bluuebunny/crossref_metadata_2025_split huggingface dataset:
Large Scale Experiments on Slug Length Evolution in Long Pipes
Authors: Kjølaas Jørn , Unander Tor Erling , Wolden Marita , Schümann Heiner , Leinan Paul Roger , Smith Ivar Eskerud , Shmueli Andrea 
Published: April 2020

Abstract
Long slugs arriving in separators/slug catchers is a major flow assurance concern in the offshore oil production industry, potentially causing flooding and/or severe separation problems. The sizing of the receiving facilities is determined by the longest slugs, so the economic implications of slug length predictions can be substantial. Slugs may also over time cause serious fatigue issues in free-span pipe sections, as large load variations can drastically reduce the lifetime of the flange connections. In most laboratory experiments reported in the literature, slugs rarely become longer than around 30-40 pipe diameters, while in many oil production fields, slugs can be considerably longer. Consequently, there is a clear need to better understand how and why such long slugs appear in production systems, and in this paper we present results that shed some light on this matter.
We present a unique set of two- and three-phase slug flow experiments conducted in a 766 meter long 8" pipe at 45 bara pressure. The first half of the pipe was horizontal, while the second half was inclined by 0.5 degrees. A total of ten narrow-beam gamma densitometers were mounted on the pipe to study flow evolution, and in particular slug length development. In addition, the average phase fractions were measured using two traversing gamma densitometers, and one 160 meter long section with shut-in valves. The pressure drop was also measured along the loop using a total of twelve pressure transmitters.
The results show that the mean slug length initially increases with the distance from the inlet, but this increase slows down and the mean slug length typically reaches a value between 20 and 50 diameters at the outlet. At low flow rates, the slug length distributions tend to be extremely wide, sometimes with standard deviations approaching 100%. The longest slugs that we observed were over 250 pipe diameters (50 meters). At higher flow rates, the slug length distributions are generally narrower. The effect of the water cut on the slug length distribution is significant, but complex, and it is difficult to establish any general trends regarding this relationship. Finally, it was observed that slug flow often requires a very long distance to develop. Specifically, in most of the slug flow experiments, the flow regime 50 meters downstream of the inlet was not slug flow.
The reported experiments are the first three-phase slug flow experiments ever conducted in a large-scale setup. By using a long, heavily instrumented pipe, we were able to study the evolution of slug length distributions over a long distance. We believe that these experiments can be of considerable value for developing tools for predicting slug lengths in multiphase transport systems, which is a critical matter for oil field operators.
First Deployment of Subsea Rotating Buoyancy to Mitigate Lateral Buckling of High Temperature Pipelines
Authors: Critsinelis Antonio , Mebarkia Sid , Huang Meirong 
Published: April 2020

Abstract
The paper seeks to address the challenges faced by High Pressure High Temperature (HPHT) subsea pipelines buckling mitigations and presents a new innovative solution that was evaluated from 2012 to 2016 and first deployed in 2017 then surveyed in 2018 after almost 6 months of operation. Laboratory tests, field tests, small scale tests, full scale tests, analytical derivations and finite element analyses were developed and used to mature the rotating buoyancy technology configuration as a new innovative solution.
High pressure and/or high temperature subsea pipelines may experience lateral buckling which require special considerations to mitigate excessive plastic deformation and fatigue during start up and shut down cycle events. One of the widely used mitigation consists of attaching fixed buoyancy modules on engineered sections of the pipeline system. However, postproduction subsea surveys and engineering evaluations showed the currently used buoyancy mitigation methods create large soil berms that may significantly reduce pipeline fatigue life and the opportunity of life extension of the pipeline system.
The rotating buoyancy system was developed to help solve this problem and increase the solution robustness to enable potential life extension and possibly reduce the stringent welding requirements at the buckled sections. It represents a step change in the way risks associated with buckling of high temperature and/or high pressure pipelines are managed and effectively mitigated. Between year 2015 and 2016, small scale and large-scale tests were performed using prototype fixed and rotating buoyancy modules to compare the current and new mitigation methods. This paper outlines the methods by which pipe-soil interaction can be simulated. It describes the validation and verification conducted, through experimental testing on both newly developed small-scale and large-scale testing rigs, coupled with computational modelling and analytical predictive calculations. The paper highlights the challenges faced when replicating seabed conditions and pipeline movements. It also highlights novel design aspects which offer improved traction in soft clay environment. The paper also presents the lessons learned during the 2017 offshore installation campaign and the 2018 results of the in-situ survey of the rotating buoyancy modules after the first 6 month of operations and future plans for next generation rotating buoyancy systems including digitalization.
The subsea rotating buoyancy is a novel simple system deployed to provide a robust mitigation of subsea pipelines lateral buckling. It provides opportunity for potential increase of subsea pipeline life extension and potentially helps decrease the stringent welding requirement of the pipeline at the buckled sections.
Use of Fiber Optic Acoustics to Improve Drilling Efficiency and Well Placement
Authors: Martinez Alejandro , Useche Manuel , Guerra Rafael 
Published: April 2020

