bluuebunny/crossref_metadata_2025 huggingface dataset:
Bottom-Up Analysis to Unravel Potential Problems and Emphasize the Impact of Individual Steps in Closed-Loop Field Development
Authors: Loomba Ashish Kumar , Botechia Vinicius Eduardo , Schiozer Denis José
Published: April 2020

Closed-loop field development (CLFD) is a feedback-based approach to optimize production strategy by utilizing new information iteratively during field development. Positive and negative results have been presented in previous work using CLFD, so this paper presents a bottom-up assessment of CLFD workflow to exhibit the impact of individual steps on the workflow, highlighting associated potential problems and, finally, proposing a methodology to tackle these problems.

Our CLFD workflow consists of updating static information, assimilating dynamic data to select an appropriate subset of models and, finally, selecting representative models to optimize the production strategy under uncertainties. We performed four activities to expand our understanding of CLFD by applying the workflow on UNISIM-I, a benchmark case study: (1) applying the aforementioned CLFD workflow, (2) applying the workflow after modifying objective function of optimization process, emphasizing the likelihood of success of optimized production strategy over the ensemble of simulation models, (3) applying the workflow after modifying the objective function, as well as the criteria for selecting the appropriate subset of models, post dynamic data assimilation, and (4) reanalyzing the results of activity 1 after using flexibility of drilling (FoD) - an approach proposed to partially imitate the real-time decision-making process to ensure that the heel of a well is not drilled in a non-reservoir zone, by utilizing the available information.

The application of the initial CLFD methodology (first activity) led to an increase in expected monetary value (EMV) based on simulation models, but we observed a decrease in EMV when we implemented this optimized strategy in the reference case UNISIM-I-R (a very refined model that emulates a "true field"). This negative result formed the basis for our motivation to perform the bottom-up analysis. During the second activity, our attempt to improve the optimization process using a new objective-function, led to a significant improvement in EMV for the reference case, compared to the first activity. Re-applying the CLFD workflow using this newly tested objective function, while using stricter criteria for selecting approved models (third activity), provided an optimized production strategy for the reference case. Last activity provided a deeper insight into the CLFD workflow. Application of FoD, during the fourth activity, revealed that the poorer results during the first activity can be segregated into two separate components: (a) relatively poorer CLFD workflow and, (b) ignoring FoD to ineptly drill the wells in non-reservoir zones.

The bottom-up approach helped us systematically improve the CLFD workflow. Implementation of the improved workflow ensured that the optimized production strategy not only improved EMV for simulation models, but also the reference case.
The Science of Sequencing Well Programs
Authors: Danner George Earl
Published: April 2020

The order of drilling a collection of wells matters. One possible sequence gives you an NPV and a total duration and another slightly different sequence of the same wells can yield an altogether different outcome, even simply swapping two wells in order. The nonlinearity of optimizing the sequence means that above a very small number of wells it is impossible for a human to intuitively identity the optimal sequence—the one sequence that yields the "best" possible outcome. As a guide, sequencing 13 wells has a surprisingly large solution space of 6.2 billion possibilities.

We must harness computing power to understand the optimal sequence of wells to drill and complete. Facilities have to be timed perfectly to be in place when the wells are ready for production. Zipper frac opportunities arise in a once-in-a-billion chance when two adjacent wells allow it to be done in a practical way. The special math of optimization is used within a computer model to calculate the optimal sequence, and the associated KPIs such as profitability and total program duration. In effect, it is as if the computer model tries every single one of the billions of possible sequences, and places the leaders on an ever-shifting leaderboard as it goes along.

In our talk we will elaborate on three past projects where we have applied analytical engines to discover optimal well sequences with lessons on how to reproduce this work in your own drilling operations.

