bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of a Cybersecurity Laboratory in Support of the Virtual Vessel Concept to Increase Safety Onboard Marine and Offshore Assets
Authors: Selvam Naveen , Scott Richard , DeWitt Cris 
Published: April 2017

Abstract
Owners and operators of marine and offshore assets must understand what is on "the wire" in their automated and highly-integrated systems. This information allows them to define the transforming functions where virtual data is converted into actionable cybersecurity knowledge. The ABS virtual vessel concept is the computational representation of the data that is sensed, stored, analyzed and transferred as actionable information on a marine or offshore asset. This paper discusses the concept through experiments designed to evaluate assumptions and hypotheses in a purpose-built cybersecurity test laboratory.
Increasing use of integrated control systems onboard the assets and complex integrated technology in the maritime and offshore industry to manage business comes with a higher risk of cyberattacks. These attacks are getting more sophisticated and, in many cases, can have significant impacts on critical areas of operation.
Maritime control system software is not constrained by the same physical laws that predict the physical behavior of equipment and vessels. Software systems behave differently and are evaluated by very different metrics. Because behavioral and security test methods are often conducted on in-service assets, comprehensive testing is impractical and potentially hazardous to perform onboard an asset. Therefore, assessments of cybersecurity solutions and guidelines are performed more on simulated systems in a laboratory environment rather than on actual in-service systems.
ABS is developing cybersecurity "use cases" in which patterns of cybersecurity threats, risks and solutions can be examined, characterized and gauged using field device level information for marine and offshore systems. This research can help the industry understand the nature and risks imposed on virtual vessel computerized elements and inform the development of guidelines and rules to increase the safety and security of real vessels. This paper describes the process of building a cybersecurity lab and research capabilities for marine and offshore assets. Specific projects examine current maritime, government and private sector approaches to research, identify and characterize cybersecurity events in maritime industrial control systems.
Best Practice for Analysis of Polyester Rope Mooring Systems
Authors: Falkenberg Erik , Åhjem Vidar , Yang Limin 
Published: April 2017

The objective of the Syrope JIP has been to improve the methods for safe and reliable design of fibre rope mooring systems. Normal, conservative, design practice for polyester rope mooring systems is to use an upper and a lower bound axial stiffness of the polyester. The use of a more advanced, but still manageable design practice allows for a more optimized design.
Only polyester lines have been covered by the work, but the principles are assumed to have a general validity. Extensive testing on change-in-length behavior has been performed on subropes. Testing has covered recommended test procedures from different standards and recommended practices and more realistic load sequences.
Based on test results a conceptual model for the behavior of polyester ropes has been developed. The mean length of a rope depends on the preceding highest mean tension in the rope and the actual tension, including its mean value. The response to wave-frequency and low-frequency loads is described by a dynamic stiffness which increases with the mean load in the line.
Recommended change-in-length testing of subropes is described, and principles for analysis of such tests for identification of parameters in the model are presented. Finally, guidance for use of the model in mooring system analyses is given.
Innovations in a Floating Production System for Optimizing Costs
Authors: Oliveira Allan Carre de , Ruggeri Felipe 
Published: April 2017

Abstract
It will be presented some developments for a ship-shape type floating production system to minimize installation and operating costs for a scenario Polo pre-salt Santos Basin. In that scenario, there are economic advantages using large diameter rigid lines for oil production and also requirements about oil treatment which increases the process plant weight and area at the production unit.
To deal with those new requirements an unconventional concept was developed. The concept is designed to operate with large diameter free standing steel catenary riser connected to a structure that may be disconnected from the hull. The possibility of disconnection allows the assessment of this solution in other harsh environmental scenarios, like hurricanes areas, where being disconnectable is required or an advantage in terms of safety.
The hull form is designed using an optimization process with genetic algorithms that took into account 7 parameters, having analyzed thousands of possibilities in the proposed scenario, focused in minimize steel weight to minimize the platform construction cost. Based on this solution, hydrodynamic analyses were performed to check the interference effects between moonpool and the riser support buoy inside the moonpool.
Based on the optimization results, the advantages and disadvantages of this solution are pointed out at well the estimated cost reduction, which also considers assessments in different scenarios by Monte Carlo approach.
Thriving in a Low-Oil Price Environment - Ursa Asset
Authors: Fairburn Mike , Henson Troy 
Published: April 2017

Abstract

Objectives/Scope
This paper describes a three-year performance improvement journey of Ursa, a Shell DeepWater Tension Leg Platform (TLP) in the Gulf of Mexico, from 2014-2016. The paper will describe the starting point, the foundation for change that was built with leadership, organizational engagement, designing a change program and the process of delivering that program to establish new levels of performance within the organization. The organizational scope includes asset leadership, offshore Facilities/Production staff and on-shore support staff.