Innovations in the field of fiber optics have resulted in the application of distributed acoustic sensing (DAS) for borehole seismic applications.
A hybrid optical-electrical cable has been developed to enable conveying all logging suites required during the entire well construction. From intermediate drilling section evaluations through well integrity and production, the optical fiber enables seismic acquisition during any wireline intervention.
Because the optical fiber inside the logging cable is the seismic sensing element, velocity information can be measured along the entire wellbore very efficiently. The acquisition of a borehole seismic program, such as a zero-offset vertical seismic profile (VSP) is reduced to minutes, instead of hours or days. Also, no additional rig time is needed if the seismic information is acquired during logging runs that involve remaining stationary in the borehole, such as fluid sampling and calibration of nuclear magnetic tools.
Improvements in drilling efficiency from using this technology are achieved in several ways: 1) elimination of a dedicated seismic run, which renders substantial rig time savings; 2) lowering risk of operations (i.e., avoiding fishing); 3) virtual elimination of nonproductive time due to downhole tool failure and the provision of many opportunities to gather data (logging runs in open or cased hole); 4) obtaining seismic information, however basic, in every well in a cost-effective manner, which is important for future well placement and derisking drilling operations; 5) optimization of seismic acquisition programs in combination with conventional downhole three-component (3C) seismic tools; and 6) seismic data quality assurance resulting from measurement during the drilling process with minimum disruption (intermediate sections and TD), avoiding sections with multiple casing strings or noncemented tubulars.
An example of a zero-offset VSP acquired on hybrid optical heptacable is discussed in the context of increasing drilling efficiency. The checkshot and VSP survey required only minimum rig time to acquire the data, with the hybrid fiber optic-conventional seismic program acquired at intermediate and final
sections that obtained VSP information for the entire well with significant rig-time savings and improved data quality.
Geological Modeling of Semideep Reservoir Based on Seismic Frequency Division Processing and Sedimentary Numerical Simulation
Authors: Lv Zuobin , Song Hongliang , Wang Pengfei , Fang Na , Zheng Bin 
Published: April 2020

Abstract
The resolution of seismic data in the semideep reservoirs ranging from 1500m to 3000m is low, and reservoir prediction is difficult when well data are scarce (Xu et al. 2005; Liu et al. 2018; Pang et al. 2012; Wang et al. 2017). The sedimentary facies of the semideep reservoirs are mostly complex deltas, fan deltas, braided river deltas, etc. In addition, in the exploration evaluation stage and early development stage, the well pattern of offshore oilfields is sparse and well spacing is large. Especially in the early stage of oilfield development, well data are very few, so it is difficult to establish an accurate reservoir geological model.
In order to solve this problem, this paper proposes a well-seismic integrated reservoir prediction technique based on seismic data frequency division processing and lithofacies distribution prediction technique based on sedimentary numerical simulation. On the basis of reservoir prediction, 3D reservoir geological modeling is carried out. With the reservoir prediction results as the constraint conditions, the sedimentary microfacies modeling is firstly developed, and then reservoir petrophysical modeling is carried out under microfacies constraints. The fine geological modeling of complex semideep reservoir is realized. Compared with the traditional geological model based on the constraint of 2D sedimentary microfacies map, the new modeling method has higher accuracy. The geological model established by the new method can more accurately predict the spatial distribution, porosity and permeability properties of reservoirs.
Real-Time Evaluation of Oil Spill Thickness
Authors: Vinther Morten Loell , Svanes Bertelsen Vemund , Storhaug Aanund , Bonvik-Stone Dickon John 
Published: April 2020