Conventional approaches to optimization, such as those found in downstream applications like refining do not always work adequately for well sequencing due to the highly non-linear nature of the constraints, such as spatial interference between bit positions of adjacent wells. We will discuss a heuristic (non-traditional) approach that was required in one particular case of well sequence optimization.
Soil Modeling for Pile Driving Simulations Using a Vibro Hammer
Authors: Bielefeld Marcel , Moscoso Nicolas , Verbeek Gerald
Published: April 2020

As vibratory driving is increasingly used to install offshore foundations, especially for offshore windfarms, an accurate soil model is key to reliable pile driving predictions and thus to improved project planning and execution. During the pile driving, the soil properties, and thus the soil parameters, do not remain constant. For vibratory driving, this effect is generally simplified by the application of the Beta Method, which was first proposed by Jonker in 1987[1]. While this simplified approach could be justified based on the computing capabilities at that time, a more sophisticated soil model should be used as part of pile driving simulations to ensure that the results are more accurate.

In this paper, the state-of-the-art soil model for vibratory driving will be described and then illustrated through two brief case studies where the pile driving simulation results are compared with the actual installation records. The paper will show that while the predictions are not perfect, they forecast the pile driving process realistically. To further enhance prediction capabilities, the paper will suggest that pile driving with vibratory hammers is monitored and that the recorded data be used for post-processing to gain a more in-depth understanding of the soil behavior.
Standardization Of Procurement Equipment Specifications: Establishing A Strong Foundation For Oil & Gas Capital Project Development And Delivery
Authors: Postema Adri , Ray Tony , Jack Bristow
Published: April 2020

Industry-wide standardization is needed for operators to manage the $3 trillion in CAPEX expenditure forecast for 2018-2025 (Global Data, 2018), while maintaining competitiveness and mitigating risks.

With the backing of the World Economic Forum, Joint Industry Program 33 (JIP 33) was initiated to drive industry-level standardization for the procurement of equipment items, moving the industry structurally – across the value chain - towards common engineering designs and solutions established by means of cross-company collaboration.

Fourteen (14) standard specifications have been delivered to date. Their adoption by 12 major operators is being measured and is progressing well. This enables the program to capture and evaluate successes, challenges, key learnings and feedback. The program is also establishing a process for future maintenance of JIP33 specifications in order to achieve sustained benefits.

A further 35-40 supplementary specifications are being developed, based on recognized industry or international standards by the end of 2020.

This paper will present the status of the JIP33 program and showcase some of its early successes, challenges and learnings. Experience with digital requirement developments will be shared, as well as learnings from the adoption and use of the Phase 1-2 specifications by JIP33 members.
Risk-Based Offshore Decommissioning Standards and Regulations
Authors: Pollett Buford Boyd
Published: April 2020

Objectives/Scope

This paper will examine the current process in establishing decommissioning standards and regulations for the offshore energy industry. Further, this paper will examine the extent some of the current decommissioning standards and regulations utilize a risk-based approach to setting standards and promulgating regulations.

Methods, Procedures, Process

The author will review how the classification societies establish standards and certain government agencies execute regulations concerning offshore decommissioning activities.

Results, Observations, and Conclusions

Since standards and regulatory policies and procedures can substantially impact the profile of companies investing and operating in the petroleum industry, this paper will highlight how risked based standards and regulatory policies and procedures may enhance reliability for end of life cycle activities.

Similarly, other sectors of the energy industry should also appreciate that the end of life-cycle regulatory regime the petroleum industry now faces in many cases may be the regulatory regime that these sectors will face going forward.

Therefore, professionals and stakeholders should work together to promote transparency, and collaboration as well as a practical approach to ensure that decommissioning standards and regulations are both realistic and sufficient.

This paper will discuss the areas of coordination to enhance safety, mitigate against environmental risks, and otherwise provide potential solutions in achieving and maintaining a social license to operate.

