bluuebunny/crossref_metadata_2025 huggingface dataset:
La partícula ra’e en guaraní mbyá. Evidencialidad y temporalidad
Authors: Dolzani Mercedes Valeria
Published: March 2017

Las lenguas de la rama guaraní (familia tupí-guaraní) se caracterizan por marcar tiempo, aspecto y modalidad mayormente mediante partículas libres. El presente trabajo hace foco en la partícula ra’e, primeramente considerada un marcador de tiempo pretérito relativo, pero más recientemente analizada como modal, en particular un evidencial con extensiones mirativas. El concepto de Evidencial de Percepción Diferida es puesto a prueba, y se postula como definición de esta partícula. En el marco de la semántica formal, se advierte que su uso introduce una presuposición de evidencialidad indirecta en los enunciados. Por último, entre los aspectos vinculados con la miratividad, se identifica que el uso de ra’e entraña el hecho de que la información codificada es nueva para el hablante.
Pueblos arroceros en la cuenca del Cebollatí: asentamientos surgidos a partir de la instalación del cultivo de arroz
Authors: Martinez Susana , Mercedes María
Published: March 2017

A partir de la segunda mitad del SXIX, la organización productiva de la explotación de arroz, en la cuenca baja del Cebollatí, dio origen a pueblos arroceros que se han desarrollado en constelaciones  convergiendo en nodos calificados de segundo y tercer nivel, en un paisaje particular y atractivo, donde los aspectos culturales y naturales se combinan. Varios usos productivos han estado asociados a la estructuración del territorio, en  donde la formulación de asentamientos concebidos para la producción y organizados en forma semiautónoma son parte sustantiva. El territorio es un proceso y un producto de prácticas individuales y grupales, en el que conviven   un patrimonio arqueológico- cerritos de indios- , que apelan a las raíces y a los primeros habitantes de nuestro territorio, un paisaje natural de llanuras, esteros, lagunas y montes naturales, y el paisaje cultural generado por el cultivo e industrialización del arroz. Este trabajo se aborda desde la perspectiva territorial: soporte físico más construcción histórica.
Association of Arm Position and Playing Time with Prevalence of Complaints of the Arm, Neck, and/or Shoulder (CANS) in Amateur Musicians: A Cross-Sectional Pilot Study Among University Students
Authors: Kok Laura M , Huisstede Bionka MA , Douglas Taco J , Nelissen Rob GHH
Published: March 2017

OBJECTIVE: In addition to known risk factors for musculoskeletal complaints in the general population, playing a musical instrument is an additional risk factor. In this pilot study, the prevalence of musculoskeletal complaints in student amateur musicians and their relation with playing
posture and playing time were evaluated. METHODS: A cross-sectional web-based survey among amateur musicians studying at a Dutch university. RESULTS: 162 amateur musicians were included in this pilot study (response rate 17.6%). 46.9% of these amateur musicians played with an elevated arm
position. Presence of complaints of the arm, neck and/or shoulder (CANS) was not statistically significantly related to arm position, except for complaints in the left shoulder with an elevated left arm position compared to neutral left arm position (OR 6.7, CI 95% 2.2–20.8) The number
of hours playing per week did not significantly contribute to CANS (OR 1.0, CI 95% 0.95–1.17). CONCLUSIONS: In this pilot study among student amateur musicians, the occurrence of CANS was not significantly related to arm position, except for musicians playing with an elevated left arm
position, which was associated with complaints of the left shoulder (OR 6.7). The number of hours playing per week did not significantly contribute to CANS in this group of musicians.
Could the Addition of Alexander Technique Improve the Effectiveness of Physical Therapy in Reducing Violinists' Neck Pain in Comparison to Physical Therapy Alone?
Authors: Taheri Arman , Lajevardi Mahbod , Shabani Sanaz , Emami Sara , Sharifi Hassan
Published: March 2017

One hypothesis for the mechanism of neck pain in musicians, particularly string players, is changed behavior of the superficial neck flexor muscles and impairment of the cervical stabilization system. To restore the supporting capacity of neck muscles and reduce neck pain, various types
of physical therapies and pain educational modalities have been recommended. However, considering the physio-psychological nature of violinists’ neck pain, its treatment may benefit from addition of therapies that address postural and movement habits. In this regard, we suggest that
management of violinists’ neck pain might benefit from additional approaches that may help to decrease muscle overactivity during performance movements.
Nonlinear Regression Analysis and System Stiffness Approach for Formation Integrity Test Interpretation
Authors: Moi Sonja , Carlsen Liv Almas , Skadsem Hans Joakim , Islam Aminul , Helstrup Ole Anders
Published: March 2017

After drilling out cement at the start of a new wellbore section, a formation integrity test is routinely performed to verify the integrity of the new formation and the cement at the casing shoe. Test results can have large impacts on the drilling operation, such as motivating remedial cementing operations, changing the drilling fluid mass density or the setting depth of casing strings. Interpretation of the test results are often made difficult for a number of reasons, including significant fluid losses to permeable formations, large friction pressure losses, compression of trapped air and unstable pump operation.

