limits vibration mitigation in some sections of the well and/or top-end rate of penetration (ROP) performance in other sections.
This paper presents an innovative PDC bit that can self-adjust its DOC control characteristics to the constantly-changing drilling environment and mitigate vibrations while delivering improved ROP. The self-adaptation is accomplished through a passive hydro-mechanical feedback mechanism encapsulated in self-contained cartridges that are installed inside the bit blades. The DOC control elements mounted on the cartridges respond to the external loads through strategically designed rate-sensitive retraction and extension strokes. During unfavorable dynamic events, the elements engage with the formation and mitigate dysfunctions. During normal steady-state drilling, the elements gradually adjust their exposure to enable fast and efficient drilling.
The operating principle of self-adjusting PDC bits is first demonstrated through laboratory drilling tests under confining pressure using full-scale prototype bits. The testing was expanded to research wells in the field to assess the ability to self-adapt and mitigate stick/slip vibrations. The field test facility enables a controlled yet realistic environment with reduced uncertainty that is often not available in the field. The tests compare stick/slip tendencies of bits by building stability maps in WOB-RPM space using downhole measurements under similar operating conditions. Bits with the self-adjusting mechanism led to fewer instances of stick/slip than fixed PDC bits in multiple formation types. Self-adjusting bits significantly expanded the stable operating region and enabled operation at higher ROP.
The ability of the DOC control elements to continuously self-adjust their exposure overcomes several other limitations posed by the fixed nature of traditional DOC control. The technology doesn't require a fixed pre-designed exposure, prevents over-engagement because of its ability to retract, and eliminates iterative tuning of DOC control currently in practice. The technology is also anticipated to absorb impacts in interbedded formations and reduce damage from improper starting procedures. With many PDC bit drilling applications being torque-limited, the technology opens up several possibilities to reduce drilling costs.
Improvements in the Root Cause Analysis of Drillstring Vibration
Authors: Greenwood Jeremy A. 
Published: January 2016

Abstract
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, all vibration mechanisms, and methods to reduce or eliminate drillstring vibration on a range of different operations.
A 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 is collected from downhole and surface sensors, as well as cutting 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, histogram analysis, and the ability to filter across time or depth ranges and further filter based on rig-activity codes.
There is a combination of factors that generate or influence drillstring vibration, including the energy inputs of weight on bit (WOB) and torque (TRQ), bit type, BHA design and stabilization, lithology type, geological structures, bit-lithology interaction, borehole size and BHA size, hole trajectory, backreaming or rotating off bottom, hole enlargement, the rig's electrical system, and on offshore floating vessels, rig heave.
The methodology is able to identify and isolate which factors are the root cause of a specific mechanism by incorporating time-based analyses with depth-based logs and plotting a to-scale BHA to identify correlations of the bit position, stabilizer, and other BHA components to formation types and boundaries, hole-size changes, and casing positions. This enables a significantly faster data analysis and a more rapid assessment of the root cause of the vibration, thereby delivering specific benefits through identifying and then reducing or eliminating drillstring vibration on a range of different operations.
Increasing Long-Term Fatigue Performance of an API Box Boreback Using an Enhanced Non-Truncated Thread Design and Revised Machining Methodology
Authors: Hauze Gregory R. , Gokhale Samit 
Published: January 2016

Abstract
Stress Relief Features (SRFs) are commonly added to Rotary-Shouldered Connections (RSCs) to increase the fatigue performance of the connection. An SRF aims to lower the critical stress at the last engaged thread and improve fatigue performance. The most common SRF prescribed by the American Petroleum Institute (API) for API box connections is the API Box Boreback.
The API Box Boreback SRF is added to an API RSC by boring out both the box threads and ID to a specified cylinder diameter and depth from the box shoulder. The API boreback is then finished by profile turning a tapered transition of specified angles and lengths which connects the back of the boreback cylinder to the ID of the component. The traditional method of boring the cylinder diameter due to the tapered threads of API connections causes a removal of the thread crests at the back of the box. These truncations of the last engaged threads reduce the contact area of the thread flanks available to support the load. The repercussions of this include an increase in stress concentration, reducing the fatigue life, and an escalation in susceptibility to thread wear, which inevitably amplifies the effect of the thread truncation, further reducing the fatigue life and cancelling out the benefits of the SRF. Details of this phenomenon can be found in IADC/SPE 128931 (Gerdes & Lee, 2010).
Despite its popularity, the API Box Boreback SRF can lose its effectiveness as the thread truncation at the back of the box can accelerate crack initiation and cause premature failures. To remedy this, an experimental study was undertaken to develop a machining method to cut a boreback with an enhanced non-truncated geometry on API box connections. The modified boreback geometry and machining methodology were perfected over multiple iterations, prototyped with a Computer Numerical Controlled (CNC) lathe using various routines and tooling selections. The dimensions were verified to conform to the requirements outlined in API Specification 7-2 and the machining process was validated on multiple API box connection types.
This paper presents details of a modified design and a universal machining methodology developed to cut an API compliant Box Boreback which retains full-height threads at the back of the box, avoiding thread truncation, and preserving the increased fatigue performance a Box Boreback provides well into the life of the connection. The method meets all dimensional requirements outlined in API Specification 7-2, ensuring proper make-up. The machining process can be performed on either a CNC or manual lathe. The enhanced boreback design provides a drastic improvement in fatigue performance over the standard API Box Boreback design, while maintaining all other structural and dimensional design aspects, and without altering the make-up torque or Bending Strength Ratio of the connection.
New Instrument Performance Models for Combined Wellbore Surveys Facilitate Optimal Use of Survey Information
Authors: Ledroz Adrián , Bang Jon , Weston John 
Published: January 2016

