bluuebunny/crossref_metadata_2025_split huggingface dataset:
Statistical Analysis Between Different Surveying Instruments to Understand the Reliability of MWD/RSS High Resolution Surveys and its Effect in Well Trajectory Characterization
Authors: Monterrosa Leida C. , Rego Marina Ferreira , Zegarra Erica , Lowdon Ross 
Published: January 2016

Abstract
Industry standard practices for MWD surveying consist in taken the MWD surveys at the connection; this usually will represent 30-m to 40-m interval depending of the drill pipe range used by the operator or drilling contractor. Additionally, in some occasions, the surveying sample is even larger due other drilling operation considerations such as drilling through unstable formations or simply to save rig time by removing the amount of surveys taken in the well trajectory. However, several cases studies had demonstrated that surveying the well path at these intervals is often not enough to capture the real characterization of the well, leading, in some scenarios, to significant errors in the final True Vertical Depth (TVD) placement, less refined reservoir structure interpretation as well as well engineering simulations due the unseen extra tortuosity not applied in the torque and drag analysis.
A new technique, using a combination of static MWD or RSS surveys with continuous inclination, provides an engineering approach that allows describing the trajectory at 3-m (10-ft) interval thus reducing the risks aforementioned. This case study aimed to obtain further understanding of wellbore TVD placement and tortuosity characterization by qualifying the accuracy of the 3-m (10-ft) interval High-Resolution Continuous MWD surveys using statistical comparisons against micro-dogleg Continuous North-Seeking gyro listings as well as Dual Inclination analysis between MWD and Rotary Steerable Systems (RSS). TVD error analysis was also taken into account to explore how TVD error modelling can be optimized when considering survey frequency and the use of continuous inclination data in the Ellipses of Uncertainty (EOU) error terms.
The results and correlations did not simply ratify the fact that High-Resolution continuous surveys enhance TVD wellbore positioning and well engineering simulations, but more importantly it was possible to demonstrate that the standard deviations between independent surveying instruments at the same sample rate were small and well within the estimate position of uncertainty predicted by the current industry standard error models. Moreover, in order to deliver a more realistic TVD position the findings also outline the need of supplementary case studies with regards TVD error modeling optimization when using continuous data in the description of the well trajectory. Furthermore, this technique represents a step forward in real time decision making process in critical well placement jobs and will also allow drilling operations to be more efficient with reduced operational and HSE risks.
Solving the Casing Wear Puzzle Using Stiff String Model
Authors: Samuel Robello , Kumar Aniket , Gonzales Adolfo , Marcou Sylvester , Rød Anne Mette 
Published: January 2016

Abstract
As more and more complex wells are being drilled, an important problem to be addressed relates to casing, liner, and tubing wear. Casing wear is one of the continuing challenges faced by the industry, and an accurate estimation of downhole wear remains a paradox. Several casing wear estimation techniques were applied to actual drilling situations in the past; however, the results of those efforts have not always provided the necessary level of accuracy of wear prediction. The effects of improper estimation of casing wear may not be felt owing to the general overdesign of the casings by largely applying excessive casing-wear safety factors. This paper addresses these concerns by providing a comprehensive solution to this long-standing casing-wear puzzle.
The widely used conventional soft-string model is not applicable for all well paths for casing-wear modeling; it assumes that the drillstring continuously follows the exact wellbore curvature and cannot predict the different contact locations of the drillpipe with the inner casing wall. Consequently, a new modeling technique has been developed by applying the stiff-string model for casing-wear analysis. The stiff-string model calculates more accurate contact loads by accounting for the bending stiffness of the string and helps to estimate the contact position of the drillstring at any given casing depth. These contact points are used to model the development of multiple wear groove locations at any casing depth cross-section by accounting for the varying contact positions as various operations are performed through the casing. Estimates of multiple groove positions at each cross-section reduce the overestimation of casing wear, because the wear is now distributed across different grooves, thus providing a more realistic casing-wear estimate.
This modeling approach was validated by using ultrasonic logs from complex directional wells that are the most susceptible to wear. Detailed operational steps and parameters for each well were modeled to predict the development of multiple wear grooves for each casing section. These models were compared with the 360° cross-sectional distribution of remaining wall thickness from image-based ultrasonic logs. The estimated groove depths and positions correlated with the peaks observed from wear logs that showed the worst wear locations. The results obtained from this exhaustive analysis are promising to establish a new, more thorough means of validating casing-wear predictions. By applying a new comprehensive modeling approach using stiff-string analysis to estimate multiple wear grooves, this study has helped to reduce long-unsolved casing-wear uncertainties. A novel method for validating the estimated groove positions using the full 360° spectrum of caliper or ultrasonic logs has been presented. Accurate wear prediction is important for well integrity and optimized well designs.
Differentiate Drilling Fluid Thermal Expansion, Wellbore Ballooning and Real Kick during Flow Check with an Innovative Combination of Transient Simulation and Pumps off Annular Pressure While Drilling
Authors: Yuan Zhaoguang , Morrell Dan , Mayans Aldrick Gracia , Adariani Yahya H. , Bogan Matthew 
Published: January 2016