This paper presents a new supervisory system providing real-time test analysis and automated result interpretation of pressure integrity tests, leak-off tests and extended leak-off tests. Based on a minimum of preconfigured user input, the system covers all test phases, from pressurization, fracture propagation to shut-in and flowback. Rather than relying on computationally intensive modelling of downhole physics, regression techniques are applied to relate surface pressure to injected fluid volume, shut-in duration and volume or time in flowback.

System compliance and fluid leakage rates are determined prior to leak-off using a nonlinear regression model. The calibrated model is in turn used to generate prediction intervals for detecting leak-off and fracture pressures. Extended leak-off interpretation is based on the system stiffness approach, in which fracture closure is associated with a reduction in system compliance. We apply regression techniques to search for fracture closure during shut-in and during flowback. The system identifies unexpected test behavior and triggers warnings by continuously evaluating key test metrics such as leakage rate, system compliance and surface pressure during each test phase.

The development is based on few model assumptions. Low-pass filtering combined with regression techniques ensure that the system is capable of analyzing field tests of variable quality and with noisy surface sensor measurements. We assess the performance based on historical tests that are representative of the variation in possible pressure-volume behaviors and with typical noise levels on input sensor signals. The system output corresponds well with the original manual test interpretations, and provides in most cases reliable determination of leak-off and fracture pressures, fracture propagation and fracture closure pressures. Real-time test supervisory functionality in addition to standardization of test interpretation and data storage are immediate benefits of system implementation.
Logging-While-Drilling in Cased Hole to Validate Top of Cement Saving Days of Rig Time: Deepwater Gulf of Mexico Case Studies
Authors: Michel Franck , Robbins Ben , Kizziar Steven , Laroussi Nasreddine , Ehiwario Michael , Fike Rivers , Garrett Jonathan , Fuller George A. , Donovan Glenn
Published: March 2017

Evaluation of cement placement is an important part of the majority of deepwater wells. Cement placement confirmation is an important step following a cementing operation. More than one technique can be used to provide information about the top of cement (TOC) and about the depth interval of a good bond between the formation and the casing. Determining the length of annular cement coverage, which is an indication of correct cement placement, is useful knowledge before drilling and/or completion operations can proceed. The requirement for additional and improved cement evaluation techniques is greater now than ever before.

A variety of methods can be used to evaluate cement placement. The routine approach after a casing or liner cement job uses a job chart to calculate lift pressure and actual vs. predicted system pressure. These data enable an estimate of cement height in the annulus to be made, but they do not confirm the TOC. These methods vary in accuracy and difficulty, depending on well conditions. Common TOC evaluation methods in specific wellbore casing/liner sections typically require running a temperature survey or cement bond log (CBL) sensors/systems on a wireline. These operations use the rig's critical path time for each wireline run, which can add risk or difficulties, depending on the well trajectory. In addition, cement bond evaluation for large diameter casing can be technically challenging because it can reach the upper threshold measurement limitations for conventional wireline-conveyed CBL tools.

Many operators now use logging-while-drilling (LWD) sonic sensors for compressional and shear data acquisition in openhole environments. Using the same sonic systems, with minimal additional rig time, logging data acquired through the casing/liner strings while running a drilling or clean out assembly can be evaluated to confirm the TOC.

This paper demonstrates how LWD sonic technology can provide confirmation of the TOC, saving a considerable amount of rig time, as compared to performing a dedicated wireline evaluation run or potentially unnecessary cement squeeze operations. The paper presents and discusses Gulf of Mexico (GOM) case studies. Based on various specific challenges, through correct data analysis, TOC evaluation best practices are implemented to optimize the LWD acoustic data acquisition inside the casing/liner. New data examination techniques are reviewed that can be applied to different scenarios, such as TOC evaluation behind dual pipes and real-time assessment for quick data analysis turn-around. In conjunction with the case studies, the paper also provides information about the LWD cased-hole logging techniques, analysis, and results of the data application.
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

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

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

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

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

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

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

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

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

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

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

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

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.
Ensuring Zonal Isolation During Abandonment with an Innovative Coiled Tubing Placement Technique
Authors: Tanoto E. , Jaffery M. F. , Pasteris M. , Habeahan P. T.
Published: March 2017

A flowing or pressure-sustained annulus is a live threat to the environment, population, vegetation, and natural habitat. In the current oilfield environment under strengthened regulations from regulatory authorities, zonal isolation must be assured before completely abandoning a well. In the west region of Sumatra, Indonesia, a large number of shallow injector wells are drilled; after passing a certain age and productive life, they are abandoned. Most of these wells have lost circulation and therefore need a cost- and time-efficient cement placement method that can demonstrate zonal isolation by means of cement bond logs.

