bluuebunny/crossref_metadata_2025 huggingface dataset:
Desarrollo del entorno personal de aprendizaje para tutoría e investigación en niveles educativos superiores
Authors: Dzib Goodin Alma , Castevich John , Hogan Dolores Luna , Sanders Linda , Slovec Kathleen , Yelizarov Daniel
Published: January 2016

El concepto de entorno personal se refiere a los sistemas que facilitan a los aprendices a tomar control de manera autónoma sus aprendizajes. Esto incluye apoyos para determinar sus propias metas, comprensión de contenidos y de los procesos implicados en el proceso de aprendizaje. Usualmente el mayor impulso se ofrece en torno a las nuevas tecnologías, ya que se supone que el alumno es capaz de interactuar de manera efectiva con los lenguajes y entornos  tecnológicos, pues más jóvenes las generaciones, más conocimiento tienen del uso y manejo de la información en medios digitales.

Partir de este supuesto, y suponer que el alumno es capaz por si mismo de encontrar su propio camino, lleva a mucha frustración, especialmente cuando se considera como factor clave las diferencias culturales.

El presente trabajo busca reconocer que existen diferencias culturales en el manejo de herramientas que se considerar usuales como las redes sociales para desarrollar propuestas académicas que permitan apoyar el aprendizaje de los estudiantes y se encuentra que existen factores que pueden potencialmente beneficiar o entorpecer el desarrollo académico de los estudiantes si estas no son consideradas en los programas educativos.

Reconocer dichas diferencias es clave para trabajar en programas de apoyo a los estudiantes, pues una vez que éstos reconocen sus potencialidades y son capaces de generar las estrategias adecuadas a los requerimientos de las nuevas tecnologías, serán más eficientes en su aprendizaje.
Wrong-Site Surgery in Orthopaedics: Prevalence, Risk Factors, and Strategies for Prevention
Authors: Santiesteban Lauren , Hutzler Lorraine , Bosco Joseph A. , Robb William
Published: January 2016

➢ The incidence of wrong-site surgery in orthopaedics is unknown. This is due to a lack of data regarding the exact numbers of surgical procedures performed and a lack of a uniform mandatory error reporting infrastructure.

➢ Twenty-one percent of hand surgeons, 50% of spinal surgeons, and 8.3% of knee surgeons surveyed have reported performing at least one wrong-site surgery during their career.

➢ Every orthopaedic surgeon, no matter his or her orthopaedic subspecialty, is at risk for completing a wrong-site surgery during his or her career. Prevention of wrong-site surgery should remain a priority for the orthopaedic community.

➢ Surgeon leadership, commitment, and vigilance are critical to improve patient safety by ensuring that validated safety processes are used in all orthopaedic settings including effective surgical team communication, checklists, and routine collection and analysis of quality and safety data.
Lithofacies Classification of Thin-Layered Turbidite Reservoirs Through the Integration of Core Data and Dielectric-Dispersion Log Measurements
Authors: Pirrone M.. , Battigelli A.. , Ruvo L..
Published: January 2016

Distal turbidites consist of thin laminations (inch scale), usually ranging from fine sand to clay-rich deposits and may represent major hydrocarbon reservoirs: Conventionally, they are studied by means of a log-based binary modeling that discriminates productive and nonproductive layers. Nevertheless, the binary model represents a major drawback when dealing with laminations in the silt-grain-size range, because their allotment to either end member can be extremely problematic.

This paper deals with a novel, probabilistic, lithological facies-classification approach that integrates core data and a high-resolution dielectric-dispersion wireline log: Its 1-in. vertical resolution and a related fit-for-purpose petrophysical model make the log tool's response suitable to describe the lithological heterogeneity of these reservoirs.

The approach is presented by means of a study performed on the cored section of a well drilled into a laminated gas-bearing Pleistocene reservoir in the Adriatic Basin. A core-based classification was first carried out with sedimentological descriptions, mineralogical analyses, cation-exchange-capacity (CEC) measurements, routine and special core analyses, and a statistical investigation of grain-size distributions: This allowed the identification of four lithofacies ranging from hemipelagite to coarse silt. Next, a log-based classification was carried out with a multivariate statistical numerical technique integrated in a Bayesian framework run on the dielectric-dispersion model curves. The outputs are the probability of log-facies, the most-probable facies scenario, and the associated uncertainty by means of entropy computation. In the end, a four-facies log-based classification was obtained that matches the core-based classification with an overall agreement in excess of 93%.