Abstract
To achieve a high level of drilling efficiency, it is paramount to correctly identify reasons of drilling events from available data in a timely fashion. Many surface or downhole events share common root causes. Drilling fluid thermal expansion, wellbore ballooning and formation kick share similarities in terms of surface observation such as pit gain volumes. However, resolution for each of them is completed in a totally different manner. Treating a wellbore ballooning effect in the same way as a kick will likely result in losing the current borehole after days or weeks of unsuccessful operations.
In this study, pressure while drilling technologies and software simulations are discussed to analyze variances in the wellbore parameters over time to investigate drilling fluid thermal expansion, wellbore ballooning and formation influx during flow checks in riserless drilling operations. A transient simulation software was used to study the fraction of gas in the annulus and fluid level inside the drillstring on several flow checks following flow and gas bubbles at the well head. Availability of continuous pumps off annular pressure while drilling measurement helps calibrate the simulations and verify its validity.
A new workflow combining modelling, simulations and downhole annular pressure profiling measurement was successfully applied to a riserless pilot hole deep water well Gulf of Mexico. The flow contribution from each drilling fluid thermal expansion, wellbore ballooning, formation influx and u-tube flow was identified and decomposed.
Transient flow simulator working together with pressure while drilling data gave the operator an exact knowledge of wellbore dynamics in an operation usually performed with limited information. This proved extremely valuable in the pursuit of drilling prospect.
Repurposing Proven HSE Techniques for use Outside Safety Reduces Non-Productive Time (NPT) and Improves Drilling Efficiency - A Case Study on Application of "Chronic Unease" to Improve Drilling Quality
Authors: Hurtado Manuel , Redlinger Thomas 
Published: January 2016

Abstract
Health, Safety and Environment (HSE) practices and regulations have been of paramount importance to the Oil & Gas industry for decades. Drilling operations represent a major HSE risk and therefore robust programs have been put in place by Operators and Service companies to minimize the risks and ultimately reduce incidents. The success and sustainability of these programs has been well documented with quantifiable results, but the techniques have been rarely expanded to other operational areas. This paper reviews the field application of these HSE techniques on other areas of drilling operations and describes the results of the implementation over several years of offshore drilling experience.
One of the HSE techniques used in this case study is known as "Chronic Unease", a state of mind that has been successfully integrated into safety programs to build a methodology based on the recognition (detection) and reaction to weak signals that could potentially lead to significant events. As such it presents strong similarities to the early detection of drilling risks that could be prevented through quality programs.
This paper re-introduces the concept of "Chronic Unease" and presents how it can be mapped to Quality Assurance and Quality Control techniques in drilling operations. It also reviews the field application of other HSE techniques and describes the results of their implementation in several case studies in offshore drilling operations. Ultimately the case study illustrates a correlation between drilling efficiency and the successful re-purposing of proven HSE techniques.
A Gear-Reduced Drilling Turbine Provides Game Changing Results: An Alternative to Downhole Positive Displacement Motor
Authors: Jones Steve , Feddema Chad , Sugiura Junichi 
Published: January 2016