Abstract
The ability to detect oil spills reliably, as well as to carry out fast and effective recovery operations, is the onus of any extraction company working in the field. Unfortunately, detecting and tracking oil spills is no easy task. By employing a combination of radar, optical and infrared (IR) sensors, operators are empowered to not only detect, characterise and track spills, but also to locate "combatable oil", i.e. where oil is at its thickest, and therefore, where recovery efforts should be mobilised.
Radar-based oil spill detection (OSD) systems can be supported to great effect by the addition of optical and IR sensors. Real-time evaluation of oil spill thickness using such a combination of sensors is achieved thanks to the exploitation of some of oil's natural properties.
The first of these properties is that oil will interact with the surface of the sea, affecting radar backscatter imagery. When oil is present on the sea surface it impacts the surface tension of the water and, as a result, wind does not create the same short-wave patterns on the surface as in areas free of oil. This means that areas covered with oil will not exhibit backscatter in the same way as areas free of oil.
The second of these properties is that when oil and water are at the same temperature, oil emits less infrared energy than water, meaning that oil will appear cooler than water when observed using an infrared sensor. Additionally, unlike water, oil absorbs almost all light in the visible part of the electromagnetic spectrum, meaning that thick oil (where the upper layers of oil are insulated from the water below) will heat up in the daytime and become hotter than water. At night, the inverse will be observed, with the upper layer of thick oil cooling to below the temperature of the surrounding water.
As a result of these properties, areas of the sea that are polluted with oil will appear differently on the various sensor displays based on the thickness of the spill, the wind and current conditions, and whether it is day or night. By harnessing the combination of radar, optical and infrared sensors, operators can determine the location of spills in daylight or darkness. They can also determine the leading edge of the spill, allowing for an understanding of its trajectory, and where recovery efforts should focus their attention.
Furthermore, automatic tracking and historical insights can add much-needed information to user interface displays, giving operators comprehensive situational awareness.
Robust and Flexible: Key Concepts for the Design, Operation, and Sponsorship of Independent Deepwater Gathering Systems
Authors: Hlavaty William , Moorehead Michael , Powell Timothy 
Published: April 2020

Abstract
The Deepwaters of the US Gulf of Mexico are traditionally the province of the major international oil companies. Independent exploration and operating companies who make discoveries face more difficulty in finding viable options to developing and exploiting their found reserves. Many parts of the offshore industry have worked diligently to find ways to cut development costs for the Independent Operator.
In addition to cost, an Independent Operator that is unable to finance its own development faces additional risk in finding options to exploit a discovery. It is here where an independently operated Midstream solution may benefit the Independent Operator.
The authors propose examining existing business and operating models in which a Midstream approach may be applied in order to provide wholly independent gathering solutions in Deepwater. The concepts that make such a solution different from other field developments are explored including the business model of how this solution may be sponsored, financed and operated.
Managed Pressure Drilling – An Unconventional Efficiency Tool Applied in Deepwater
Authors: Dow Blaine , Rojas Freddy , Hobin John , Rojas Jimmy , Gallo Fernando , Abuelaish Ahmed 
Published: April 2020

AbstractApplied annular pressure, for both managed pressure and underbalanced drilling, was born on land decades ago. In fact, the first Rotating Control Device (RCD), the critical component, dates as far back as the 1930's. Simply closing the annulus around the drillstring, and "bottling up" the well, introduced new techniques that enabled wellbore pressures to be managed to drill a better well. In some cases, this was the only way to drill the well.Typical of the drilling business, innovation is generally derived from repurposing or repackaging technology to address new challenges. Applied annular pressure fits squarely into this arena. The shale boom in North America has pushed all technical limits, striving to squeeze every ounce of lost efficiency out of the program. The lighter your fluid, the more you can pump, the better your rate of penetration, the better you can clean the hole, and the less damage to drilling equipment… efficiencies compound. Lighter fluid introduces more pressure dynamics with the well, however, and these require managing. This is where Managed Pressure Drilling (MPD) came to life as unconventional drilling expanded. As a result, more than 75% of drilling rigs are making hole with RCDs in North America Land today.Early success of applied annular pressure drilling allowed for migration offshore also. The nature of equipment required to execute limits how easily it can deploy, however. So historically, it has been reserved for the most demanding "undrillable" wells. MPD was typically a technology of last resort, requiring equipment uniquely designed for offshore applications, along with space not commonly available on offshore installations. These barriers eroded over time, however, and MPD is now common on several offshore projects.Moving into deepwater, the step-change to overcome barriers becomes another significant technology shift. The RCD needs to fit into the drilling riser, and an additional annular is required to manage any gas buildup above the sub-surface BOP. These challenges are dissolving and MPD is picking up pace in deepwater. The motivation remains "undrillable" challenges. However, in order to justify the effort and cost, cracking the "efficiency" drivers that have pushed the shale revolution need to be harvested.What happens when the efficiency drivers applied in the shale factory start heading to deeper and deeper water? Surprising, the opportunities to harvest efficiency with MPD are even greater, with less effort, in deeper water. The challenge is getting the equipment there.This paper will explore two parallel universes, showing cases of the technical efficiency gains from real wells. In both arenas, the financial impacts of cost and savings will be normalized. Further opportunities to expand the "efficiency-verse" will also be explored, shining clear light on money well spent.
Unmanned Full Processing Platforms; Using Subsea Technology as Enabler
Authors: Frostad Anna Isabella Thomassen , Singer Thomas , Fløttum Linda , Rikheim Trygve Andreas , Balas Robin , Haaheim Svein Audun 
Published: April 2020