Compared with the conventional methodology, the presented approach shows the added value of identifying intermediate lithologies, thus leading to a more-accurate quantification of the thickness of the potentially hydrocarbon-bearing net reservoir.
An Integrated Work Flow for a Comprehensive Evaluation of Thin, Silty Hydrocarbon-Reservoir Sequences
Authors: Chu Wei-Chun , Steckhan Jan
Published: January 2016

A robust work flow is established to identify low-resistivity pay (LRP) in thinly laminated sands with silty and/or shaly layers. The work flow integrates data from gas-while-drilling, conventional logging, and nuclear-magnetic-resonance (NMR) logging for picking intervals for further examination with a wireline formation tester (WFT). A mini-drill-stem test (DST) is performed by means of a WFT equipped with either a single probe (SP) or a dual packer (DP) to determine the fluid type and productivity of each individual level.

Two field examples are presented to compare well performance predicted by the microscale mini-DSTs with macroscale production tests. In both cases, the traditional DST is eliminated from the drilling/completion program. The final verification consists of comparing contributions of individual levels derived from the mini-DSTs with production logs.

In the first case, mini-DSTs are able to provide the fluid type and individual-level transmissibility (kh/μ) for eight out of 13 distinct levels. A cost-effective approach of running mini-DSTs by means of a WFT equipped with a single probe is demonstrated to investigate multiple levels in the thin-hydrocarbon reservoir sequence. Guidelines are provided as to when a WFT with a DP is to be deployed to perform a mini-DST in a laminated formation.

In the second case, the same work flow was applied to derive the fluid type and transmissibility for two wells consisting of more than 30 distinct levels in the same field. After integrating mini-DST results from the two wells 750 m apart, a framework is constructed to establish both vertical and lateral heterogeneities of thinly laminated reservoirs. The integration helps visualize the multiple-layer reservoir.

Our examples confirm that mini-DSTs effectively define individual-layer producibilities in multiple-layered reservoirs. The benefits are illustrated through case histories that demonstrate our ability to manage expectations of well performance in thin hydrocarbon-reservoir sequences.
A Low-Density Direct Emulsion (DE) System has been Successfully Formulated for Mature Depleted Fields
Authors: Collins Natalia , Chumakov Evgenii
Published: January 2016

A low-density direct emulsion (DE) system has been successfully formulated to minimize formation damage in mature depleted fields.

Key objectives for the DE system are to provide all the functions of traditional reservoir drill in fluids (RDF) in terms of efficient cutting suspension and carrying characteristics, effective fluid loss control and friction coefficient, while minimizing overbalance on depleted formations. Excessive overbalance on the formation would potentially cause severe losses and could result in formation damage, with negative impacts on the environment, and an increase in overall fluid cost. This novel oil-in-water DE system consists of a dispersion with oil as the internal phase, and water as the external phase. It targets densities less than 8.17 lb/gal to minimize overbalance on the formation while providing all the benefits of an emulsion system – enhanced friction reduction, effective fluid-loss control, superior rheology for hole cleaning and minimal ECD, and effective clay inhibition.

Numerous attempts of using DE systems in oil field drilling fluids have been made in the past. However, DE systems have never been fully accepted in industry due to difficulties maintaining the emulsion stability and its sensitivity to common contaminants. A novel thermodynamically stable DE system has been successfully formulated and used to drill a well with no excessive losses or emulsion stability issues.

The paper will present a detailed study of the laboratory development of the DE system along with field application data and lessons learned.
Invasion and Movement of Fluids in Shale Formations and Wellbore Stability
Authors: He Wenwu , Jimbi Esmeraldo , Chamberlin Molly , Zakaria Ahmed
Published: January 2016

The invasion and movement of drilling fluids through shale formations can significantly contribute to wellbore instability. By combining the experimental results with the microstructural studies of core samples, we will examine the invasion and movement of fluids in shale formations near wellbore, including the mechanisms, rates, affecting factors, and impact on shale stability.

Pre-test core studies provided insight into rock composition, structure, fracture distribution, water activity, and pore-fluid composition. Pore-fluid transmission tests were conducted on preserved shale cores from four different formations, each with a different water activity measurement. Thin section analyses of post-test cores were conducted to evaluate shale-fluid interactions and the impact of fluid invasion and movement on shale stability.

Test results show clear evidence of a reverse osmosis process out of the shale. The reverse osmosis increased when the difference between the water activity of the shale's pore fluid and the drilling fluid also increased. A water activity difference of >0.07, and the resulting pore-pressure drop (caused by the reverse osmosis), can subdue the impact of fluid invasion from drilling fluid to formation and led to a net decrease in downstream pressure. Reverse osmosis could cause downstream pressure below the initial value in a few minutes. A pore-pressure drop due to reverse osmosis may improve the stability of wellbore due to an increase in effective drilling fluid support. However, tests show that strong reverse osmosis could cause fracturing from over-dehydration of the shale. Tests also indicate that invasion along fractures increases pore pressure, even with a potential for strong reverse osmosis. Adjusting the water activity of drilling fluids to closely match that of the shale formations while minimizing fluid invasion along fractures and other fluid channels reduces wellbore instability.
Engineered Solutions to Address Deepwater Remedial Cementing Challenges
Authors: Fuller George A. , Mercado Steven , Mead Christopher
Published: January 2016

Performing cementations in a deepwater environment poses many unique challenges during the drilling and completion operational phases in the Gulf of Mexico. These challenges add further difficulty and risk to an already complex operation.

