bluuebunny/crossref_metadata_2025_split huggingface dataset:
Previous Announcement Method Using 3D CG Face Interface for Mobile Robot
Authors: Mikawa Masahiko , Lyu Jiayi , Fujisawa Makoto , Hiiragi Wasuke , Ishibashi Toyoyuki ,   University of Tsukuba 1-2 Kasuga, Tsukuba, Ibaraki 305-8550, Japan,   Chubu University 1200 Matsumoto-cho, Kasugai, Aichi 487-8501, Japan,   Gifu Women’s University 80 Taromaru, Gifu, Gifu 501-2592, Japan
Published: February 2020

When a robot works among people in a public space,	its behavior can make	some people feel uncomfortable.	One of the reasons for this	is that it is difficult for people to understand	the robot’s intended behavior based on its appearance.	This paper presents	a	new intention expression method	using a three dimensional computer graphics (3D CG) face model.	The 3D CG face model is displayed on a flat panel screen	and has two eyes and a head that can be rotated freely.	When the mobile robot is about to change its traveling direction,	the robot rotates its head and eyes in the direction	it intends to go,	so that	an oncoming person	can know the robot’s intention	from this previous announcement.	Three main types of experiment were conducted, to confirm	the validity and effectiveness of	our proposed previous announcement method	using the face interface.	First, an appropriate timing for the previous announcement	was determined from impression evaluations	as a preliminary experiment.	Secondly,	differences between two experiments,	in which a pedestrian and the robot	passed each other in a corridor	both with and without the previous announcement,	were evaluated	as main experiments of this study.	Finally,	differences between our proposed face interface	and the conventional robot head were analyzed	as a reference experiments.	The experimental results confirmed the validity and effectiveness of	the proposed method.
Aalenian–Lower Bajocian Foraminiferal Fauna from the Ammonitico Rosso Series of Bakonycsernye (Hungary). Part 2: Palaeoecological and Palaeobiogeographical Aspects
Authors: Zsiborás Gábor , Görög Ágnes 
Published: February 2020

AbstractThis paper provides the first assessment of the paleoecology and biogeography of foraminiferal assemblages from the continuous Aalenian–lower Bajocian succession from the pelagic region of the Neotethys. Foraminiferal assemblages were extracted by glacial acetic acid from the Tűzkövesárok section B of Bakonycsernye (Hungary), which is well dated by ammonites and consists of Ammonitico Rosso type limestones. Palaeoenvironmental changes were evaluated based on microfacies studies, taxonomic and palaeoecological analyses (abundance, diversity, morphogroups, and ecozones) of the 49 benthic and one planktic taxa. The grazer-dominated foraminiferal assemblages indicated normal marine salinity and well-oxygenated conditions in a pelagic swell-graben environment below the photic zone. The majority of the foraminifera likely grazed on a biofilm or mat produced by microbes and/or fungi and also may have fed on marine snow. At the Aalenian–Bajocian transition, the decrease in abundance and diversity was linked with a sea-level fall event (JBj1). In the upper Bajocian, dissolution due to deepening resulted in the gradual and selective impoverishment of the fauna. In addition, two biomes, Boreal-Atlantic and Mediterranean, were distinguished within the area of the Boreal-Atlantic-Caucasian Province, based on the review of the coeval faunas.
A Study of the Reeving Efficiency and Inertia of Drawworks
Authors: Kyllingstad Åge 
Published: February 2020

Abstract
The reeving efficiency is a measure of how effectively the drill line and sheaves transfer the drawworks power to the moving external load. The drill line is a steel wire rope having an inherent bending resistance. The internal bending friction is the dominating component of the single sheave efficiency, which is a function of line to sheave diameter ratio, the line tension force, the rope construction type, and the lubricator. The model used here is an empirical two parameter model validated by measurements. Experimental evidence found in the literature strongly suggests that the single sheave efficiency for typical sheaves and loads is around 99.8%. This is much higher than the 96% efficiency suggested by the American Petroleum Institute (2015) in their Recommended Practice 9B.
The paper also discusses the inertia of the drill line and sheaves and presents general models for reeving efficiency and reeving inertia valid for both single and dual drawworks. It also discusses some of the implications of both the friction losses and the inertia effects. One is that systematic errors in the deadline-based hookload can be minimized by applying simple speed and acceleration dependent corrections. Another implication is that the downwards acceleration (or upwards retardation) of the external load must be limited to avoid hazardous situations with fast-line slack.
Intelligent Pipe-Handling: A Case Study for Automation
Authors: Moralez Nathan , Ronquillo Nahum , Lisi Dario , Lynch Michael , Parker Christopher , Sutler John , Machum Matias 
Published: February 2020