The conventional cement placement method across the perforations requires several steps: placing cement, squeezing, leaving the cement on top of the perforations, waiting on cement, drilling the cement, and running the cement bond log. A novel squeeze method was deployed as a solution by combining a chemical contaminant and a squeeze technique. The objective was to perform the cement bond log directly after wait on cement without spending time to drill out the cement. In this technique, cement was placed using a coiled tubing pump-and-pull method: A squeeze was performed in the perforations; then coiled tubing was run into the well below 30 ft of perforations and an engineered contaminant fluid was pumped to contaminate the cement in the tubing. After the recommended wait- on-cement time, the cement bond log was run to confirm zonal isolation across the perforations. This technique eliminated the need to drill the set cement in the slim tubing, saving several days of work time.

In most of the wells, the cement bond log showed less than 5 mV, which helped to determine the achievement of zonal isolation. Furthermore pressure tests were conducted to ensure the zonal isolation across the perforated intervals.

Engineered cement and contaminant design is required to ensure cement will gain and maintain designed mechanical properties behind the tubing. This paper will discuss the case histories from six wells in the west region of Sumatra field, where the novel coiled tubing placement technique has been applied and proven successful and cost-effective.
Advanced Modeling of Cement Displacement Complexities
Authors: Enayatpour Saeid , van Oort Eric
Published: March 2017

Cement job success is largely determined by fluid displacement efficiency. Optimum displacement requires understanding of flow patterns, frictional pressure losses and mutual interactions of mud, spacers and cement in annular spaces. Modeling this complex behavior is very difficult, but understanding it is essential to guarantee displacement success. A state-of-the-art cement displacement study was carried out using the very latest in computational fluid dynamics (CFD) modeling techniques, to identify practical guidelines and solutions to cement displacement challenges.

A state-of-the-art 3D "3-phase" (i.e. mud-spacer-cement phases) CFD model was created and simulations were carried out, featuring tracking of fluid interfaces during displacement, calculation of frictional pressure drops, and characterization of complex flow profiles. These simulations accounted for the effects of such complexities as non-Newtonian rheological behavior of all fluids involved, eccentric / narrow annuli, and pipe movement / rotation. The integrated study clearly identifies the root cause(s) of cement displacement failures and highlights comprehensive practical solutions, which are proposed for implementation in field operations.

There are many causes for cement displacement problems and failures, including poor borehole conditioning, inappropriate displacement flow rates, insufficient casing centralization, viscosity contrast mismatches between mud-spacer-cement leading to interface instabilities, etc. Our high-resolution finite element study quantifies the effects of many of these causes and highlights parameters that can improve displacement, such as avoiding high shear strength in non-Newtonian mud and cement rheology, reducing pipe eccentricity and applying pipe rotation during displacement. The modeling approach is used to identify optimum parameters values, and studies interdependencies between factors, for instance determining optimum rheology, flow rate and pipe rotation speeds when pipe is placed eccentrically in the hole, in order to maximize the probability of displacement success in the field. Particularly revealing are the non-intuitive results obtained while modeling mud, spacer and cement as non-Newtonian yield power law (YPL) fluids, which has never been done before.

This paper presents: (1) a new, state-of-the-art 3D CFD model; (2) advanced numerical analysis of cement displacement, taking into account complexities such as non-Newtonian rheology, borehole enlargement, pipe eccentricity, and pipe movement during displacement; (3) practical guidelines derived from the modeling results that can be used for improved cement job pre-planning and field application.
Advancements in APB Mitigation for Thunder Horse Wells
Authors: Miller Richard A. , Coy Alejandro , Frank Gustavo , Dondale Aaron
Published: March 2017

A wide variety of annular pressure buildup (APB) mitigation techniques have been deployed in the past two decades. In the early 2000s, BP focused efforts on the development and implementation of rupture disks, nitrified foam spacers, syntactic foam modules and vacuum insulated tubing (VIT). Initiatives to simplify operations while maintaining well integrity have led to innovative techniques which expand the APB mitigation toolkit.

BP's Gulf of Mexico Thunder Horse drilling team has recently pursued three APB mitigation techniques. One method is to fully-cement the annulus, thereby removing the fluid that is subject to thermal expansion in a trapped annulus. A second method uses a qualified port collar to equalize pressure across a casing string. The third method focuses on better acquisition and utilization of mud pressure-volume-temperature (PVT) data for a more precise prediction of the APB design loads.

These methods and techniques have led to the removal of syntactic foam from some wells in the Thunder Horse field. The design change reduces installation time and operational complexity during well construction and abandonment.