During the course of constructing the wellbore, it may be necessary to perform un-scheduled remedial cementing operations to acheive the main objectives. Squeeze cementing performed to remediate undesireable well conditions which may have resulted during the drilling phase (major mud losses) or as a result of a poor primary cement job (insufficient zonal isolation) must be thoroughly analyzed during planning to understand all the critical parameters needed to execute the right plan.

When designing for a squeeze job, key decision factors during the planning process must be addressed for a successful outcome. The success or failure of a squeeze cement operation relies on 1) understanding what is the objective of the squeeze operation 2) determination of the optimum cement placement depth, 3) development of an effective placement procedure with proper technique and down-hole tools employed, 4) proper design of cementing fluids including washes and spacers, 5) flawless execution with a detailed pressure/rate/volume record of fluid injection, and 6) a meaningful post evaluation of the squeeze operation’s results to determine if objective was met.

This paper will provide guidance on addressing the key decision factors, development of a proper placement strategy, general design guidelines for appropriate cementing fluids to employ, and how to evaluate if the objective was met. Results will be presented from recent deepwater case histories to demonstrate the successful application of this methodology for squeeze jobs and the techniques used.
Vibration Monitoring and Mitigation - An Integrated Measurement System
Authors: Greenwood Jeremy A.
Published: January 2016

Dynamic dysfunctions of the drillstring are extremely complex to model, and it is difficult to produce timely model updates to keep up with the continually changing conditions during drilling operations. This paper describes an integrated measurement system that mitigates the effects of damaging downhole vibration and enables the driller to instantaneously respond and evaluate the effectiveness of corrective actions.

The failure to measure all of the correct parameters will leave the driller blind to the existence of damaging vibration and lead to sub-optimal performance or equipment and drillstring failures. The integrated system of downhole and surface measurements combines a significant amount of surface, downhole, and formation information to help the driller to correctly identify the vibration mechanism and to determine the appropriate response. The system measures the movement of the bottomhole assembly (BHA), the levels of energy generated during episodes of vibration, and the energy going into the system.

The capability to clearly and concisely present the results of the analyses to the driller and to produce recommendations for the correct mitigation strategy is a powerful tool for controlling downhole vibration. Monitoring surface weight on bit (WOB), torque (TRQ), rotary speed (RPM), and standpipe pressure (SPP), and performing a frequency analysis helps to identify vibration signatures for stick/slip and bit bounce. Mechanical specific energy (MSE) calculations determine drilling efficiency. Downhole accelerometer, gyroscope, magnetometer, bending, tension, and torsion measurements used alongside formation evaluation data identify bit bounce, bit whirl, BHA whirl (both forward and backward), torsional resonance, bit chatter, modal coupling, and lateral shocks. A three-tier warning system brings attention to the presence of vibration, supplies the mechanism and corrective actions, and provides detailed analytical information to the expert. Tracking environmental exposure of downhole equipment enables the driller to determine when the operating limits of WOB, RPM, temperature, and dogleg severity (DLS), as well as axial, lateral, and torsional vibration, are being approached or exceeded.

This smart system reduces the reliance on expert analysis to identify the correct actions to mitigate the problem, leading to an increased speed of response. The combined capacities of identifying all vibration mechanisms, tracking the environmental exposure, and representing this information in an easily understood manner provides a powerful tool for the control of drilling operations.
Iron Roughneck Make Up Torque–Its Not What You Think!
Authors: Zenero Nathan , Koneti Srinivasa , Schnieder Warren
Published: January 2016

Declining marginal profits demand that operating companies and drilling contractors review their practices and examine ways to optimize processes and reduce unplanned expenditures. One area that has been largely overlooked is iron roughneck make up torque. Until recently, most iron roughnecks had no manufacturer's recommended method to field-verify their accuracy and no way to digitally record or transmit the torque applied to one or more connections. This has undoubtedly resulted in unnecessary expense from lost and damage drillpipe and other downhole tools. The economic impact of the problem is significant and warrants structured, collaborative approach for a solution.

In mid-2014, a collaborative group, including an operator, a drilling contractor and multiple vendors and original equipment manufacturers (OEMs), began the first parts of a six-sigma DMAIC (Define-Measure-Analyze-Improve-Control) cycle to improve make up torque process capability. The effort involved the manufacture of a fit-for purpose tool to measure applied torque and an exhaustive study of multiple makes, models, contractors, operators and operating conditions. The results of the study demonstrate that the process of making up drillpipe with iron roughnecks is uncontrolled (from a statistical perspective). It is also shown that the tools, as they currently exist, deviate significantly from customer defined process capability.

