bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analytical Model to Estimate the Drag Forces for Microhole Coiled Tubing Drilling
Authors: Zhang Yuan , Hao Ye , Samuel Robello 
Published: March 2013

Abstract
Microhole coiled tubing drilling is a new technology that provides many added advantages but at the same time poses numerous operational challenges. This manifests itself in a number of ways, all of which adversely affect the efficiency of the drilling process. These problems include increased wellbore friction, poor hole-cleaning, tubular failures, and associated problems during tripping operations. Presently conventional torque and drag models are used to calculate drag forces and surface loads during microhole coiled tubing drilling. However, these estimates might be under conservative. Therefore, an improved model and more comprehensive analysis are required.
Conditions expected during microhole coiled tubing drilling are completely different from those encountered during conventional drilling. Further complexity is added when the wellbore is undulated. This paper describes a new analytical model for estimating drag forces by assuming that pipe in the horizontal portion follows a sine function wave due to residual bends and snubbing force. In addition, the model takes into account when the wellbore is also tortuous. Fluid viscosity (an important force in the microhole) is also included so we can calculate appropriate surface loads in addition to drag. This study concludes that besides wellbore inclination, curvature, and wellbore torsion, parameters such as wave length and contact area also influence the results. This paper documents the comparison between the predicted mathematical simulation results with actual data from wells describing the accuracy and applicability of the model. The analysis results and comparison are presented along with three examples.
Practical Guide to Lost Returns Treatment Selection Based on a Holistic Model of the State of the Near Wellbore Stresses
Authors: Duffadar Ranojoy D. , Dupriest Fred E. , Zeilinger Sabine C. 
Published: March 2013

Abstract
This paper presents a holistic model describing the relationship between the state of the hoop stress in a given well and the selection of lost circulation treatments. While some losses are vugular, the majority of lost returns events are due to the propagation of a fracture that develops when the borehole pressure overcomes the total hoop stress, which is the stress holding the hole closed. Although methods such as casing drilling, lost circulation pills or continuous fracture sealing fluids appear dissimilar, each stops losses by modifying the hoop stress. If a treatment does not modify the stress holding the hole closed, it does not change the pressure at which the borehole will open. This unifying concept is not always apparent to engineers and operations personnel since treatments are described to act in ways as diverse and seemingly unrelated as tip plugging, sealing, smearing, etc. Consequently, those who develop and execute new treatments may not be asking important questions that could further improve treatment performance and operational practices.
In the proposed model, the potential state of the hoop stress is placed on a single pathway that is divided into four distinct regimes. At one end of the spectrum are those treatments that prevent losses by simply ensuring that the ideal hoop stress predicted by Kirsch is preserved. At the other end of the spectrum are severely depleted wells where treatments must achieve very large increases in hoop stress. Common industry treatments are categorized by the hoop stress regime in which they are applicable, and the conceptual limit to which each might enhance integrity is discussed.
The authors' purpose in describing these concepts and treatments within a holistic hoop stress continuum is to improve treatment selection, facilitate field diagnostics, and highlight the need for further research in some areas.
Operational Control and Managing Change: the Integration of Non-technical Skills with Workplace Procedures
Authors: Thorogood J L , Crichton M T 
Published: March 2013

Abstract
Some of the common pitfalls and problems associated with managing operations are discussed with suggestions about how these can be addressed. Existing literature on human error, operational decision-making and industrial psychology is combined with the authors' experience in researching these problems and working with operations teams. The non-technical skills required to manage operations effectively are described together with the organisational structures and work processes that best support operations. Techniques for training teams and helping them to develop the competencies for teams to manage operations safely and deal with uncertainty are explained.
Mindful that "Proper planning prevents poor performance", engineers go to considerable lengths to create quality plans. A structured well delivery process is followed, complete with peer reviews, risk assessments and technical sign-offs. Deliverables include statements of requirements, basis of design documents, HAZID sessions, drill the well on paper meetings and a drilling programme.
Despite these preparations teams make decisions during operations with sometimes costly consequences, especially when surprised by an unexpected event or when facing high levels of uncertainty. This problem is not unusual and typically occurs when teams fail to prepare and actively manage the transition from planning to operations, and to anticipate the necessary change in the functioning of the team. Planning and operations require completely different modes. The lack of preparation for this transition stems from a common assumption that the team that has done the planning is more than capable of managing a dynamic operation effectively. Research has identified that two different modes are required; planning teams produce a plan designed to solve a problem, whereas an operations team has to manage a task requiring the ability to adapt dynamically to shifting demands of the situation.
Effective operations management requires a high degree of operational discipline and teams that are skilled in dealing with the unexpected and making decisions in time-constrained situations. These skills are not intuitive and must be taught, trained, practised and assessed. The protocols and decision rights must be clear and the team trained so that it executes these functions in a fluent and competent manner.
Evaluation of Filter Cake Mineralogy in Extended Reach and Maximum Reservoir Contact Wells in Sandstone Reservoirs
Authors: Ba geri B. S. , Al-Majed A. A. , Al-Mutairi S. H. , Ul-Hamid A. , Al-Sultan A. S. 
Published: March 2013