Abstract
Drilling turbines, commonly referred to as Turbodrills, have historically been used for hard-rock applications in conjunction with diamond impregnated drill bits. Their use in North America land was typically restricted by rig stand-pipe-pressure limitations. Now, the latest generation rigs in North America land have sufficient stand pipe pressure to make use of Turbodrills.
Reducing the bit speed of a Turbodrill can provide significant advantages. Reducing the bit speed and increasing torque makes the Turbodrill suitable for a wider range of drilling environments, including high-temperature wells.
Turbodrills require no elastomer re-lines like Positive Displacement Motor (PDM) Power Sections, which are typically re-lined after every run in oil based mud. High-performance PDMs generate significant vibration which could reduce the life of measurement-while-drilling (MWD) systems. On the other hand, Turbodrills produce very little vibration, hence the life expectancy of bottom-hole assembly (BHA) components can be increased. Drilling with less vibration will lead to a more efficient drilling system and reduced non-productive time (NPT).
This paper describes the operation, flow test and field test results from a new Gear-Reduced Drilling Turbine (GRDT). Key component in the GRDT were instrumented to gather critical information on vibration, shock, temperature and rotation speed in revolutions per minute (RPM).
Use of a Transient Cuttings Transport Model in the Planning, Monitoring and Post Analysis of Complex Drilling Operations in the North Sea
Authors: Cayeux Eric , Leulseged Amare , Kluge Roald , Haga Jarle 
Published: January 2016

Abstract
Inadequate hole cleaning during a drilling operation may result in immediate problems such as excessive torque or pack-off situations, or it can lead to delayed problems such as while running in hole with a casing/liner or a completion string in a leftover cuttings bed. It is therefore desirable to provide quantitative information about hole cleaning conditions: at the planning stage, while drilling or when investigating incidents.
Because the ability to transport cuttings particles varies with their position in the borehole and the current drilling parameters, hole cleaning modelling is a history-dependent problem. The precise modelling of the movement of solid particles during a drilling operation gives the possibility to estimate whether they are in suspension in the drilling fluid, settling on the low side or being eroded from a cuttings bed. These estimations may be confirmed through the change of the active volume or by the increase of downhole pressure, when PWD (Pressure While Drilling) measurements are available.
A transient cuttings transport model has been used for planning and monitoring an ERD (Extended Reach Drilling) well drilled in the North Sea. The model has been used to compare the expected performance of different mud systems on both hydraulic and mechanical limits that could be expected prior to drilling. For another challenging drilling operation, the model has been used to post analyze the sequence of actions that led to problems while running in hole with a liner. Here also, the observations tended to confirm the predictions made by the hole cleaning model.
Furthermore, an active use of such an advanced hole cleaning model may help determine the time required for circulation procedures prior to pull out of hole. This can help reduce the flat time associated with circulation procedures and at the same time decrease the duration by which the hole stays open thus reducing the risk of hole instability.
Utilizing Short Bit-to-Bend Motor Technology Enables Monobore Wells to be Drilled in the Niobrara Unconventional Shale Play with a Single Drilling Assembly
Authors: Augustine Norwood , Jerde Brayden , Fleischhacker Curtis , Peterson Brian 
Published: January 2016