Further study is required to address all the common and special cause variations in the process. Moreover, OEMs, contractors and vendors must work together to implement process controls.
Solid Expandable Solution to Qualify Existing Non-Sour Service Production Casing
Authors: Contreras Jesus D. , Gamarra Francisco , Becnel Joe L. , Phillips Conoco , Galloway Greg
Published: January 2016

In the early development of the Eagle Ford Field in South Texas, the initial well design equipped wells with non-sour service P-110 production strings. After the early stages of production, some of these early wells were found to produce increasing levels of H2S, which posed the problem of potential sulfide stress cracking at shallow wellbore depths because of relatively high H2S partial pressures and associated low formation temperatures (<145°F). To mitigate this risk, production packers were run to protect the production casing in flowing wells with H2S partial pressures of more than 0.05 psi. As these wells were depleted to lower flowing pressures, production was maintained by intermittently producing. This method was used because of limited or no artificial lift options for wells with non-sour-service production casing. A solution allowing artificial lift was needed to better maintain and sustain production, to extend the utility of these wells, and to allow future recovery of the potential reserves.

Expandable casing technology was ultimately chosen as a solution to maintain well integrity and enable implementation of artificial lift (gas lift). This operation involved the running of an expandable liner to cover and protect the section of the casing susceptible to sulfide stress cracking. A solid expandable tubular designed to support the corrosive environment was successfully tested and qualified for sour service in extreme corrosive conditions by the operator metallurgists, adhering to sour service qualification according to paragraph A.2.1.6 and Annex B of NACE MR0175/ISO 15156 standards.

Additional testing was performed to ensure that the required length of the chosen liner could be run while being held at surface. Normally, these liners are left free at the top which allows slight shrinkage in length to avoid high tensile forces as the liner is expanded outward. The liner system passed all tests performed independently by the service company. The team proceeded to install the solid expandable liner, from 7,047 ft. (where the temperature was above the threshold of H2S embrittlement) to surface to protect the existing 5 1/2-in. 20 ppf P-110 casing. The internal D-diameter (ID) of the completion changed from 4.778 in. (original production casing size) to 4.140 in. (once the pipe was expanded). The well was then completed with 2 3/8-in. tubing, a production packer, and traditional side-pocket-mandrel gas lift. Currently, the well is producing on continuous gas lift with the casing protected by the expandable liner. The expandable liner provided an enabling solution that allowed implementation of the optimal artificial-lift method to recover additional resources within the drainage area.
First Successful Implementation of an Advanced Fibrous Organic Based LCM and Optimized Casing Design in Europe: A Case History From Drilling a 6022 m HPHT Exploration Well in Vienna Basin, Austria
Authors: Abdelaal Khaled , Ovrevik Kjell , Knezevic Rudolf-Nikolaus , Husodo Ryanto
Published: January 2016

The paper presents findings of a case history based on the first application of specialized organic fibre lost circulation materials (LCM) in Europe. It lists technical challenges encountered during the recent drilling of HPHT exploration well Stripfing T1 to 6022 mMD and describes how new fibrous organic LCM have proven their value in a range of lost-circulation applications in the Vienna basin. The paper will also elaborate on the narrow mud window available and the main drivers for well design along with contingency concepts.

The operator identified an innovative LCM which had the characteristics that it is plastic, deformable and can be squeezed into a loss zone resulting in an effective seal being formed across the loss zone with an internal filtercake rather than a high loss filtercake forming on the exterior of the wellbore. Several pills containing this product were used achieving excellent results when applied according to a specific procedure. The paper will look in detail at this procedure and highlight the input from detailed decision-tree charts, and the characteristics and wettability of fibres.

The Vienna Basin has a history of mud losses ranging from continuous seepage to severe losses. The main concerns while planning the Stripfing T1 well were the magnitude of overpressure in combination with the expected losses. The above had been the root cause of previous failures.

Several attempts to cure the losses with standard LCM had proven unsuccessful, as a consequence the operator decided to adopt a new approach using a specialized LCM product in order to avoid running casing earlier. Successful implementation of this advanced technique allowed the operator to drill the well using only 3 casing strings and a final hole size of 8 ½ in. without reducing the mud weight.

The level of success achieved by using these materials suggests it should be considered as the preferred standard practice for curing any type and volume of losses.
Data Ownership for Drilling Automation – Managing the Impact
Authors: Macpherson John , Wardt John de , Laing Moray , Zenero Nathan
Published: January 2016

Drilling systems automation depends on timely flow of accurate and relevant data from multiple sources to control equipment, machines and processes. The fragmented nature of the drilling operations business means that data must usually be shared among companies contracted to perform services, and the operator, and all companies must trust that data. This paper describes the issue of data ownership in terms of the application of drilling systems automation, and proposes solutions.

