bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geomechanics of Wellbore Strengthening Revisited: A Combined Theoretical and Experimental Approach with Field Case Studies
Authors: Mehrabian Amin , Savari Sharath , Whitfill Donald , Abousleiman Younane 
Published: March 2017

Abstract
Wellbore strengthening generally refers to the practice of enhancing the lost circulation limit of a (fractured) wellbore through proper design of the drilling fluid system and downhole circulation program. Particulate-based additives, known as lost circulation materials (LCMs), are commonly and often successfully used for this purpose. The use of geomechanical solutions and wellbore stability analysis is currently well established in the industry as standard practice for predrill and real-time estimation of the drilling margin of a nonfractured wellbore; however, an appropriate methodology that quantifies the possible gain in extending drilling margins of the well using the wellbore strengthening technique is lacking in the literature.
This paper proposes a combined theoretical and experimental approach to quantifying the possible extension in the breakdown limit of a fractured wellbore undergoing the LCM-based wellbore strengthening operation. The approach comprises a verified geomechanical model and solution for the stability of the fractured and LCM-treated wellbore, together with the use of in-house experimental data from uniaxial-strain compression testing on LCM products. The model identifies the maximum possible extension in the wellbore breakdown margin, along with an optimal blend type and composition for use in the drilling fluid system. The extension allows for drilling through the troublesome formation without secondary failure of the wellbore wall or unstable propagation of the already existing fracture wings. The obtained extended margin is often recognized to be higher than the wellbore tensile limit or minimum component of the far-field principal stress.
A set of subsurface and operational field parameters from (depleted) sand sections of four wells located in two different regions is used to assess the proposed wellbore geomechanics solution. The maximum drilling fluid density and optimal LCM blend designs that can be reached while maintaining the stability of the fractured wellbore are determined for the selected field case studies. Results compare well with the actual blend design and enhanced drilling margin, allowing the operator to drill through the troublesome formation.
Tubular Connection Integrity: A Comparison of Pipe Makeup Methods
Authors: Amezaga Federico , Liess Martin 
Published: March 2017

Abstract
Tubular connection integrity is a key to short-term and long-term well integrity. The stress on the tubular and the connection, particularly in high-pressure, high-temperature wells, creates challenges for connection providers. Proper selection of makeup method is essential to achieving long-term performance of premium connections.
The tubular running process comprises the use of a tong to make up and break out connections. Over the years many different tong types have been developed, from manual tongs to fully mechanized power tongs. The torque reaction system in the tong plays an important role in providing optimum torque to the connection, which depends on how well it eliminates undesirable side forces on and bending of the connection. Side forces create high friction on the threads that can cause the measuring system to provide an incorrect torque reading, which can result in an undertorqued connection. The friction and compressive forces can also introduce thread galling problems that affect connection integrity.
To evaluate this phenomenon, laboratory tests were performed on a 5.50-in. premium connection joint using two power tongs with three different torque reaction systems (free-floating backup, integral backup, and snub line). Strain gauges and 3D-optical strain measurements were used to analyze forces and deflection acting on the connection during makeup. Results indicate higher side forces and bending on the connection when using integral backup and snub line configurations; however, the free-floating backup system reduces these forces significantly.
This paper first highlights the importance of pipe connection integrity and the consequences when it is compromised and goes on to provide a comparison of the three torque reaction systems and their effect on the connection.
Improved Thixtotropic Barrier Fluid
Authors: Turner Jay , Shumway Bill , Ramirez Jessica , Lovorn Randy , Cedeno Freddy , Mendez Gerardo 
Published: March 2017

Abstract
Managed pressure drilling operations pose several challenges to the upstream oil industry. While tripping the drillstring, the bottomhole pressure of the wellbore must be maintained at the nominal formation pressure, and the solutions currently used have less than optimal success rates in high angle wellbores. A balanced mud cap displaced into the well before a trip can supply the bottomhole pressure required, but the cap is prone to fall through the lighter drilling fluid below. Viscosifying the mud cap is seldom successful, and placing a high viscosity spacer between the two fluids has not been a reliable solution, until now. The spacer chemistry presented in this paper successfully addresses those limitations.
This barrier spacer meets the operational tripping requirements because it is easy to pump and spot, and robust enough to hold the heavy mud cap above the drilling fluid, yet easy to remove when it is no longer required. Since its introduction, some minor shortcomings of the spacer were identified, and a modified formulation has been developed to improve the mixing and deployment of the spacer.
Drill Bit Connections: A Time for Change
Authors: Anderle Seth , Arfele Rob , Hinz Brandon , Shafer Eric 
Published: March 2017