Novel/Additive Information

Also, the paper will promote knowledge sharing of risked-based decommissioning standards and regulations in a collaborative effort to enhance the protection of stakeholder interests. Correspondingly, this paper will examine the potential pros and cons of using risk-based assessments in establishing decommissioning standards and regulations.
Deep Learning Toolkit: Shallow Geohazards Case Study
Authors: Krueger Ana , Endresen Paul , Omoboya Bode , Lartigue Benjamin
Published: April 2020

Identification of shallow hazard features at the sub-surface are performed via seismic interpretation of high-resolution three-dimensional (3D) seismic surveys. Today, seismic interpretation is a fastidious and time-consuming process. Usually an interpreter must spend weeks or months to fully interpret this type of survey and its volume. Deep learning methodologies utilizing neural networks are currently revolutionizing seismic interpretation by accelerating the speed in which geologic features such as faults, salt diapirs, and gas chimneys can be mapped. It has become an industry goal to utilize neural networks for all uses of seismic interpretation, including shallow hazard identification.

There have been challenges to the adoption of machine learning, to the interpretation of shallow hazards. The results of this interpretation have a direct impact on drilling safety and therefore its accuracy is paramount. Traditional machine learning technologies do not consider the human experience and abstract thinking required for seismic interpretation. For interpreters to fully trust the results of the neural networks, they must spend an extensive amount of time conducting quality control of the results and editing as needed. Traditional machine learning technology requires a significant amount of time to be spent on data preparation.

Our project has two main goals. The first goal is to create technological improvements to enable humans to work interactively with neural networks. The second goal is to reduce the amount of time spent in data preparation to zero. We present a new interactive deep learning methodology, that differs from existing methodologies and achieves these two goals. We have built our methodology on top of our proprietary technology that provides random data access to seismic data, enabling interactivity between the neural network and the geoscientists, therefore putting geoscientists in complete control. Our methodology eliminates the burden of data preparation methodologies, because it does not require prior randomization of the seismic data like older technologies. We achieve acceleration, and improved results in the seismic interpretation of shallow hazards.
Streamlining Zinc Removal From Completion Fluid Flowback And Produced Water In Offshore Oil & Gas Production
Authors: Broussard Shane , Burclaff Philip
Published: April 2020

This paper and its presentation provides an overview of an innovative way to treat zinc-contaminated water that might, for example, result from the use of completion fluids with extremely dense zinc bromide—up to 19.2 pounds (8.7 kilograms) per gallon—in high-pressure wells. Traditional approaches to treating zinc from completion fluid flowback and produced water are cumbersome and costly, with potential for perpetual liabilities associated with onshore in-ground disposal. Discussed will be a simpler, highly effective system that can save as much as 25 percent or more in zinc treatment and disposal costs.

The patented system combines two technologies—reverse osmosis (RO) membrane and ion exchange (IX) resin—to minimize zinc waste volumes. It works without chemicals and has a relatively low residence time. By selectively removing zinc, the remainder of the salts and most of the water can be discharged to the ocean. The zinc-removal system is available in two options: (1) RO with IX and (2) IX only. Both components arrive in a skid-based, offshore package. The entire system is fully compliant with API RP 14C safety standards and can operate as a standalone or integrated with pre-treatment systems that separate oil and other contaminants from completion fluid flowback or produced water.

In a 2019 efficiency test with a large independent E&P operator in the Gulf of Mexico, the system treated 36,387 barrels of water using five pairs of IX resin columns that together averaged 5 barrels-per-minute flow rates, with four total backwash cycles. Because the TDS of the produced water was already high, RO was not needed as part of the treatment system. Ultimately, the operator was able to discharge 35,400 barrels of water overboard instead of being collected and sent ashore. Only 900 barrels of zinc water from the IX resin columns needed to be sent ashore for disposal, although that amount was reduced by 75 percent to just 225 barrels upon the system's second deployment a month later.
Accelerating Petroleum Project Delivery Through a Lean Operational Readiness Structure
Authors: Kusumawardhani Mayang , Markeset Tore , Kumar Rajesh
Published: April 2020

Delivering a petroleum project on time and on budget in a safe and quality manner is one of the main goals in every project. Especially with the fluctuating oil price, the need of meeting the budget, quality and schedule increases. The paper proposed to improve the project delivery time through integration of functions in the operational readiness and assurance (ORA) structure.