Various parties in a drilling operation measure, collect, analyze and report data gathered during the drilling operation. They take actions to control the drilling process, avoid problems and improve performance, using information derived from the data. Data is used in pre-job planning, in real-time by those operating the drilling rig and various drilling tools, as well as periodically to advise the onsite drilling team. Data flow ranges from high-frequency, low-latency response loops at the wellsite to low-frequency, high-latency response loops in remote centers.

The SPE Drilling Systems Automation Technical Section (DSATS) has identified OPC UA as the most suited communications protocol for multidirectional fast-loop control systems. In these environments, there is high likelihood that a controller from one supplier will access and use data created by another supplier.

Drilling systems automation requires structured and organized data sharing between parties. This data sharing adds value to the drilling process. A conceptual data model describes at least three classes of data generated while drilling, and all lie within the confidentiality envelope of the operator or government agency. There is data that is the property of the data generator (such as equipment condition monitoring data), data that is restricted (such as formation evaluation data), and data that is shared in an "open data pool" for the purposes of drilling systems automation. Because ownership or control means responsibility for data quality, it is important that each data generator own its contribution to the shared data pool. The data aggregator – the party managing the shared data pool – is therefore not necessarily the owner of all data in the pool, but a caretaker of that data.

This paper describes the history of data measurement, data flow and data ownership in the drilling industry. It will address data ownership issues pertaining to drilling systems automation and drilling performance improvement. A brief review of examples of data from academia and from within our own industry will assist in understanding the relationship between data ownership and intellectual property. The paper presents a data ownership and data sharing solution that provides an environment for drilling systems automation.
Casing Integrity: Modeling Strength Degradation
Authors: Li Changning , Samuel Robello
Published: January 2016

Casing integrity management is crucial, especially in wells experiencing severe casing wall degradation. It is highly desirable to predict the threshold pressure for degraded casing burst and collapse strength and to design the casing strings considering these wear effects. Knowledge of stress distribution in worn casing helps predict where casing failure occurs first. This study focuses on building a model for stress distribution along the casing circumference based on "crescent-shape" casing wear. A common method is to estimate the reduction of the casing burst strength in worn casing using the API burst strength equation with a linear reduction by the remaining wall thickness or wear percentage equivalent to a "uniformly-worn" casing model. This paper presents a rigorous engineering method to calculate the hoop strength directly, including the local bending in the thinner portion of the "crescent-worn" casing.

A model and correlation to calculate varying hoop strength in the crescent-worn shape and non-worn casing have been developed with force and moment balance equations. The stress predicted in this paper is similar to the results obtained from the finite element method (FEM), which validates equations and results obtained from this paper. The developed model is generic and can be used for casings, risers, and tubings.
Lost Circulation Management in Naturally Fractured Formations: Efficient Operational Strategies and Novel Solutions
Authors: Savari Sharath , Whitfill Donald L.
Published: January 2016

Managing severe to total lost circulation can be very challenging in naturally fractured formations. Particulate lost circulation materials (LCMs) have been used to manage lost circulation for many years; however, current LCMs are not efficient in terms of their size and application methods when it comes to curing severe to total losses, such as highly fractured formations.

In the present paper, preventive (proactive) and remedial (reactive) operational strategies will be discussed. In addition to the operational strategy, this paper will also present novel additives in the form of engineered composite LCM solutions (ECS) with multi-modal particle-size distribution (PSD), which were successfully used to manage severe-to-total-loss situations in naturally fractured carbonate formations. The multi-modal PSD will help manage any uncertainties in fracture sizes, and the presence of larger particles will also aid in plugging large fractures. Case studies will be presented for applications in the mid-continental USA, Middle East, and offshore East Africa.

Preventive strategies are recommended to reduce the potential for lost circulation (LC). It is recommended that LC management be considered in the wellbore planning/design phase and that all engineering analyses be performed prior to the start of drilling the well. It is very important to have remedial strategies in place if the preventive plan does not work. This includes putting loss contingency plans in place should unexpected loss events occur. Examples will be discussed as to how previous knowledge and lessons learned can play a critical role in developing contingency engineered solutions to effectively cure losses.

When managing severe-to-total losses in highly fractured formations, particulates alone may not be effective. The combination of a large multi-modal PSD LCM, a swellable component, and chopped synthetic fibers were proposed as a solution for dealing with such extreme losses. While drilling highly fractured formations, this combination was applied after all conventional LCM applications failed. In most cases, the combination was pumped open-ended, and losses were totally cured so that circulation could be re-established. To conserve rig time, the use of a treating sub is recommended as part of the BHA for handling high concentrations of large PSD LCMs for curing severe losses.

The combination of operational strategies (LCM applications) and novel LCM solutions for curing severe-to-total losses in naturally fractured formations are the technology improvements presented in this paper.
Nonaqueous, Salt-Free Drilling Fluid Delivers Excellent Drilling Performance with a Smaller Environmental Footprint
Authors: Walker Jonathan , Miller J. J. , Burrows Kim , Mander Timothy , Hovan Jared
Published: January 2016

Disposal of drill cuttings from nonaqueous drilling fluids (NAF) can be a significant expense and logistical issue for the operator of a drilling rig. NAFs typically contain high levels of salts, commonly calcium chloride or sodium chloride, in the internal phase of the emulsion. These salts are highly beneficial for wellbore stabilization performance but pose issues for disposal of drill cuttings because the salts do not biodegrade and can accumulate in high concentrations in soil.