Abstract
Offshore full-processing platforms are permanently manned due to the large number of operational and maintenance tasks. Having these platforms unmanned and remotely operated would improve the field economy, reduce the personnel risk and minimize the environmental footprint. The use of subsea mindset and technology in the platform design can enable such a shift in the manning and operations regime.
Unmanned platforms have been in operation for decades in the form of simple platforms without complex process functions. The frequency of visits has however, turned out to be quite high. Further, maintaining facilities as unmanned has proved challenging when processing functions are added. To enable full-processing platforms to operate as unmanned installations, a new approach to design can be adopted. This new approach is characterized by use of design principles for complex subsea processing facilities and benefitting from the digital revolution.
A main difference when comparing subsea and topside processing facilities is the significant number of utilities, support and safety functions on a platform. For the new platform concept proposed, several of these functions are simplified or eliminated, which reduces complexity, the need for maintenance and cost. The platform concept is among others proposed without accommodation and helideck. Access by personnel and evacuation is via bridge to Service Operation Vessel.
By examining the Mean Time Between Failure for topside vs subsea equipment, it is evident that the subsea equipment has higher availability and requires less maintenance. For the topside equipment which as of today is maintenance intensive, e.g. compressors and pumps, the concept includes using subsea derived equipment. Seal-less subsea derived compressors are already proven for topside application. The maintenance need is determined based on surveillance by sensors and predictive analytics, i.e. predictive maintenance.
On a staffed facility there are cranes and trolleys for material handling and personnel are carrying out in-situ inspection and repairs, representing a significant number of offshore man-hours. For Subsea installations, the principle is plug & play replacement by use of intervention vessels. The layout of the new platform concept is arranged in a subsea derived manner adopting the replacement principle by use of vessels. Also, the platform is proposed with robotics tailored for intervention of minor items.
New technologies as drones and crawlers are developing rapidly and are used for inspection tasks replacing personnel, in addition to sensors and cameras and in combination with a digital twin. These technologies are comparable to using ROV for inspection of subsea equipment.
This paper will present the conceptual idea for the subsea derived full-processing unmanned platform in more detail, and discuss benefits compared to a conventional staffed full-processing platform.
Innovative Features Added to the Subsea Control System, to Enable a Safer Execution of the Intervention Operation
Authors: Mujahed Eslam , Abu Zeid Hosam , Eser Hakan , Morris David 
Published: April 2020

Abstract
The Intervention and well P&A are considered high-risk and complex operations that must be carried out in a fully managed and controlled environment. This can be achieved through enhancing the existing intervention systems or introducing new solutions. The intervention riser system and the riser-less open-water abandonment module introduce new technologies that will expand today's operating envelope to deeper and higher temperature environments while maintaining costs and risks firmly under control. Improved synergies can also be achieved through new alliances when different types of operating assets are lumped together, delivering seamless service through integration.
Advancing BOP Reilability through IoT Technology
Authors: Meziou Amine , Hattab Oussama , Meraz Jose 
Published: April 2020

Abstract
A blowout preventer (BOP) is one of the major pressure control safety devices used in the drilling of hydrocarbon wells. Hence, improving BOP reliability and reducing non-productive time has been always a concern to ensure safe and efficient operations. In the last years, multiple analytics tools have been developed by the Oil and Gas (O&G) industry to monitor the health of BOP components using the control system data. However, the ability of those tools to predict critical failures and establish a predictive maintenance strategy was constrained by the limited number of sensors and the inability to transmit higher fidelity data. First, this paper describes the state of the art of the BOP analytics, data transmission and instrumentation technology and points out its limitations. Different solutions are then proposed to leverage the IoT technology as a driver to enhance BOP predictive analytics capabilities.
Prevalence and possible aetiological factors of acne keloidalis nuchae in South–South Nigeria
Authors: Otike-Odibi Bolaji , Altraide Dasetima , Egboh Stella-Maris 
Published: April 2020

Background:
Acne keloidalis nuchae (AKN) is a scarring folliculitis found predominantly among men of African descent. It could present as pustules, papules or keloidal eruptions usually at the occiput of the scalp and has been associated with certain aetiological factors.

Aim:
The aim of the study was to determine the prevalence and possible aetiological factors of AKN in the University of Port Harcourt Teaching Hospital (UPTH).

Methods:
It was a 3-year retrospective study conducted in the Dermatology Clinic of the UPTH, from 2014 to 2017, where folders of patients who were diagnosed with AKN by dermatologist were retrieved and reviewed.

Results:
The prevalence of AKN was 1.7%. Male patients were predominantly affected with a male-to-female ratio of 21:1. The age range of the cases was from 18 to 51 years, with a mean ± standard deviation of 27.31 ± 7.01. Majority of the subjects had a history of clean-shaven hair (80.6%). Other possible predisposing factors were friction from collars (48.4%) and shaving of the hairline at the occiput during haircuts (64.5%).

Conclusion:
Despite the low prevalence of AKN, its social impact is glaring; therefore, more emphasis should be laid on the aetiological factors and management to improve the quality of life of the affected patients.