This study was validated by broad respondents of industry practitioners to review the suitability of the proposed structure. The study also aims to gain insight into ORA from the industry practitioners, since most of the available methods are patented or owned by the organizations.

In addition, the ORA processes will focus on identifying and minimizing the potential operation risks early in the project phase and ensuring that the project delivers the best possible value to the business. The process will be illustrated and explained in the paper. The paper will guide the Readers through the control and alignment of actions, tasks and deliverables organized under the knowledge areas that are maintained throughout the project.
Suction Pile Seabed Landing and Vents Calculation
Authors: Løkke Arnkjell , Rahim Amir , Schrøder Knut
Published: April 2020

A computer program has been developed to simulate the landing of suction piles on the seabed. The procedure is based on the dynamic analysis procedure outlined in DNVGL-RP-N103 (DNVGL 2017) and calculates the pile motion as it penetrates the soil using a time integration scheme to simulate the dynamic seabed landing. The analysis method considers all significant forces acting on the pile with their time-dependent values, including gravity, buoyancy, crane wire tension, hydrodynamic pressure within the pile, and soil resistance. The program can be used for a given pile geometry to determine the maximum allowable lowering velocity that does not lead to foundation failure. Or for a given lowering velocity, determine the minimum allowable vent area in the pile.

The DNVGL procedure is numerically challenging to implement because iterating on the main unknown variable (the incremental soil displacement) using the last known state parameters will not necessarily lead to convergence towards the ‘correct’ solution. The use of a line search algorithm is proposed to overcome this issue. The results of a sensitivity study are briefly presented to investigate how the main parameters influencing the results.

The dynamic analysis method is also compared to the traditional ‘simplified method’ of DNVGL-RP-N103 Section 6.2.6 which considers only static forces acting on the pile and neglects the beneficial dynamic effects of damping. The advantages of using the dynamic method over the simplified method is discussed.
Gas Hydrate Formation & Transportability During Transient Shut-In/Restart Conditions
Authors: Pickarts Marshall A , Croce Daniel , Zerpa Luis E , Koh Carolyn A.
Published: April 2020

Hydrates are crystalline water compounds that may form in deepsea pipelines and have the ability to quickly and efficiently plug flow. Given this issue, gas hydrate formation tests have been conducted and reported in a number of published articles. However, most published data has focused on continuous "steady-state" operations and a gap exists for the more complicated, yet interesting transient shut-in/restart scenarios. Motivation to study such systems are further exacerbated given that industrial fields can operate outside the gas hydrate formation region during continuous production. Hydrates become a major concern especially during unplanned shutdowns and restarts. Therefore, this work focuses only on hydrate transient results. Industrially relevant scenarios are investigated by looking into gas hydrate formation and its effect on fluid transportability through visualization and pressure drop during shut-in and restart in a laboratory-scale flowloop.

The effects of parameters such as water content and dispersion state, shear, chemical injection, and oil properties on hydrate formation under transient conditions are reviewed and general agreement is shown between the studies. Overall, the general consensus is that lower water contents, dispersed water, high shear, thermodynamic inhibitor injection, dosing of anti-agglomerants or kinetic hydrate inhibitors, higher oil viscosities, and oils with natural chemical surfactant properties can be favorable for ensuring successful restart of hydrate forming systems.

Flowloop tests in a gas-dominated system show that film growth over and around the liquid pool at the bottom of the pipe could lead to plugging in a significant portion of the flowline. This could continue to build up over time (with the addition of fresh hydrate forming materials in an actual system) and inhibit gas flow. Further tests on an oil-dominated system with an intermediate water content demonstrate how shut-in conditions could potentially increase the risk of plugging compared to dispersed lower water content systems. In the former case, water accumulation to low spots in the flowloop allowed for localized areas of high water concentration, where rapid hydrate bed formation in partially dispersed oil-water sections controlled the overall fluid transportability.
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

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

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.
Secondary Control In Subsea Mining
Authors: Teuteberg Michael
Published: April 2020