A salt-free NAF has been developed and field validated in the Western Canadian Sedimentary Basin in Alberta, Canada. The system uses a biodegradable organic to provide an internal phase with equivalent water activity to traditional salt-containing systems. This results in a fluid system with the performance and benefits of a conventional NAF while potentially allowing for greater cuttings disposal options. Depending on local regulations, the system has the potential to reduce environmental and long-term liability concerns by being able to land-farm drilled cuttings without hindering plant growth.

Three wells on a seven-well pad were drilled with the salt-free NAF; the other four with a conventional invert emulsion fluid (IEF). The salt-free fluid performed the same as or better than a conventional fluid while drilling. Observed improvements over conventional NAFs included less required fluid maintenance, greater inhibition of the formation, and less fluid losses in part resulting from reduced oil on cuttings (OOC). A bioremediation study was conducted to analyze the cuttings for electrical conductivity and plant growth. Cuttings were sampled from each type of well and delivered to the lab for testing and analysis. Laboratory testing showed that when mixed with top soil, the salt-free cuttings allowed for viable plant growth. In comparison, the conventional cuttings did not allow plant growth. The paper will discuss in detail the field trial and bioremediation study of the salt-free NAF.

The salt-free system showed equivalent and in some respects better performance to conventional NAFs used on other wells on the same pad. Additionally, cuttings from the salt-free system showed superior plant growth when compared to conventional, salt-containing systems. This system is expected to offer expanded options for cuttings disposal and ultimately reduce the cost and liability associated with using NAFs in many areas.
PMCD Technique Enables Coring & Wireline Logging Operations in Total Lost Circulation
Authors: Houng N. H. , Gallo Zapata J. F. , Ahmad Fauzi M. A.
Published: January 2016

After reaching target depth (TD) with Pressurized Mud Cap Drilling (PMCD) technique, risks associated with total lost circulation (including potential gas migration and unsustainable fluid logistics) have led to the perception that wireline logging and coring operations in PMCD are not feasible. However, with proper planning and procedures in place these operations are possible. Recent carbonate drilling operations in offshore Sarawak, Malaysia, have proven coring and wireline logging operations can be completed in PMCD conditions.

In the first well, Well S, the operator retrieved core samples from three different zones in a gas bearing carbonate reservoir. The coring operation with PMCD, which was the first of its kind in the Asia Pacific Region, created new frontier for carbonate formation evaluation by allowing the acquisition of rock property data from wells once considered to be impossible to drill to TD.

In another well, Well X, PMCD wireline logging operations were conducted safely and successfully. Open hole of 509 m was drilled with PMCD, and upon reaching TD the wireline logging pressure control equipment was rigged up to commence the PMCD wireline logging operation. In addition to the comprehensive planning and execution procedures, the increased riser pressure limitation was a main enabler for the PMCD wireline logging operations. Eight wireline runs were performed, collecting critical data for the field development plan (FDP). The gas water contact for the field was determined accurately despite the total lost circulation.

Running wireline logging and coring operations with PMCD allowed the operator to not only drill once perceived impossible-to-drill wells, but also to retrieve crucial and valuable data from the well at TD. These operations reduce field volumetric uncertainty.

This paper records the planning, execution, and post well analysis of carbonate sections, including the general methodology for the logging and coring operations in PMCD mode, risk and hazard assessment of the operations, results and observations of successful operations in Malaysia with elaboration of issues encountered, and recommended solutions.
Drilling From Onshore to Offshore Targets: Planning and Systematic Execution On An Extended-Reach Drilling Campaign
Authors: Tikkoo Rajiv , Nasarczyk Mark , Akinniranye Goke , Goura Nicholas , Amin Sajid
Published: January 2016

Origin Energy Pty Ltd ("Origin") completed its first extended reach drilling (ERD) project in southeast Australia to access offshore targets from an onshore location. The project targeted the Halladale gas field which is located 5.5 km offshore and 1.8 km below the seabed. For this operator, the challenge was to access offshore reserves using onshore drilling and production infrastructure to minimize project development costs and avoid working in sensitive marine environments.

To mitigate depth uncertainty at the target location, an S-shaped trajectory was selected for the Halladale-2 production well. This started with a shallow kick-off followed by a sub-horizontal section that travelled laterally offshore and ended with a drop-off section to intersect the reservoir target. Advanced drag management techniques were required to drill the 12 ¼-in. and 8 ½-in. hole intervals, install the 9 ⅝-in. production casing, 7-in. production liner, and 5 ½-in. intelligent upper completion. The 9 ⅝-in. casing was installed using the buoyancy-assisted method (floatation), such that it could be "pushed" and "reamed" in the hole beyond the point of negative weight. Due to the geological environment and potential for mud losses, special attention was required in order to have the system designed for reduced hydrodynamic loads and still maintain appropriate mud weight for wellbore stability.