Methods/Procedures/Process
The improvement journey involved understanding and increasing organizational capability, recurring reviews of the asset's strengths and performance gaps, selection of improvement initiatives that matter, timely execution of improvements and ensuring that planned results were sustained.
Some of the ways Ursa changed the way it works include:
Ursa's learnings are applicable to any capital-intensive organization.

Results/Observations/Conclusions
Like most organizations, Ursa had been subject to many improvement efforts before the time covered by this paper. However, the results of these improvement efforts had been mixed and were often not sustainable. This led to a predictable attitude in the organization that these "flavor of the month" improvements would come and go, without much change to daily operations.
The approach taken by the Ursa team changed that. By systematically improving how each person thought about, executed and validated their work, performance was materially improved. This took Ursa from a well-performing organization content with its output, to a truly world-class team that continually looks for the best ways to improve and optimize performance.
Improvements realized:
These improvements enabled Ursa to thrive in this low-oil price environment, lead in profitability versus peers, and become a model for TLP operations within Shell.

Novel/Additive Information
Most companies understand how to cut cost/activity…but you can't cut your way to an engaged workforce with more effective work execution. Ursa has found a way to engage its team to achieve dramatic results in this highly challenging environment. Read on to see how you can too.
Cost Effective Offshore Concepts - Compact Semi-Submersible - A New Concept of Windfarm Service Operations Vessel
Authors: Grace Lee , Lee Won-Ho 
Published: April 2017

Abstract
This paper details the process undertaken for the design of a novel windfarm Service Operations Vessel (SOV).
This paper covers:
An offshore wind energy sector overview Characteristics of the Compact Semi-Submersible (CSS) platform Design and analyses required for concept SOV validation Design challenges, risks and solutions Approval in Principle (AiP) process with class
The information within this paper will be useful to design companies moving away from their typical knowledge base and vessel portfolio. Venturing into a new market sector or new type of vessel always presents risk. This early stage AiP process reduces that risk before a project and design gains too much momentum to be able to incorporate regulatory updates or interpretations at a later stage. Challenging area's based on the designer's and classification society's experience are discussed with proposed solutions as well as areas to focus on and develop with up and coming rule updates, guides and interpretations.
The CSS platform is classed as a Mobile Offshore Unit/Mobile Offshore Drill Unit (MOU/MODU) due to previous versions of the design being classed in such a manner for the offshore Oil and Gas sector. Applying a vessel designed for this sector to a new but similar sector which requires alternate regulations calls for clear interpretations and rule compliance. The relevance and applicability of more recent class notations such as "Ship Shaped Unit" are still being investigated and analyzed. This could allow for more relevant and typical vessel like criteria to be applied to the platform when transiting to and from shore and between turbines but then allows for MODU like notations to remain when gangway connected or operating on station and in Dynamic Positioning (DP) mode. HAZID workshops are highly recommended for novel concepts such as this to identify and eliminate "show stoppers" during initial design stages. Time spent undertaking such reviews at this stage pay for themselves in a reduction in design rework during class, functional and production design stages.
The relatively immature and rapidly evolving nature of this industry sector leads to many challenges for all involved and the willingness and cooperation that classification societies play during early stage designs to provide the necessary guidance to safely meet the developing market segments is critical. Offshore Oil and Gas regulations become the founding basis for many novel offshore designs but are not always entirely appropriate because the mechanical, structural, stability, safety and habitability requirements differ in many ways. The AiP process undertaken between designer and classification society for this project highlighted many of these areas and highlighted areas in which rules require development and careful interpretation.
Pushing Conventional Boundaries of Hydrate Management in a Dry Tree Facility
Authors: Kurup Anjushri S. , Hernandez Oris , Idstein Timothy , Zamora Chris A. , Greenly Leah , Anderson Joseph 
Published: April 2017