Abstract
Rotary shouldered connections (RSCs) for polycrystalline diamond compact (PDC) drill bits have been unchanged since PDC bits were introduced in the late 1970s. These specifications were carried over from roller cone (RC) bits, which require significantly less torque to fail rock than a PDC bit. Current drilling processes and technologies highlight the need to re-evaluate connection requirements for PDC bits, specifically bits using the 3 1/2 REG connection. The Bakken shale requires extremely long laterals of up to two miles to remain within production zones, which are most economically drilled with a bent housing motor. These long laterals led to significant motor technology improvements for preventing stalls and allowing more weight on bit (WOB), increasing rate of penetration (ROP), and decreasing the number of bottomhole assemblies (BHAs), which reduced drilling costs. These advantages were achieved using a 5-in. motor that has a peak torque output greater than the makeup torque of the 3 1/2 REG connection. Therefore, it is necessary to re-evaluate PDC bit connections.
The connection fatigue index (CFI) is used to compare the fatigue life of connections given a set of parameters. It uses the Morrow strain-life equation to predict fatigue life. A unique feature of the equation is that it takes into account both stress and strain in the plastic region, which is crucial because the last engaged thread enters plastic deformation during makeup. The CFI includes Numbered Connections (NC) 35 and NC38 but does not include the 3 1/2 REG connection; therefore, the starting point for evaluation is to perform the calculations for the 3 1/2 REG connection. Fatigue life was evaluated using the CFI for the 3 1/2 REG, 3 1/2 REG with 1-in. stress-relief groove (SRG), NC35, and NC38 connections for a given bending moment.
Results from the Morrow strain-life equation predict that the NC35 with a SRG will have the greatest number of cycles to failure of the four connections evaluated. Based on the CFI calculations, the NC35 is predicted to last approximately 800 times longer than the 3 1/2 REG, 40 times longer than the NC38, and 10 times longer than a 3 1/2 REG with 1-in. SRG. The following thread form characteristics account for the exponential increase in life of the NC connections over the 3 1/2 REG: larger pitch diameter, SRG, larger root radius, and reduced taper angle. The NC35 connection was then field tested in a Bakken shale lateral.
As well plans are modified for shale drilling and motor technology advances, connection advances are also required. At a minimum, the makeup torque of the connection should be greater than the torsional output of the motor to prevent downhole makeup, mud seal galling, and reduced fatigue life.
An Offshore Drilling Company's Approach to Process Safety Management
Authors: Gidley John K. , Campbell Dustin L. 
Published: March 2017

Abstract
A global offshore driller has developed and successfully implemented a process safety management framework that provides for the identification, documentation, maintenance and verification of technical, organizational and procedural barriers, by which it manages safety-critical elements on board its Mobile Offshore Drilling Units (MODU) to prevent or mitigate precursors to major accident events.
The paper discusses in detail: the overall barrier management model; the necessary prerequisites to implementing process safety management throughout an operational fleet; the means by which knowledge of subject matter experts is captured to manage risk; a barrier audit methodology; and developing key performance indicators. It also discusses how important senior management engagement is in achieving a balance in focus on injuries to individuals and threats to the entire MODU.
Incident data regarding well integrity, marine integrity and fire/explosion incidents is being actively captured and these data categories, which are seen to represent the most significant process safety threats in an offshore drilling environment, were retroactively applied to earlier incident data to provide a total of 7 years analysis. This empirical data provided the basis for developing a detailed process safety incident classification scheme by which each incident is classified according to its actual and potential outcome. In turn, a number of leading and lagging indicators were derived, together with a meaningful Process Safety Incident Rate calculation method that has been incorporated into company metrics with a view to continual improvement.
Moving the concepts of process safety to offshore drilling has been a challenge, with a number of elements required for successful implementation. This paper examines each of these elements and how they combine to form a cohesive and scalable management system designed to protect the lives of those offshore and the environments in which they work.
Development of Experimental Equipment and Procedures to Evaluate Zonal Isolation and Well Abandonment Materials
Authors: van Eijden Jip , Cornelissen Erik , Ruckert Frank , Wolterbeek Tim 
Published: March 2017

Abstract
Extensive set of experimental set-ups have been designed and build to evaluate the sealing performance of systems for zonal isolation and well abandonment. The fully automated test procedure enables the comparison of systems under identical conditions (P, T). Additionally a novel set-up has been built to concurrently measure the internal and external volumetric change during the hydration reaction of cement systems at well conditions.
Maximizing Extended Reach Drilling Efficiency with Unconventional Thinking
Authors: Hooff Gerritt , Hinke Sean 
Published: March 2017