The 9 ⅝-in. casing was run completely empty and required rotation in order to reach total depth. During the operation of landing-out the casing on the well head, the use of rotation to overcome axial drag was not an option; therefore, adequate contingency planning was required. A casing selective floatation collar was installed to provide additional weight should it be required by filling the top portion of the string with drilling fluid as total depth was approached. This allowed the lower portion of the casing in the high angle interval of the wellbore to remain empty, and thus neutrally buoyant. This contingency was in addition to the risk assessed push-down weight that the top drive could provide. A process was adopted to ensure that every member of the team understood the program and was committed to the successful delivery of the wells. These measures resulted in significant cost savings for the project.

Technical challenges were overcome with design solutions and operational practices developed with the aid of modeling and simulations performed during the planning phase. The preparation of comprehensive multi-well program, the use of real-time data to validate the engineering models and a systematic approach to well planning contributed to the success of the project. When the rig limitation is accounted for, the Halladale-2 ERD well was a world-class challenge that was successfully overcome.
A New Damping Model for Nonlinear Drillstring Dynamics: Understanding the Effects of Rotation, Eccentricity, and Confined Fluid Flow and Their Impact on Unconventional Drillstring Design
Authors: Wilson J. K. , Noynaert S. F.
Published: January 2016

Since the pioneering work of Bailey and Finnie in 1960, drillstring dynamics continues to be an active area of research within the industry. While much effort is put into developing accurate descriptions of the complexities associated with the downhole environment, proper modeling of the various damping mechanisms acting on the drillstring remains underdeveloped. A typical approach to modeling the damping downhole consists of utilizing a generalized, or proportional, damping model based on measurements of the actual system response. This technique can be fairly useful when done properly but does not actually quantify the effects of various environmental or operational parameters, such as fluid characteristics or string rotation, on the overall behavior of the drilling assembly.

This study presents a nonlinear, semi-analytical, fluid-force model specifically developed to account for the various downhole characteristics that contribute to energy dissipation such as pipe eccentricity, lateral velocity, rotation speed, fluid rheology, and flow rate. This new fluid-force model is combined into an already proven drillstring model which was developed to embody the fully coupled flexibility of the drillstring, arbitrary wellbore curvature, frictional contact, and complex tool geometry. Using the improved model, the paper analyzes the nonlinear behavior of drillstrings with a focus on lateral vibrations in modern unconventional wellbores. Specific attention is given to studying the damping effects on the dynamic response of the drillstring and BHA during rotation with a Rotary Steerable System (RSS).

The results shown through this investigation help to quantify the dynamics associated with modern drilling operations. Effects of fluid properties, flow rate, and rotation speed on the nonlinear behavior of the drillstring are examined through numerical studies of rotating an RSS assembly in an unconventional horizontal wellbore. Through the results, it is shown that proper modeling of the fluid forces acting on the drillstring helps to explain how BHAs, under certain conditions, can be safely operated within a range of resonant frequencies. Advanced visualizations of these time-domain simulations also reveal a unique observation that could have a significant influence on expanding the drilling envelope in automated operations.
Innovative Conical Diamond Element Bit Significantly Reduces Drilling Cost of Williston Basin Three Forks First Bench Laterals
Authors: Schilling John , Cooley Emy , Azar Mike , White Allen , Koffler Kerry , McDonough Scott , Self Jordan , Krough Brad , Bits Smith
Published: January 2016

The Three Forks First Bench (TF1) in the Williston Basin is attractive to operators for its production qualities; however, the formation is problematic for drilling with polycrystalline diamond compact (PDC) bits. TF1 is an interbedded dolostone, 30 to 40 ft thick, capped by the abrasive Pronghorn/Sanish formation with high stress variations/spikes and laminations. These formation characteristics lead to cutter damage and vibration, which cause slow rates of penetration (ROP) and additional trips due to bit/bottomhole assembly (BHA) failure.

In response to these challenges, a revolutionary rock-removal system has been designed. The system implements conical diamond elements (CDE) to work in unison with the PDC cutters. Conventional PDC bits complete a typical 10,000-ft TF1 lateral in a one-bit/BHA in only one out of five wells. The most common reason for tripping is bit/BHA failure due to the harsh characteristics of the TF1. The CDE's unique geometry applies a concentrated point load to fracture formation more efficiently, and its ultra-thick diamond layer provides superior impact strength and wear resistance. Bits utilizing CDEs in conjunction with PDC cutters are known as CDE bits. They are able to withstand the demands of the application where conventional PDC bits cannot.