Abstract
Good knowledge of filter cake structure and composition leads to successful selection of drilling fluid that minimizes formations damage and selection of an effective and efficient recipe for removing the filter cake.
This study focus on an aspect which was not fully covered in the literature: the chemical characteristics of filter cake formed along the horizontal well, from its heel to its toe. High pressure fluid loss tests were performed using real drilling fluid samples from the field which were collected during drilling horizontal section of a sandstone formation. The mineralogy of the external filter cake formed by fluid loss cell is determined using both Scanning Electron Microscopy (SEM) and X-Ray Diffraction (XRD).
The results showed that for long horizontal sections, the composition of the filter cake was not constant from its heel to its toe since the small drilled cuttings or particles, that are not completely removed, were mixed with the drilling fluid during circulation and become an integral part of the fabric of the filter cake.
Operational Reliability Assessment of Conventional vs. MPD on Challenging Offshore Wells
Authors: Don Hannegan P. E 
Published: March 2013

Abstract
Value-added efforts towards determining the optimum approach to drilling challenging offshore prospects include applications of reliability centered strategy early in the planning process. The objective would be to determine the drilling method with highest probability of enabling a safe, on-time and on-budget drilling program that reaches total depth objective with large enough hole for viable production.
Reliability assessments focus on probability of successful functioning; fit for a purpose, resistance to failure, ability to perform a required function for a definitive period of time, and ability to fail well. The reliable performance of the hydraulics of the circulating fluids system itself, even if the encountered pressure environment is not within the predicted drilling margin of error, is critical for operational success.
This presentation applies Reliability Engineering skills to a HPHT prospect whose water depth and formation pressure map suggests risk of kick-loss scenarios, differential sticking, cementing challenges and TD with too small a hole. An offset well's actual experience with conventional drilling methods will be compared with an operational reliability assessment of applying some applicable variation of managed pressure drilling (MPD) on the proposed well.
Reliability theory became a creditable science during the early days of sail ships to inform investors of the reliability of a vessel to return safe & sound.1 The author proposes that operational reliability concepts remain valuable in marine environments and are uniquely applicable for the purpose of choosing the optimum drilling and well construction methods for drilling challenging offshore drilling programs.
New Generation Thermally Stable Cutters Deliver High Penetration Rates While Maintaining Durability in the Troll Field, Norway
Authors: Roberts Tom , Hæreid Olav 
Published: March 2013

Abstract
One of the main challenges drilling within the Troll field, offshore Norway is maintaining a high Rate of Penetration (ROP) while drilling through hard calcite cemented stringers (Jones et al. 2008a; Gunderson et al. 2008). The calcite distribution in this field is complex and can be difficult to predict, while it is easy to maintain a high ROP when drilling the sand sections between the stringers. Early wear or damage to the cutting structure limits the bit's ability to apply sufficient point loading to efficiently cut through the calcite and remaining lithologies, so the key aspects in solving this challenge is to retain the sharpness of the Polycrystalline Diamond Compact (PDC) cutters and minimize the risk of impact damage when hitting these thin inter-bedded stringers at high penetration rates.
Following an in-depth study of the application, the drill bit design evolved following several iterations that included computational fluid dynamics to optimize fluid impingement angles and reduce fluid induced shear stress on both the bit body and cutter substrates. Torque control components were introduced to improve the design's response to weight-on-bit, minimize stick-slip and improve directional response. Detailed laboratory tests were conducted to investigate a new edge preparation applied to a new thermally stable PDC cutter, and the cutter-rock interaction was modeled to investigate complex wear, involving impact, abrasion and thermal mechanisms, while drilling these highly inter-bedded formations.
The results of this research led to new cutter and bit technologies which have proven that the combination of improved thermal resistance and more efficient cutter geometry enables the cutters to stay sharp while drilling through the hardest stringers and maintain greater durability to complete the section. The improved designs have now drilled further and faster than any previous attempts, resulting in significant cost savings for the operator.
Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well
Authors: Gradishar John , Ugueto Gustavo , Van Oort Eric 
Published: March 2013