Subsea mining increasingly plays an important role in the extraction of raw materials. The decentral automation is the next generation of this technology. The conventional hydraulic drive systems were not able to fulfil the requirements of slow speed parallel drive operation of the chain drives of the vehicle with a sufficient result.
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

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

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.
Qualification Program for Subsea Batteries
Authors: Glaser Markus , Winter Tobias , Abele Manuel , Schnitzler Jan
Published: April 2020

Cost reduction, deep water, long-step outs, HSE (Health, Safety and Environment) and reduction of carbon footprint drive the change from hydraulic to all-electric subsea control systems in the offshore oil and gas production. The main challenge of an all-electric control system is the safe and reliable actuation of the valves on the tree. A battery provides the power and energy to supply the electric actuators to close the valves in case of an ESD (Emergency Shutdown). The paper presents the qualification program developed to access the performance and safety over the design life of 25 years together with the results after a 3-year qualification program.

The qualification program was based on a risk assessment taking into consideration the uncertainties associated to this novel subsea technology and the API 17F for qualification requirements. The qualification program developed covers the following main sections: Misuse (destructive testing), Cycle Testing, Environmental Testing and EMI (Electro-magnetic Interference) testing. To access the state of health a large signal EIS (Electrochemical Impedance Spectroscopy) has been developed and applied throughout the qualification program together with the DC-resistance and capacity measurements. For the cycle testing a DoE (Design of Experiment) methodology has been applied to develop a test plan which includes the parameters: temperature, cycles and idle time. The testing was performed on 30 cells in parallel.

The qualification results show a degradation of the battery depending on the parameter sets. The EIS measurements correlate with the degradation of the battery performance. The testing parameters range from −4°C to 50°C to stimulate an increased degradation. A reference group was used to access the acceleration factor for the increased temperature. The DC (Direct Current) measurements show an increase of the internal resistance over time.

The results provide details for a qualification program for subsea batteries in order to access the performance over the lifetime of 25 years. The program includes additional testing and monitoring compared to the API 17F requirements for PCBs (Printed Circuit Boards). The qualification program also provides information about the degradation kinematics of Li-Ion Batteries over the design life of 25 years. Based on the results of the qualification program a design life of 25 years can be concluded.
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

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

Applied 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

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

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

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.
Long term trends and breeding parameters of Gull-billed Tern Gelochelidon nilotica in three Italian coastal sites
Authors: Grussu Marcello , Scarton Francesco , Verza Emiliano , Valle Roberto G.
Published: April 2020

Between 2001 and 2018 colonies of Gull-billed Tern were monitored in large wetland complexes of Veneto (lagoon of Venice and the Northern Po Delta) and Sardinia (western and southern) regions. Most of the colonies settled in man-made structures such as islets, levees, dams, located inside fish farms, fish ponds and salt pans. Laying took place around half May until early June (Veneto), with eggs occurring in the nests until half July (Sardinia). Colonies had 3-230 pairs, with several instances of isolated pairs; colonies were mono- or plurispecific, with other Charadriiformes. The number of eggs per clutch was 2.6±0.6 (N=111, 1 SD) in the Venice lagoon, 2.6±0.6 (N=182) in the Po delta, 2.3±0.70 (N=1007) in Sardinia; hatched eggs were 2.2±0.6 (N=111), 2.0±0.7 (N=182) and 1.7±0.67 (N=40) per nest, respectively. The most important cause of breeding failure was due to flooding of nesting sites, due to the rapid increase of water levels inside fish farms and salt pans. During the 2001-2018 years, the Gull-billed Tern nested regularly in Sardinia, whereas in the Po Delta the first nesting occurred in 2001 and in the lagoon of Venice in 2008. The whole population ranged between 34 and 417 pairs until 2017 (223.6±113.4, N=17), with a sudden increase up to almost 1,000 pairs in 2018; the overall trend is of strong increase (p<0.01), with an annual rate of 10.5%.
Students' guide to veterinary medical terminology
Authors: Penzhorn B. L.
Published: April 2020

No abstract available.
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.