In the oil and gas production industry, it is well known that formation of hydrate blockages can cause substantial economic impact in terms of deferred production and the costs of remediation. Considering these financial implications and to avoid any potential safety concerns during a hydrate remediation, most often operating companies design and operate fields on a hydrate management philosophy of complete avoidance of hydrate formation. In the last few years, however, a shift in the hydrate management philosophy is being observed as discussed in the publications of Creek et al., 2011 and Kinnari et al., 2015, to cite a few. Due to the developments shifting towards more extreme environments, hydrate management philosophy is shifting from complete avoidance to risk management.
This paper discusses the evolution of hydrate management philosophy of a dry tree facility in the Gulf of Mexico. During steady state production, the fluids flow at temperatures outside the hydrate envelope. The hydrate management strategy following a shutdown is to displace (bullhead) the riser tubing with dead oil within the cooldown time (time required for the fluids to enter hydrate forming conditions after a shutdown). However, due to the dry tree configuration, low liquid rates and insulation performance, the cooldown time is short for these high water cut wells. Using gas lift to boost production further decreases the predicted cooldown time to less than an hour making it operationally difficult to complete hydrate safe out measures within the design cooldown time. A few tests conducted in the field to identify a realistic time available after shutdown, along with a few historical instances during which the hydrate safe out measures could not be completed within the cooldown time, have indicated that there exists a range of water cut (WC) and GOR (Gas to oil ratio) within which the system was restarted without a hydrate blockage. This paper describes how a combination of industry standard predictive tools coupled with field observations is shaping the hydrate management philosophy of this field, by operating within conditions that can form hydrates but do not lead to blockage. The paper also describes two hydrate blockage instances that occurred when the operating conditions were outside the identified hydrate blockage limit reinforcing that the WC and GOR of the fluids have a strong influence on the hydrate blockage risk.
Mitigation of Hydrates Using Continuous KHI Injection in Deepwater GoM
Authors: Swank L. , Kapadia K. P. , Webber P. A. , Jones R. 
Published: April 2017

Anadarko operates a subsea tieback well in 3,500 ft of water depth that currently produces 525 bbl/d of water, 250 bbl/d of condensate, and 25 mmscf/d through an uninsulated flowline and riser. The subsea flowing pressure and temperature are within hydrate conditions and hence, continuous methanol injection is used to mitigate hydrates using thermodynamic inhibition. With an increase in water production forecasted, higher injection of methanol was required. However, existing chemical injection capabilities were limited and could not accommodate the forecasted increase in water production. Also, high methanol usage resulted in the produced oil on the platform being contaminated with methanol. With a methanol in crude (MIC) limitation of 50 ppm for the export pipeline, a reduction in methanol usage was required.
Based on the modeled flowing conditions for the well, it was determined that anti-agglomerate hydrate inhibition was not feasible because of a lack of hydrocarbon liquid phase at the point of injection subsea. Lab testing and qualification of a kinetic hydrate inhibitor (KHI) was pursued. Laboratory testing was completed for selection of KHI to be co-injected with methanol while minimizing the impact to produced water quality. The details of the change from methanol to KHI and methanol co-injection is described in this paper along with the field optimization.
The initial methanol reduction strategy called for continuous injection of methanol at approximately 20-23%vol to water of the well. With the application of the co-injection process, the methanol injection volume was slowly stepped down while maintaining the same KHI treat rate, injected at 5.1%vol of methanol. Lab testing from a 3rd party who provided the KHI, indicated the lowest possible treat rate of methanol at 18% to water. Once 18% methanol injection was reached in the field and successful, operations re-evaluated and opted to continue optimization of the methanol-KHI dosage rate. Throughout the study, water production of the well from 480 bbl/d of water to 525 bbl/d of water, there was further need for reduction. Currently with the addition of KHI the well is operating at 7.5% methanol injection to water production, about a 50% reduction in methanol volume. Additionally, methanol in crude (MIC) concentration has reduced significantly in the export oil with the reduction of methanol injection.
By increasing the KHI treat rate, there can be a greater reduction of methanol injection to the system and a lower concentration of methanol in the crude. High volumes of methanol in the export line could result in the pipeline shutting in the platform and subsequent down time for the operator. The combination of KHI with methanol was successful in significantly reducing methanol (&gt;50%), proven to be cost-effective, enables reduced methanol injection requirements.
New Wireless Acoustic Network Provides Real-Time Downhole Data During Completion, Casing and Cementing Operations
Authors: Hawthorn Andy , Aguilar Sergio 
Published: April 2017

Abstract
The drilling world has benefitted immensely in the last 20 years from real-time data during on bottom time. Huge advances in safety, efficiency and productivity have come with directional control and geosteering data being transferred back to surface. As wells have become more complex, particularly in the deepwater environment then the actual on bottom drilling time has reduced to less than 15% of total rig time (Blacklaw: SPE GCS Annual Drilling Symposium. April, 2016). The casing and liner running, cementing and completion installation related activities have, however, not had those same benfits. They instead have had to rely on surface measurements and modeling. As wells have become more complex and windows of operations tighter there are multiple case histories where these models and surface measurements are significantly diverging from what is actually happening downhole.
Accelerated Innovation as the Great Enabler for Well Completions - Tools for Cheaper, Safer and Faster Ways of Completing Wells
Authors: Ganguly Partha 
Published: April 2017