Abstract
The demand for reduced AFEs for horizontal wells drilled in the Niobrara unconventional shale play increased the need for improved drilling efficiencies. Better efficiencies can be achieved by utilizing monobore well designs which maintain a single diameter hole size for the vertical, curve and lateral sections, eliminating the need for an intermediate casing string and the subsequent need to change out drilling assemblies for a reduced hole size. Positive displacement motors (PDM) with short bit-to-bend technology (SBTB) enable the well to be completed with a single conventional drilling assembly.
To drill monobore wells in a single run, the following solutions were implemented: A positive displacement motor with SBTB and reduced adjustable kick-off (AKO) angle to achieve planned build-up rates and prevent component damage.Optimal motor output torque and speed for desired rate of penetration (ROP) and bit life.Drillstring and bottomhole assembly designed for improved drilling mechanics.Optimized drilling fluid program to maintain wellbore stability in challenging formations.
Each solution enablesfor the monobore wells to be drilled in a single run, which decreases the days on well by reducing time spent running intermediate casing and tripping for drilling assemblies.
This paper compares the monobore well design to the original well design utilizing multiple hole sizes by studying build-up rates (BUR), days on well, ROP and time spent tripping. The dataset used for this study comprises six single- conventional assembly monobore wells and six representative multiple-hole size wells. A consistent drilling efficiency improvement was apparent in the comparison.
This paper shows in detail how short bit-to-bend motor technology is an innovative solution to drilling the Niobrara unconventional shale play with a single conventional assembly.
Improved Wellbore Quality Using a Novel Real-Time Tortuosity Index
Authors: Zhou Yang , Zheng Dandan , Ashok Pradeepkumar , Oort Eric van 
Published: January 2016

Abstract
Tortuosity is an important metric in evaluating wellbore quality. A tortuous well path can lead to such well problems as stuck pipe, poor cementation, and early production equipment failure. The industry currently lacks a readily usable real-time tortuosity (density) index to enable the driller to make corrections during the drilling process. This paper presents a new algorithm to calculate the tortuosity index and validates the index using field data.
Until the last decade, average and maximum dogleg severity were the main indicators of wellbore tortuosity and quality. Recently, approaches which measure/model indirect quantities such as wellbore friction, bending moment, elastic energy etc. and then translate these to a measure of tortuosity, have gained popularity. However, such an indirect process introduces errors when the model used is not accurate. Another approach produces high precision 3D wellbore profiles to assist in ascertaining the tortuosity of the well. This method, however, requires additional downhole sensors at additional cost and a need for additional data-communicating and processing. To overcome these shortcomings, this paper proposes a methodology that is leveraging techniques used in medical field, more specifically in ophthalmology, to determine the tortuosity of the narrow veins in human eyes.
The methodology described in this paper produces a tortuosity "density" that has the ability to capture tortuosity at different length scales (from 1 foot to 10,000 feet). It works with conventional directional survey data and/or high-resolution survey as input and calculates a normalized number, the tortuosity (density) index, in real-time. The methodology was applied on the horizontal sections of 18 wells drilled in 2013 and 2014, and the tortuosity indices derived for these wells were compared against reports of drilling dysfunction and non-productive time. The tortuosity index correctly identified problematic wells that had multiple downhole equipment failures during drilling, and showed a strong correlation with other drilling dysfunctions.
The new real-time index provides a holistic view of wellbore tortuosity and may help to mitigate and correct problems before they occur. No new sensors or special practices are needed for the adoption of the method. This index is also robust to changes in survey distance, and provides an indication of micro-tortuosity when continuous/high-frequency gyro data is available.
Using Wired Drill Pipe, High-Speed Downhole Data, and Closed Loop Drilling Automation Technology to Drive Performance Improvement Across Multiple Wells in the Bakken
Authors: Trichel Donald K. , Isbell Matthew , Brown Bruce , Flash Major , McRay Michael , Nieto James , Fonseca Isaac 
Published: January 2016