Abstract
This paper details the case history of the highly challenging extended reach deepwater A-10 well, drilled in the Ursa ("Bear" in Latin) prospect in the Gulf of Mexico. This 30,000 ft well, drilled from the Ursa TLP at a vertical depth of 18,000 ft and a horizontal displacement of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole, a subsequent sidetrack and two mechanical bypasses, a number of significant hole problems materialized which caused extensive non-productive time and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high deviation and extended reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the Gulf of Mexico's challenging geopressured environment. In all, at least five independent borehole failure mechanisms were encountered while drilling the original hole and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor:
Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10 original hole. Lost circulation in induced fractures, with associated heavy mud losses. Borehole fatigue, caused by stress cycling on weak formations due to annular pressure fluctuations. Borehole instability caused by too low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 sidetrack 1. Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 sidetrack 1 bypasses 1 & 2, and ultimately forced the well to be completed in shallower Magenta sands. Complicating Factor: barite sag of synthetic based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms.
An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices (for hole cleaning, ECD management, sag control etc.), and the development of new systems (including novel, sag-resistant synthetic-based mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here in order to help the future drilling of extended reach wells in geopressured, low-margin deepwater environments.
Drilling Unconventional Shale Wells Remotely
Authors: Gongora Cesar , Awan Omar , Mota Jose , van Oort Eric 
Published: March 2013

Abstract
After a successful pilot application in the Haynesville Shale, Shell Upstream Americas is currently taking steps to conduct all of its directional drilling, MWD/LWD and geosteering operations in the Americas and beyond from remote drilling centers. The main drivers for the use of these centers are:
More wells can be directionally drilled with the involvement of the most knowledgeable / most experienced directional drilling / MWD/LWD / geosteering staff, while at the same time new staff can be trained and developed effectively from a central location. Safety is improved by having less staff commuting back and forth to the rig site (i.e. reducing the number of driving-related accidents), and by reducing occupational exposure through the decrease in number of people "in harm's way" present at the rig-site itself. Remote geosteering at a central facility allows for efficient communication between geologists and interpreters, with a single geosteering expert and a single geologist being able to handle a large number of geosteering operations at the same time, while at the same time greatly improving the speed of decision-making. Staying within the shale target zone and reduction of the number of geosteering corrections and doglegs while landing the horizontal section, resulting in noticeably improved wellbore quality, which yields immediate benefits in the ease of running production casing and will ultimately translate in higher hydrocarbon recovery.
The learnings and best practices associated with the ongoing implementation of the remote drilling centers for unconventional shale drilling operations in the Americas are compiled. This includes a review of the technologies involved, the new workflows that were implemented, how the "people issues" were addressed, and what results - including a 90% improvement in the speed of decision making, clear improvements in wellbore placement and quality, and the drilling of best-in-class directional wells in the Eagle Ford Shale - were obtained. In addition, the future of remote directional drilling and its extension into drilling automation is briefly discussed.
Innovative Rolling PDC Cutter Increases Drilling Efficiency Improving Bit Performance in Challenging Applications
Authors: Zhang Youhe , Baker Ryan , Burhan Yuri , Shi Jibin , Chen Chen , Tammineni Sandeep , Durairajan Bala , Self Jordan , Segal Steven 
Published: March 2013

Abstract
Extended footage capabilities and high rate of penetration give PDC bits a distinct advantage over rollercone bits in many applications. However, the fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts the formation, and as the cutters wear/chip drilling efficiency declines. The industry requires new technology that can effectively utilize the entire 360° diamond cutting edge to reduce frictional heat/wear while increasing drilling efficiency and bit life.
A plan was initiated to rotate the cutter while drilling and engineers investigated different retention methods and cutting structure designs to create the optimal driving force to accomplish the objective. Several designs were implemented that hold the cutter securely in place and allow full cutter rotation. These assemblies were extensively modeled using FEA and laboratory tested to evaluate function and strength. In a test apparatus, the new shearing element (rolling cutter/RC) was able to cut an extended section of rock with a consistent force level (lbs). Conversely, the traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency.
Initial field testing targeted the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. Application challenges include slow ROP and premature tripping for a new bit. A six-bladed prototype PDC bit was manufactured with three rolling cutters positioned in the shoulder area. The bit was run on a steerable motor through the horizontal interval with good results. The next prototype was equipped with additional RCs and drilled more footage compared to offset average. Additional experiments are being conducted with RCs which will continue to increase performance. The authors will present several case studies which will document performance improvement in challenging drilling environments.
Industry's First Hydro-Mechanical Surface Controlled System for Multiple Reamer Activation/Deactivation Increases Drilling Efficiency
Authors: Torvestad Bjoern Tore , Bjoerneli Hans Magnus , Toerge Ketil , Andreassen Lars , Haavardstein Stein , Blikra Harald 
Published: March 2013