Technology innovation has played a great role in oilfield by continuously (a) increasing recoverable reserves, (b) decreasing production cost per barrel of oil equivalent (BOE), and (c) making operations safer. The current paper will focus on some of the game-changing innovations and their impact on operational cost and complexity. In Well Completions arena, a significant number of innovative technologies and processes have been developed in the past few years. These include sealing technologies for high-pressure, high-temperature wells that makes production from these wells possible; high-expansion packers for open-hole completions; erosion and corrosion resistant sand screen media that can be easily assembled on the base pipe and retain torque and tension requirements; and autonomous ICDs that can sense and delay water production.
The recent dramatic downturn in oil prices has further accentuated the need for high impact innovation. Additionally, a significant reduction in the time-to-market of new technologies is a competitive advantage. Such an accelerated process merits special considerations, including development of technology processes to assess functional risk in an accelerated manner. This has been done using extensive simulation work (at system as well as sub-system level) in combination with novel experimentation to validate the models. Such model-based development has led to significantly faster convergence of the design and experimentation cycle, as compared to the previous approaches. Additionally, organizational practices (including customer alignments) to enhance innovation success through lean processes also need to be considered.
Comprehensive Experiments and Modelling Reduces Uncertainties in Liquid Management for the Tanzania Gas Project
Authors: Biberg D. , Kjølaas J. , Staff G. , Vanvik T. , Nossen J. , Lawrence C. , Holm H. 
Published: April 2017

Abstract
The Tanzania Gas Project aims to exploit reserves located offshore from Tanzania in East Africa. The project faces challenges in the management of liquid content due to deep waters, rough seabed terrain, long transport lines to shore, relatively steep inclinations, and very dry reservoir fluids. The narrow operational envelope associated with the water depth underlines the importance of accurate flow simulations for design and production. In addition, the low liquid loading conditions are expected to result in substantial liquid accumulation in the upwardly inclined sections of the pipeline for low production rates. A large-scale experimental campaign was launched to reduce the uncertainty in the field development. A novel experimental "screening technique", allowed for the sampling of an unprecedented number of flow rate combinations corresponding to the onset of liquid accumulation. Diameter scaling was addressed by conducting similar experiments in 8- and 12-in. pipes. Froude number similarity was utilized for scale-up and to assess model predictions for field conditions. The data confirmed That the flow model captures the correct physics, and allowed for fine tuning. The updated model was applied in an uncertainty analysis for the Tanzania field, based on a large number of combinations of key input and flow model parameters, sampled from estimated uncertainty distributions. Simulation results for gas production rate, minimum turndown point, etc. were determined as probability distributions. The effort to quantify and reduce uncertainty has been very successful. Engagement of the operating company with experimental researchers, model developers, and software suppliers greatly increased the understanding of the physics and diameter scaling of low liquid loading flows, significantly reducing the uncertainty for gas condensate field developments.
Advanced Petrophysical Evaluation of a Low-Resistivity Laminated Shaly Sand Formation Showed Significant Increase in Reserves Calculations
Authors: Kukharchuk Alisa , XiaoXuan An , Doss Eric 
Published: April 2017

Abstract
Reserve estimation of low-resistivity, low-contrast, laminated shaly sand formations from conventional logging tools often yield inaccurate results of the true potential of the reservoir. A productive zone with horizontal resistivity of 1 Ohm-m can easily be interpreted as wet and therefore overlooked. The resistivity suppression is caused by a lack of conventional tool resolution and the presence of conductive shale lamina. This paper will describe advanced techniques for effective evaluation of the low-resistivity laminated shaly sand sequences.
To accurately identify and quantify these thinly laminated sands, we will detail a method to acquire the necessary data for proper reserve calculation with examples from a well in the Gulf of Mexico. The study well has a deep-water distal turbidite depositional environment, and contains significant intervals of thinly-bedded sands and shales. The sedimentary facies appeared to be different to offset wells because of separation by a large fault. This geological setting caused an expected zone of interest to have a very low apparent resistivity and brought a lot of uncertainty about hydrocarbon potential of the formation. To provide a thorough appraisal, a suite of most beneficial for such environment advanced wireline measurements were acquired, which were combined with core analysis and conventional logs for an accurate evaluation of thin sand layers.
This integrated approach improved net pay calculations by 80% when compared to the conventional petrophysical analysis, allowing the operator to make some key adjustments in the completion program. The proof of the laminated formation having hydrocarbon potential from the integrated petrophysical analysis was confirmed by the production data. Multiple 24-hour flow tests confirmed oil and gas production with an inconsequential amount of water.