This paper provides a description and technical details around the planning and job execution for the fully-cemented annulus and the use of port collars for pressure equalization. It also discusses the motivation behind acquiring PVT data specific to a particular mud system and provides interpretation of laboratory data. The work may be useful for other operators as they plan and execute wells subject to the potential for APB.
Challenges in Elastomer Technology for Drill-Through Equipment
Authors: Berckenhoff Mike , Hack Richard J.
Published: March 2017

Sealing demands have increased due to high and low temperature exposure, intensifying wellbore pressure, and aggressive fluids. Innovative ideas are required to formulate elastomeric compounds and engineer optimized seal geometries in drill through equipment. For static conditions like a BX ring gasket, metal to metal seals generally provide adequate sealing capabilities. However, for dynamic sealing conditions like the actuation of a ram blowout preventer (BOP), elastomers are generally required for well control sealing. The design of annular and ram BOP packers highlight how the use of elastomers with properly designed inserts can close an extrusion gap to improve packer performance. Optimizing the design of the assembly and elastomeric compound is critical to meet challenging performance requirements. Multiple examples demonstrate how laboratory evaluation of elastomeric compounds and full scale component testing improve the final product. Lab tests include procedures such as mechanical properties testing and compatibility testing in drilling mud and other chemicals. Product testing includes full scale fatigue testing, sealing characteristics testing, and temperature testing. The development of annular and ram BOP packers serve as examples of how advances in elastomer technology improve performance and extend service life of drill through equipment.
Statistical Method for Error Prediction in Decision Support and Control Systems
Authors: Aghito Manuel
Published: March 2017

A statistical method for improving the accuracy of predictive mathematical models used in drilling operations is proposed. The scheme can be applied in drilling automation, for example for improving accuracy in automated control systems such as managed pressure drilling (MPD), and for more reliable real-time monitoring and decision support systems.

The proposed method is applied to a simulated case of MPD. Hydraulic model predictions of BHP are continuously compared to PWD readings. A short sequence with varying pump rate is run to train the statistics, which are collected at each pump rate, and refined considering also the pump rate derivative. This is visualized as a 3D surface giving a clear illustration of the error signature of the simulated case. The estimated error is added to the set point of the choke control system, demonstrating a clear improvement of BHP control.

We proposed a new statistical method that uses real-time sensor data to perform automatic fingerprinting of the predictive performance of a given model. The principle is simple but powerful and can be applied to many cases. It can be combined with smart visualization tools in decision support systems, helping to build confidence in the users, or even utilized to adjust the initial prediction for improved accuracy in control systems. The tool is independent of the internal calculations in the mathematical model, and it can therefore be utilized in combination with any model.
Drilling Dynamics Data Recorders Now Cost-Effective for Every Operator - Compact Embedded Sensors in Bit and BHA Capture Small Data to Make the Right Decisions Fast
Authors: Jones Steve , Sugiura Junichi , Rose Karl , Schnuriger Matthew
Published: March 2017

Historically, everyday drilling dynamics measurements rely on the data captured at Measurement While Drilling (MWD) tools. These measurements only provide data at the location where the MWD is placed in the bottom-hole assembly (BHA). Embedding cost-effective sensors at the drill bit, bit box of steerable motor, top sub of the steerable motor and in the BHA provide data at point of insertion giving a much clearer understanding of downhole dynamics. The sensor package discussed in this paper contains 3-axis vibration, 3-axis shock, two temperature sensors and a new 3-axis gyro. The new 3-axis solid-state gyro sensors were added in the data recorder to measure accurate rotation speed, torsional oscillation and stick-slip at the bit, bit box and other parts of the BHA/drillstring.

The data retrieved at the in-bit and bit-box drilling dynamics recorders, along with other points in the BHA, confirmed the effectiveness of "at-point" measurements for correlating bit conditions with downhole drilling dynamics. This granularity of the drilling dynamics data captured "at-point" is typically not seen from an MWD sensor. The in-bit and at-bit measurements revealed critical drilling dynamics dysfunctions that effected bit performance and life. Significant temperature increases at the bit were noted in certain formations where excessive dysfunctions were present.

This paper describes the results obtained from "at-point" sensors while drilling in some of the harsher plays in North America Land (NAL). Using proprietary software, the downhole data was merged with EDR data to show the relationship between surface and downhole. Since the bit is typically semi-decoupled from the drillstring (through the mud motor power section), the data gathered from the in-bit and bit-box sensors provide a new dimension of data for bit and drilling tool development.
Hyperventilation mistaken for local anaesthetic toxicity
Authors: Misurati Mohammad , Allman Louise
Published: March 2017

Local anaesthetic toxicity is a serious complication of regional anaesthesia for which the anaesthetist needs to have a high index of suspicion. The symptoms and signs associated with hyperventilation are similar to, and can mimic, local anaesthetic toxicity.