CDE bits average 5,447 ft at 83 ft per IADC hour when placed as the first bit in a lateral. That performance is 10% farther and 15% faster than conventional PDC bit offsets. Analyzing measurement while drilling (MWD) tool vibration data, CDE bits have proven to mitigate BHA vibrations compared to conventional PDC bits. These performance step changes have helped operators improve their one-bit/BHA TF1 lateral success rate from one out of five wells with conventional PDC bits to an astounding one out of three with CDE bits.

One operator in particular has utilized CDE bits to their full potential. From September 2014 to September 2015, the operator's one-bit/BHA total depth (TD) rate using conventional PDC bits was only 13%. However, the 1-bit/BHA rate when CDE bits were used was 83%, which provided a considerable savings in eliminating the nonproductive time (NPT) in tripping. Depending on the depth, a trip could cost the operator USD 80,000 and 16 hours in NPT. The average performance of CDE bit drillouts has been 9,538 ft at 137 ft per on-bottom hour, providing a 74% improvement in footage and a 2% improvement in ROP over conventional PDC bits for the operator. The reduction in NPT in tripping and improvement in drilling performance has led the operator to prefer drilling with CDE bits.
Changing Drillstring Design to Allow Accurate Calculation of BHA SAG Corrections
Authors: Hinke Sean , Kanji Karim , Mracek Brian , Slight Chris , Happy Robin , Zabcic Lidia , Relph Diver
Published: January 2016

Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) drilling environments in Northern Alberta have some of the tightest geological control in the world. In many cases, there are multiple stratigraphic wells along the length of the vertical section of the horizontal legs. This geological control allows wells to be more accurately positioned with formation evaluation sensors than in most areas, which often means that the resulting wellbore position from directional surveys, containing compounding survey uncertainty, places the wells differently than expected from the geological wellbore positioning. Through empirical testing in controlled environments and field validation trials, it was determined that small changes in the bottomhole assembly (BHA) design can greatly reduce the deflection of BHA components and the impact it has on the misalignment of the directional sensor, otherwise known as BHA SAG. These small changes to the BHA allow the current industry modeling software to more accurately predict the BHA deflection, providing the most accurate survey inclination corrections possible.

Testing was performed comparing different combinations of hole size and tool size on assemblies that contained external upsets to better determine the effects of SAG when using flex collars and stiffer slick collars with a constant diameter. Through empirical testing, it was determined that flex collars deflect in a manner which BHA modeling is unable to predict when external upsets are present. External upsets can include stabilizers, wear bands, worn BHA components, crossover subs, and reducing OD on BHA components. When modeling the flexure across the length of a flex collar or other complex BHA components, it results in a reduction in accuracy when predicting deflection of the BHA in the vicinity of survey instruments. Using collars with a constant diameter circumvents this issue; eliminating variations in diameter across the length of a component allows modeling software to predict the deflection, providing the most accurate results. The results of this study can provide the industry with a best practice to manage and reduce this effect until the modelling has advanced sufficiently to account for the SAG inaccuracy.
Reduce P&A Cost with Section Milling Technology
Authors: Ghegadmal Tejas , Ponder Andrew
Published: January 2016

A firm commitment to environmental safety calls for abandoning wells with depleting production by setting a competent cement plug in the wellbore per government regulations. To prepare the wellbore for the cement plug, concentric casing strings must be removed. When cutting and pulling the casing is not possible, it must be milled away. Milling the casing requires numerous trips into the hole, substantially raising the cost to plug and abandon (P&A) a subsea well.

A conventional section mill, used to accomplish milling, has stabilization features sized close to the inside diameter of the milled casing. Multiple knives expand outward, radially far enough to mill a single casing string. Stabilization features reduce milling vibration, but their gauge-diameter prevents them from passing through some restricted-diameter tubulars that can exist above the wellbore. Reducing the gauge diameter of the mill to pass through restrictions compromises its performance and reliability. Because of the subtle nature of its stabilization features, conventional section mills are referred to as "passively stabilized". A new undersized section mill with "active stabilization" can be deployed through a restricted-diameter tubular to mill a section of casing string below it with similar performance and reliability of the conventional mill.

This new actively stabilized section mill was used to mill a 70-ft. section in 11-3/4 in. casing below a restricted-diameter production riser. The mill passed through the restricted inside diameter of the riser and blowout preventer (BOP). It then expanded its stabilizer arms to centralize itself inside the casing before cutting knives expanded to begin the cut. Cutting knives slowly expanded as they cut through the casing wall, and then milled down the unwanted casing section. The stabilizer arms kept the undersized mill firmly centralized inside the milled casing, limiting lateral vibration of the mill. Leaving the riser, BOP and surface equipment in place saved the operator 3 days and USD 1 million.

Active stabilization reduced vibration, improved milling performance and knife longevity, thus reducing the number of trips to mill a section of casing, substantially reducing costs and HSE risks of P&A.