Abstract
In order to determine confidently the path of a wellbore, established practice involves the collection of multiple survey data using the various methods that are available to the industry, such as measurement while drilling methods, using either magnetic or gyroscopic measurements, or surveys taken after a section of the wellbore has been completed, normally using gyro tools. The survey deemed to be of the highest precision, based on published survey system error models, is commonly selected to be the "definitive survey" for that section of the well and all other data is discarded. However, by combining multiple data sets through the use of survey averaging techniques, it is possible to obtain a more accurate estimate of wellbore position.
Having generated a "combined survey" by such an averaging method, i.e. a survey generated by combining two or more surveys that may be of the same or different type, it is then required to quantify the accuracy of that survey. This may be expressed in the usual manner as a sequence of error ellipsoids at intervals along the path of the well. At present, however, this can only be done by rigorous calculations analogous to the survey averaging itself. This is a complex analysis, which is one important reason why survey averaging has not been generally implemented and adopted as a standard analysis practice.
Error models for individual survey tools are usually specified in terms of Instrument Performance Model (IPM) files in accordance with methods and procedures derived through the work of the SPE Well Positioning Technical Section. The IPM files, along with wellbore trajectory data, form the inputs to standard error model software packages through which survey uncertainty is calculated to a specified level of confidence. This paper demonstrates how new IPM files can be generated for combined surveys. The error analysis resulting from the new IPM file is shown to be consistent with the results obtained through the rigorous mathematical analysis of the individual surveys.
The introduction of new IPM files offers an easy and efficient method for operators to utilize all available survey information in a consistent manner. This may help to optimize the surveying program, with implications for both positional uncertainty assessment and safety aspects. Furthermore, the improvement in the positional data as well as the reduced uncertainty that can be achieved by combining surveys is a great advantage when considering small targets, very long extended reach wells, and highly congested fields in general, as it might turn unfeasible projects into achievable ones.
Quantifying Asphaltene Content from Downhole Optical Spectral Data during Sampling While-Drilling Operations
Authors: Indo K. , Pop J. J. , Hsu K. , Qi J. , Agarwal V. , Garcia Mayans A. , Ossia S. , Haq S. A. , Varughese J. 
Published: January 2016

Abstract
Over the last two decades downhole fluid analysis (DFA) using visible and near-infrared spectrometry has proven to be one of the most effective means for obtaining accurate and detailed reservoir fluid property information during formation tester operations. In a previous publication (SPE 166464) a methodology was introduced for estimating fluid properties, such as fluid type, hydrocarbon composition (C1, C2, C3, C4, C5, and C6+), carbon dioxide content, and gas/oil ratio (GOR), from downhole optical spectrometer data acquired during sampling operations. We have extended the methodology introduced in the previous publication to the real-time estimation of asphaltene content of black oils.
The equation derived for quantifying the asphaltene content of crude oils uses optical densities (OD), the absorption coefficients of asphaltene and resin, stock tank oil (STO) density, resin content and formation volume factor (FVF). In the process of deriving the asphaltene content a new method was devised for estimating FVF from optical data. The unknown parameters in the equation and the uncertainty in the estimate of asphaltene content are calibrated against a database that contains asphaltene content data of various crude oils and the corresponding optical spectra. Using the derived equation, a maximum likelihood estimate of asphaltene content of crude oil and its associated uncertainty can be obtained.
The accuracy of the method for estimating FVF and asphaltene contentwas verified and validated using laboratory crude oil data. The method was also applied to downhole optical spectral data acquired during a sampling-while-drilling (SWD) operation. It was found that the estimated asphaltene content and FVF obtained from the measured downhole spectral data showed very good agreement with the results of laboratory pressure/volume/temperature (PVT) analysis performed on captured fluid samples.