Abstract
This paper provides a case study on the successes and challenges with retrofitting tripping automation on two deepwater rigs operating in the Gulf of Mexico. The paper details the approach taken to overcome challenges associated with implementing and adopting automation technology and presents an analysis of key performance indicators that illustrate the success of the project. The paper also presents learnings and recommendations for deploying process automation while discussing some of the remaining challenges to overcome acceptance of automation in the upstream oil and gas drilling industry including implications to human performance.
Automated BOP Testing Technologies Provide Economic Benefits Along with Personal and Process Safety Improvements
Authors: Anderson Mark W. , Hilpert Jeff , Graziano Matthew , Zimpfer Douglas , Boegershausen Sebastian , Kirker Christian 
Published: February 2020

Abstract
In 2013, a technology development project was started that digitized, automated and applied analytics to the blowout preventer (BOP) pressure testing process. At the time it was viewed that BOP testing was a neglected process and could benefit from a technology development project.
As a result of the deployment of automated BOP testing technologies, significant improvements have been achieved in process safety, personal safety and rig time savings. Rig time savings of up to 50% of the BOP testing time have been achieved.
Analog circular pressure chart recorders were replaced with a personal computer (PC) based digital pressure recording software. An automated valve actuation device was developed that can retrofit any API 6A style gate valve. An acoustic detection system for leaking valve identification was developed. A novel method of directly measuring a leak using a linear press pump was trialed that, after additional development work, may supersede the indirect leak measurement of the pressure decay leak testing method.
Future enhancements and development are underway to go beyond BOP testing. These are being developed to cover casing pressure tests, casing inflow tests and completions pressure tests. Also, field trials will commence shortly to apply this technology suite to completion and hydraulic fracturing domains.
Gyro Wellbore Placement Using Advanced Solid-State Sensor Technology
Authors: Ledroz Adrián , Weston John , Moisan James 
Published: February 2020

Abstract
This paper describes the construction of a wellbore that has been drilled using gyroscopic measurements alone to control the path of the well. Wellbores have not been drilled solely using gyroscopes since the early days of oil and gas extraction in the last century, and it is many years since a wellbore has been constructed without the use of magnetic MWD measurements. The exercise described here therefore marks a milestone in the application of downhole gyroscopic technology.
The wellbore development described has been implemented using advanced solid-state gyroscopic sensors based on a new Coriolis vibratory gyroscope (CVG). Recent studies have demonstrated how this new sensor technology has become both a viable and practical option for high accuracy wellbore placement, largely achievable since CVGs are not affected significantly by the high levels of shock and vibration that can be experienced under extreme drilling conditions. The new technology provides an attractive option for while-drilling application, not only as an alternative to conventional gyro while drilling technology but also as a potential replacement for magnetic MWD.
The results presented here illustrate the ability to use the gyroscopic measurements alone to achieve a planned wellbore trajectory. For the purpose of this case study, a post-drilling gyroscopic survey was conducted using a high accuracy gyro tool to verify the accuracy of the while drilling measurements.
The paper sets out the numerous benefits that accrue from the application of CVG technology for the drilling of all types of well. First of all, it allows close proximity well placement in top-hole sections since the gyros are immune to magnetic interference from nearby wells. It also eliminates the need to add a nudge to the wellbore trajectory, a process that normally increases the tortuosity. The need to incorporate non-magnetic drill collars in the tool string is now removed, as well as the need for magnetic models and corrections, both with consequent cost savings. The new survey tool allows measurements to be taken near the bit facilitating more precise well path control. Multiple gyro sensor packages may be run simultaneously, thus providing independent surveys for quality control purposes and greater confidence in the detection of gross error.
Step Changing Safety and Efficiency Gains by Fast Rig Moves, Automated Sequences and Data Processing
Authors: De Mul Arthur , Hooft Daniel , Ziatdinov Sergey 
Published: February 2020