Abstract
This case study outlines how drilling times and costs were reduced for an oilsands steam-assisted gravity drainage (SAGD) operation. It describes the primary challenges encountered when attempting to streamline the drilling process and how generally accepted solutions to these problems are not necessarily the best ones. The evidence presented demonstrates how unconventional approaches to drilling optimization resulted in substantial reductions in the time and cost while also improving wellbore placement, quality, and repeatability.
The primary challenges identified when attempting to reduce drilling times were as follows:
Ineffective hole cleaning while increasing the drilling rate of penetration (ROP). Increased downhole tool damage resulting from excessive torsional and axial shocks, stresses, and abrasion. The inability to directionally place the wellbore as required while maintaining a high ROP.
The challenge was to adjust drilling parameters and bottomhole assembly (BHA) designs to reduce drilling times and costs without sacrificing wellbore quality or BHA reliability.
Through careful modelling, adjustment, and measurement over the course of an 11-month optimization program, drilling costs were reduced by 25% per well and the below rotary table time was reduced by 28%. The primary discovery from this process was that, contrary to traditional understanding, increasing drilling ROP and rotary speed can actually result in improved BHA reliability, directional wellbore placement, hole cleaning, borehole condition, and liner run times. The key to realizing these improvements is careful BHA design and drilling parameter refinement to ensure that the entire drilling operation is optimized to be fit-for-purpose for fast, efficient, and reliable drilling.
This paper discusses how using a conservative approach might be detrimental to drilling efficiency and that what is perceived as aggressive drilling practices could actually be beneficial when there is an intimate knowledge and understanding of the drilling environment. As a result of this mindset shift, tens of millions of USD per year in drilling cost savings have been realized.
Pragmatic Analytics of Control System Alarms for Improved Drilling Performance and Equipment Maintenance
Authors: Goetz Christopher 
Published: March 2017

Abstract
Drilling Control Alarms Systems (DCAS) leave much to be desired. Excessive alarm volumes on Integrated Control Systems (ICS) lead to Driller alarm blindness and exceed all industry recognized standards. Additionally, most maintenance crews do not typically have a filtered prioritized list on a dedicated Human Machine Interface (HMI) consol. This results in critical alarms being ignored, maintenance crews being reactive and preventative maintenance opportunities not being taken. There is almost zero connection to user performance capabilities and enhanced interface training. Safety performance personnel do not consider alarm management in their scope of consideration in efforts to educate, train and reduce incidents.
A typical 6th generation offshore rig generates hundreds to thousands of driller alarms every day. Counts can range from 6000 to 50000+ in a seven day period. Even the best case scenario of 1 alarm per minute is deemed unacceptable by the Norwegian Petroleum Directorate (NPD now PSA) as illustrated in TABLE 1. Other recognized standards including ISA 18.2 and EEMUA 191 mirror these expectations.
Table 1 from Principles for Alarm System Design, February 2001, YA - 711, Norwegian Alarm Rate Consequence 1 alarm per minute Very Likely to be unacceptable 1 alarm per 2 minutes Likely to be over-demanding 1 alarm per 5 minutes Manageable 1 alarm per 10 minutes Very likely to be acceptable
Petroleum Directorate
Several other commonly recognized complaints include:
Poor Prioritization Unclear meaning and vague required action No tie to equipment performance optimization or crew training competence Absence of Alarm Management and Management of Change (MOC) Underutilization of technology; wireless communication, iPad workstations, etc. Lack of a clear Alarm Management Philosophy by vendors or contractors
Kingston Systems believes that there is significant unutilized value in these alarms. Value that can lead to crew training opportunities, improved preventative maintenance practices, higher safety standards, and lower operating costs. With these goals in mind, Kingston Systems has made available consulting services and web tools that can facilitate the extraction of enhanced value from the alarms that are typically ignored. We have outlined a few case studies in which our enhanced analytics tools led to cost and time savings from otherwise overlooked alarms.
Tripping Operations Optimized Through Closed-Loop Vision Technology
Authors: Vintervold Y. S. , Holmstrøm M. , Rosano H. 
Published: March 2017

Abstract
Image sensor technology transforms traditional rig floor drilling processes. It can replace manual functions, such as visual verification of correct iron roughneck jaw position, and improve the efficiency of operations such as physical adjustment of tool height, by adding automation. The presented system uses an imaging sensor installed in a remote, static position with a clear line-of-sight to well center. Custom algorithms automatically resolve the height and (optionally) the diameter of a pipe in well center. The system continuously processes images, correlates these against machine states, and shares the results with the control system and the operator. The measured height is then used to optimize the iron roughneck trajectory from the initial position to the correct make-up position, reducing the overall time needed to perform trip in and standbuilding processes. The system measures and reports the correct pipe height in 98.7 % of the test experiments, and is capable of improving connection efficiency by 26.2 % on average, as well as increasing consistency when compared to conventional operations.
Case History: How to Enable the Horizontal Development of Shallow Reservoirs
Authors: Mathis Wolfgang , Strand Harald , Hollinger Gerald 
Published: March 2017