Abstract
Many operators have developed optimization processes to reduce well delivery time and cost. These optimization processes typically include three basic performance improvement cycles: The first, the Real-time cycle, involves the management of drilling parameters to safely maximize penetration rate and drill bit run length with the drilling system currently in the hole. This cycle moves at a fast pace.The second, the Run-to-Run cycle, involves recognizing and reacting to the drilling system configuration needs based on performance during the run. These adjustments can only be applied to the following bit run or the same interval on a future well. This cycle moves at a slower pace than the first.The third, the Well-to-Well cycle, uses a detailed post-well analysis of performance trends and massive amounts of digital data collected over multiple wells to identify root causes of performance limiters. This knowledge is then applied to the drilling system re-design. This cycle is the slowest of the three.
To accelerate learning, the operator deployed a real-time, closed loop, downhole automation system (DHAS) in conjunction with wired drill pipe in the 8 ¾ in. hole section. The operator also used downhole memory tools in the 5 7/8 in. lateral section to collect downhole drilling parameters and vibration data. Our optimization process drew upon key elements from lean manufacturing concepts. It followed a Plan, Do, Check, Adjust (PDCA) loop, with the DHAS and the data provided by it impacting each of the three concurrently moving performance improvement cycles. The pilot test of the DHAS in the Bakken continued for 16 wells on four different surface locations, or pads.
Thirteen out of sixteen 8 ¾ in. hole intervals drilled with this system exhibited top quartile performance from a rig that had not drilled a top quartile well for over 2 years. As many as 45 hours of invisible lost time were removed from on-bottom drilling in a single hole section, compared to average performance in the same interval for the last three pads drilled with this same rig. Additionally, the operator identified previously unrecognized rate of penetration (ROP) limiters over the course of the project. The key limiter for the 8 ¾ in. vertical interval was a directional dropping tendency of the bottomhole assembly (BHA) which also limited the ability to mitigate the second key limiter, drill bit vibration. Off-bottom practices (e.g., reaming) limited performance for the curve interval. The key limiter for the lateral turned out to be tool failures, resulting from vibration events occurring during on-bottom and off-bottom transitions. The drilling team also learned how each of the performance improvement cycles is affected by the DHAS.
Along String Dynamics Measurements Reveal Isolated Potentially Damaging Upper String Vibration Environments
Authors: Cardy Neil , Hjortland Frode , Jeffrey Christopher , Wilde Simon , Muecke Nick , Wroth Andrew 
Published: January 2016

Abstract
While dynamics studies of drilling Bottom Hole Assemblies (BHAs) have been common since the introduction of downhole vibration measurement tools, little attention has been given to the dynamic environment in the upper drill string. By using distributed recorded mode dynamic subs both in the BHA and higher in the drill string, it has been possible to identify dynamic dysfunctions in the drill string that are not evident from BHA based sensors.
This paper examines offshore wells from the North West Shelf, Australia and the North Sea, which exhibit these potentially damaging vibrations. Data was collected from the downhole measurement tools and merged with surface data to allow the investigation of the BHA and drill string dynamic environments. In addition, high speed data bursts were investigated to understand the finer details of the dynamics. Modelling of the BHA and string to predict the critical vibration modes, resonances and contact forces was also carried out.
The analysis of the wells showed that while the bottom hole assemblies displayed very little torsional or lateral vibration; the upper drill string components were exposed to high energy lateral vibrations. The high energy lateral vibration environments were typically either bound by the rig drive system and contact forces between the drill string and the cased hole or between localized high contact forces in the upper sections of the well. Contact forces can isolate the drill string into distinct dynamic environments, potentially creating high energy destructive events in one section while relatively normal conditions are maintained in the other sections. These isolated drill string dynamic dysfunctions can potentially lead to accelerated drill pipe or casing wear with no obvious cause.
This paper shows how using distributed dynamics sensors throughout the BHA and drill string enables a detailed view of the drilling dynamics in the upper drill string, which previously has only been discussed theoretically. The study also highlights the potential risk for accelerated wear to both drill pipe and casing.