Abstract
In the last years drilling industry is rapidly, changing from mechanized/manual rig solutions to fully automated hands-free remotely controlled drilling operations. This is mainly driven by the strive to achieve consistent high operational speeds.
The automated rig minimizes man's factor on the performance equation. However, new types of operations require new equipment with new requirements. The other main driver is to decrease total well delivery time and costs by reducing or eliminating flat time and improving drilling performance. To meet these significant industry challenges a contractor, together with a rig manufacturer set an ambitious target by introducing automation into the whole drilling process to cut total well cost on 30% for a project where the contractor intends to drill wells with total depth up to 1400 meter.
To reach the target the new rig needs to be extremely mobile, have less personnel, automated pipe and casing handling, smart mud system, automated drilling capabilities, directional drilling through remote operating centers, have next generation digital interface etc. Another great aspect of such automated rig is improved safety by removing people from dangerous areas.
Full automation depends on knowing exactly where the tubular is at each moment of the process. This required a new design for the steelwork to provide sufficient stiffness as well as the right sensor packag
The above resulted in the first onshore system in the industry that provides fully automated tripping (RIH and POOH) and automated casing running, included automated casing connections. The connection time during drilling operations has been reduced by 20-30% in comparison to manual handling.
To reduce the time between rig release and spud on the next well to hours instead days, a trailer-mounted solution is introduced with advanced BOP handling and offline testing.
Further incremental improvements will be made possible by collecting all rig and downhole data on the server and share this via the open source server (OPC-UA). The same server is controlling mud system, downhole data, cementing unit and other important systems. From here the processed data is sent to the cloud based digital eco system, and shared with the back office. Real time setpoints can be submitted back to the rig to adjust the auto driller, enabling maximum drilling speeds. The rif control system will interface with the remote data system from the contractor that enables an interconnected rig fleet that connects all the activity on a rig, end-to-end process automation and advanced QA/QC on all aspects of drilling.
The intention with the new technology is to offer a full section automated well construction service.
Such an integrated design approach, rather than adding sensors to existing steel, enables the biggest time and cost savings and is a game changer for the complete well delivery process
BHA Lateral Vibration Chatter Impedes Application of Weight to Bit
Authors: Bailey Jeffrey R , Lathi Harshit , Tenny Matthew J. , Payette Gregory S. , Wang Lei 
Published: February 2020

Abstract
Lateral vibration modeling of certain BHA (bottomhole assembly) designs has shown great sensitivity to the proximity of stabilizer blades. In a previous paper, the BHA chatter vibration mode was presented, including the basic theory and three field examples. In each case, lower drilling rates were associated with higher levels of BHA dynamic dysfunction as determined using a lateral vibration model. One case clearly illustrated a reduction in effective weight applied to the bit, determined using bit dull grade results. This paper will further explore the mechanisms in which BHA dynamic contact forces can act to reduce the effective weight on bit.
The contact forces that push a stabilizer blade to be constrained within a borehole include both static and dynamic components. The dynamic forces are difficult to visualize as they are generated by the BHA in motion, and a well-formulated dynamic model is required to evaluate these forces. In drilling, we simply see the effects as worn and damaged drillstring components.
A frequency-domain BHA lateral vibration model represents lateral vibration flexural waves propagating in the BHA. This model can be used to calculate dynamic side forces acting at stabilizer and LWD tool blade contacts with the borehole for reference excitation forces. These contact forces may be strong functions of rotary speed and BHA contact spacing, and they typically create a non-trivial level of residual drag that impedes getting weight to bit.
The physics of dynamic contact forces are similar in some respects to static contact forces. Superposition of the dynamic modes illustrate that, although an individual component may vanish momentarily, additional modes and phases can constructively combine such that the total force summation does not vanish. The net result is that dynamic forces can generate significant lateral forces that are similar to static contact forces.
Static effects are known to impede application of weight to bit in deviated and horizontal wells, and small ledges can prevent a stabilizer blade from moving forward. Dynamic effects from improper stabilizer placement are potent sources of lateral dysfunction that can have a similar effect. BHA dynamics have the potential to both create borehole irregularities and resist forward motion resulting from contact forces between drilling tools and the borehole.
Plume Analysis Establishes Safe Work Zone and Confirms Well-Access for Subsea Capping Equipment Installation
Authors: Godse Uday , Gill Alistair 
Published: February 2020

Abstract
The scope of this paper is to present the benefits of incorporating plume analysis studies into source control emergency response planning (SCERP) and preparations, prior to a blowout event. By using modeling and engineering analysis as part of the SCERP, plume studies can improve the likelihood of successful capping stack installation efforts during a blowout.
A blowout is a low probability but potentially high impact event that could occur during any well's life. Immediate action is required to bring the well back under control and minimize the consequences. Protocols for dealing with a blowout are usually outlined in an emergency response plan (ERP) developed ahead of time. In the case of subsea wells, a subset of an ERP is a source control emergency response plan (SCERP) focused on how to halt the flow of hydrocarbons from the well. As described by the International Association of Oil and Gas Producers (IOGP) planning guide published in January 2019, multiple engineering assessments are recommended in support of the SCERP, including plume studies. Generally, Computational Fluid Dynamics (CFD) or similar tools are used to carry out the plume studies. Plume studies model the subsea release, comprised of hydrocarbons (oil and/or gas) and water, and track the dispersion of the hydrocarbons from the seabed through the water column to the sea surface. The surface concentrations of hydrocarbons pose a flammable threat above the water surface and hence, are a threat to the response teams. The plume modelling also identifies whether vertical well access is compromised; an important consideration for capping stack installation. Further, interaction between the blowout flow and the capping stack during its installation can complicate and threaten a successful intervention. The subsea plume studies can also examine such interaction.
Multiple case studies from wells throughout the world, along with the plume studies performed to support the SCERP, will be presented. The state-of-the-art techniques including models to cater for turbulence effects, gas bubble and liquid droplet break-up and coalescence, gas dissolution, hydrate formation and dynamic fluid-body interactions used within the CFD analyses will be outlined.
Current CFD techniques to model plume studies demonstrating the adequacies as well as challenges will be presented. Wherever possible, how the numerical predictions compare to measured data will be highlighted.
Capturing Stick-Slip in the Lab Using Hardware-in-the-Loop
Authors: Panayirci H. Murat , Robinson Andrew , Scott David , Skoff Greg 
Published: February 2020