Abstract
Substantial volumes of oil and gas reserves have been discovered in the Norwegian sector of the Barents Sea. This will give numerous field developments opportunities in the years to come. However, some of these oil reserves are located within thin reservoir beds which maybe as shallow as 200 to 250 m TVD below mudline, which results in development drilling challenges to economically develop these reserves. The case study discussed in this paper shows how the use of a modern top hole well design can help facilitate the economic development drilling of these reserves.
OMV (Norge) AS have drilled a set of exploration and appraisal wells in the production license PL 537 located about 350 km north of Hammerfest, Norway. The appraisal well "Wisting Central II" was planned as a horizontal well with three main objectives. The first objective being to prove that it is possible to penetrate such shallow reservoirs horizontally, the second one being the need for a representative production test from the reservoir and as last objective to gain appraisal information like oil water contact, reservoir data, etc. All well objectives were achieved according to plan.
This paper will present one of the key technologies that enabled the 1.4 km long horizontal reservoir section, at 250 m TVD below mud line, to be successfully drilled and tested. Typically in these wells the conductor would be set 50 to 60 m below mud line which would significantly reduce the probability to successfully build the hole angle up to horizontal at the desired reservoir entry point due to the limited TVD available.
Therefore, the plan was to substantially shorten the conductor, and to integrate it into a suction anchor based well foundation, a Conductor Anchor Node (CAN®) in what is now known as a CAN-ductor design. This structure provided the required load capacity and allowed the conductor to be as short as 11 m below mudline. This allowed sufficient TVD for building hole angle and achieve the horizontal reservoir entry point at only 250 m TVD below mudline. Thereby, this well could be successfully drilled as planned, to become the shallowest horizontal well ever drilled from a floating drilling unit.
Since the installation of the CAN with integrated conductor is performed by a vessel ahead of rig arrival the technical benefits are further supported by an overall cost reduction as rig time is saved by not having to drill the conductor hole section and subsequently run and cement the conductor. Further cost savings are achieved due to the fact that no remedial and top up conductor cement jobs are required when using the CAN concept. To be noted is also that the wells P&A operations are simplified.
Transitioning the Directional Driller Off the Rig
Authors: Hildebrand Ginger , Torre Ariel , Hopewell Joseph , Olesen Lars 
Published: March 2017

Abstract
Given the recent advances in rig site communications and motor steering advisor software, directional drilling operations can now be directed by a directional driller in a remote operations center rather than at the rig site. This allows better utilization of expertise across multiple jobs, the ability to engage experts/specialists when needed, and closer collaboration with the operator.
This paper reflects the experience of transitioning through a series of steps from a traditional directional drilling operational model of two directional drillers working opposite shifts at the rig site to a reduced crew model. The key enablers allowing this operational change were: 1.) a software advisor and monitoring system that assisted the remote directional drillers in making steering decisions and monitoring the result of motor steering operations 2.) shifting the accountability for the physical aspects of the directional drilling workflow to the driller, such as picking up/laying down the bottom hole assembly and executing slides.
This study demonstrated that directional drillers can be effectively moved off the rig site without degradation in performance and without introducing additional safety risks as long as the proper enablement is in place. On an example job, the drilling crew used a reduced personnel model assisted by a directional advisor system to drill an S-shaped well approximately six days faster than the fastest previous offset well. The directional drilling process became transparent with continual evaluation of key performance indicators. A clear record of the intended operations was produced along with a comparison of the actual executed operations and the results achieved.
A Synchronized Rigsite-to-Office Approach to the Management of Automated Torque and Drag Data
Authors: Borjas Ricardo , Creegan Andrew , Perdomo Angel , Caraway Jennings 
Published: March 2017

Abstract
This paper describes an automated system for the capture of torque and drag (T&D) data that can alert the driller to impending issues. The automated system is managed by a real-time operating center (RTOC) that utilizes live T&D data to make informed recommendations to the driller.
The system utilizes existing high-frequency surface sensor data to sample hookload and torque and, through an automated system, intelligently determines T&D data. This data is displayed to the driller and managed via a rig floor mounted human-machine interface (HMI). An RTOC is employed to remotely manage this system and provide the driller with feedback and recommendations on remedial action based on observed wellbore conditions.
This continual feedback loop of actual T&D data to the RTOC also allows for a more accurate model to be updated and simultaneously displayed on the driller screen while drilling. An updated friction factor roadmap provides the driller/RTOC an accurate reference point for their T&D data.
Given the multitasking nature of a driller's job, it has been seen that T&D information can be overshadowed by other operational matters. It is observed that the automatic update of friction factors and automated, intelligent hookload and torque alarms can alert a driller/RTOC of impending problems that may be missed otherwise.
Historically, T&D had been manually recorded by a driller and periodically sent in to the office or calculated at an RTOC but disconnected from the rig floor. By applying "capture" logic to raw, high-frequency sensor data, we can now get consistent and reliable T&D data that is immediately available to the driller, the RTOC, and the drilling team.