Abstract
Using a concentric underreamer is a widely used technique for efficient wellbore construction. Most underreamers are fitted with lock-out systems to provide a means of drilling out the shoe-track with the cutters closed before enlarging the tool below casing. Several underreamers also provide a system to lock the tool closed after reaching TD to enable full flow while POOH for best possible cleaning. However, a major limitation these systems have in common is the underreamer cannot be reactivated once closed and the tool must be placed at top BHA due to the activation method.
To increase reamer efficiency/BHA flexibility, a new hydro-mechanical system has been developed that makes it possible to perform multiple activation/deactivation of the underreamer by manipulating the flow rate in a short sequence allowing infinite open/close cycling for selective underreaming and more flexible placement opportunities within the BHA. The concept does not require any form of device to be pumped down the drill string. The system also increases the potential to save rig time on the activation/deactivation sequence.
Through the field testing stage, it has been proven that the system works as designed under difficult drilling conditions. It delivers operator value by having the flexibility to selectively activate/deactivate and save rig time. The majority of runs have been on complex rotary steerable BHAs together with MWD/LWD systems and does not interfere with those tools’ operating range. All criteria set in the comprehensive field testing plan have been met to qualify the reamer as a viable downhole tool system.
Several case studies will be presented to document successful operation of the on-demand surface controlled system with details about operator benefits including downhole flexibility, cost savings and increased safety.
Surge and Swab Effects Due to Vessel Heave in Deepwater Wells: Model Development and Benchmarking
Authors: Chandrasekhar Sharat , Bacon William , Toldo Benni , Suryanarayana P. V. 
Published: March 2013

Abstract
During operations in deepwater wells (such as, for instance, running smart completions), there exist periods when the axial movement of the string in the well remains uncompensated. During these periods, vessel heave is imposed on the string at the surface, resulting in transient pressure fluctuations (swab and surge effects) in the fluid downhole. The problem is further complicated by the presence of multiple flow ports in the string, and of choke and kill lines at surface, as well as float valves in the string itself. As the margin between pore and fracture pressure is narrow, these fluctuations can create conditions for an influx or lost circulation, with potentially significant consequences. While existing literature and commercial models address the classical drill pipe induced swab/surge due to tripping, they do not model multiple flow paths and/or continuous forcing functions (such as heave) at the surface of the drill string or completion string.
In this paper, we present the development of a semi-analytical approach to model such transient pressure problems. The transient pressure problem is solved using the method of characteristics, and draws from the seminal work of Lubinski et al. and employs the electrical analogy first proposed by Bergeron (Water hammer in Hydraulics and Wave Surges in Electricity", John Wiley, 1961). The method is extended to include Power-Law fluids (as well as Bingham Plastic and Newtonian rheological models). Arbitrary flow ports can be situated anywhere in the string, with either one or two-way flow. Both open- and closed-end pipes are considered, in addition to nozzles at the pipe end. Temperature and pressure effects on the compressibility, as well as the elasticity of the formation, are considered in the calculation of the characteristic impedance. The approach can accept any arbitrary forcing function at surface, either as a periodic wave or as a tabulated time function of displacements. Several limitations of the previous models are also addressed in the theoretical development reported in this work.
The method is implemented in a spreadsheet tool that allows the input of a wide variety of situations, incorporates different fluid PVT and rheology models, and calculates transient pressure at any point of interest in the annulus. The model is compared to several benchmark field cases in the literature, and the comparison is shown to be very satisfactory. Finally, a case of a smart completion with one to four flow ports in the lower sections that can be selectively closed or opened, subjected to sinusoidal vessel heave at surface, is examined. Results show that the pressure fluctuations can be substantial in some of the cases, and suggest that with appropriate fluid selection and operational procedure, even large heave can be sustained without initiating either underbalance or lost circulation.