Abstract
Stick-slip is a torsional vibration mode observed in drilling systems, which are used in creating boreholes for the exploration and production of oil and natural gas. This paper presents a method to create and assess stick-slip in the laboratory environment. This is achieved by using the hardware-in-the-loop method, where a numerical drillstring model is combined with an experimental drilling machine. In this setup, the numerical model captures the axial and torsional oscillations between the surface and the drill bit, while the drilling machine acts as the hardware in the loop, capturing the actual bit-rock interaction. The proposed framework allows creating self-excited stick-slip oscillations in a controlled, repeatable and measurable manner. This enables reducing the risk, cost, and time for activities related to testing, developing, debugging or optimizing any stick-slip related tool or mitigation concept.
Identification and Mitigation of Friction- and Cutting Action-Induced Stick-Slip Vibrations with PDC Bits
Authors: Chen Shilin , Wisinger John , Dunbar Brad , Propes Chris 
Published: February 2020

Abstract
This paper provides some new insights into stick-slip vibration in drilling with polycrystalline diamond compact (PDC) bits. Fifty-six field runs under various drilling conditions were collected with the help of on-bit vibration sensors. Stick-slip vibration occurrence during drilling was analyzed. Two types of stick-slip vibrations were identified: cutting action-induced stick-slip and friction-induced stick-slip. Methods were developed to determine whether a stick-slip occurrence is induced by cutting action or by friction. Statistical analysis found that bit drilling efficiency is well correlated with the occurrence of cutting action-induced bit stick-slip vibration. If a PDC bit is designed so that its drilling efficiency is greater than a critical value, then the cutting action-induced bit stick-slip vibration is not expected in drilling. Increasing the aggressiveness of the cutting structure of a PDC bit within a limited critical depth of cut is found to be helpful to mitigate bit stick-slip vibration.
Automating Tubular-Running Operations to Increase Rig Efficiency
Authors: Amezaga Federico , Cummins Tracy , Hooker John 
Published: February 2020

Abstract
Rig efficiency is essential to success in oil and gas operations. Innovative solutions such as automation help to reduce operating costs and minimize safety hazards, which improve efficiency. Traditional tubular-running operations require extensive manual intervention with increased red-zone exposure, especially during equipment rig up and rig down. Equipment interfaces between different manufacturers are often not existing or poorly designed, which can reduce productivity. Automated processes with open interfaces in tubular-running operations would significantly improve rig efficiencies and safety.
Drilling and casing plans include multiple strings, various connection types with different torque requirements, and a variety of hydraulic power tongs. Newly developed, intelligent positioning devices with hands-free, automatic multi-couplers for power and data transfer enable fast, simple, and safe rig up and rig down of tong modules with the push of a button. With a state-of-the-art control system, equipped with an open interface to connect tong modules, it is now possible to eliminate manual intervention. Automatic module identification eliminates manual data entry, removes the human factor, and saves set-up time and therefore valuable rig time.
Automated tubular-running processes provide a wide range of benefits from an operational, safety, and financial standpoint for both drilling contractors and operators. Full rig-control-system integration, along with intelligent positioning devices, maximize advantages by reducing the personnel required to operate equipment during the construction of the well. Automation eliminates time-consuming and dangerous equipment handling on the rig floor and helps to implement a new set of operational and safety standards. Rig up and rig down time is significantly reduced by up to 90%-time compared to conventional tool-handling operations. Fully automated sequences using new generation positioning devices considerably improve well construction running times and minimize potential safety incidents.
Implementing cutting-edge technology with improved rig-control systems integration to automate tubular-running processes increases the potential to bring rig efficiencies to a higher operational level.