bluuebunny/crossref_metadata_2025_split huggingface dataset:
Generalized Framework to Simulate Gravel Packing in Wellbore Completions
Authors: Mimouna A. , Verma A. , Guddati M. N. 
Published: April 2018

Abstract
A generalized numerical framework to simulate gravel packing in typical wellbore completions is proposed. Given the well, downhole tool string configuration, fluid and gravel properties, and pump schedule, the simulator predicts the time evolution of the pressure, fluid and gravel fluxes and concentrations along the wellbore. The time evolution of the gravel concentration provides the packing pattern and the end of job pack state. This is achieved by solving the one dimensional (1D), mass and momentum conservation equations for the fluid and gravel in a staggered manner. A 1D, piecewise linear, finite element method is used to discretize the governing equations along the wellbore. The architecture of the framework is general enough to handle typical wellbore completions and gravel packing tool string configurations. This is achieved by modeling wellbore components as generalized forms of nodes, linear elements (with or without cross flow), and sources/sinks. This description allows different gravel packing completion configurations to be modeled generally without resorting to a separate and explicit model of each type of tool. At each time step, the whole system is assembled, and the nonlinear system is solved using robust and performant non-linear and sparse linear solvers. The software heavily leverages object-oriented design and high-performance computing practices. Finally, the simulator is used to show the efficacy of the Alternate path technology shunt tubes in achieving complete gravel pack in a long horizontal well. This is shown by simulating cases where significant leak-off would result in a premature bridge in the absence of the shunt tubes. This generalized approach should allow for a flexible extension to simulating gravel packing using other wellbore completions such as washpipe diverter valves, screens with inflow control devices.
Comparing Levelized Cost of Energy for a 200 MW Floating Wind Farm using Vertical and Horizontal Axis Turbines in the Northeast U.S.A.
Authors: Shelley Steffen. A. , Boo S. Y. , Kim D. , Luyties William H. 
Published: April 2018

Abstract
The technology to engineer, fabricate and install offshore floating wind turbine exists and is feasible for all components. Applying lessons learned from offshore oil and gas projects with respect to engineering execution options, competitive supply and reduction in life cycle costs makes offshore floating wind a commercially viable energy supply in regions with relatively high electricity prices or in regions that have other geographical or resource constraints to bringing additional energy supply on-line.
However, while horizontal wind turbine (HAWT) technology is developing rapidly and driving down cost, it may be possible to further drive down offshore floating wind costs by choosing a vertical axis wind turbine (VAWT) technology. VL Offshore has developed a cost effective 5 MW floating foundation, Y-Wind semi for HAWT. In this study, the LCoE (Levelized Cost of Energy) of the Y-Wind semi with 5 MW HAWT is compared against the same foundation type with a 5 MW VAWT. For the present work, a 200 MW wind farm, located about 10km off shore the Northeast U.S. at a water depth of 100m is selected. This water depth exceeds the current commercial limits for fixed foundations for offshore wind. LCoE is estimated using the tool developed by NREL, considering all the cost parameters of foundation and mooring CAPEX, installation, operation and maintenances, in-field and export power cables, capacity factors, turbine layouts, substation, discount rate, cost escalation rate, current electricity price and design life. The LCoE results indicate that a 5 MW VAWT foundation will be more commercially viable than a comparable 5 MW HAWT foundation. The LCoE values compare favorably to the LCoE values for most electricity prices in the Northeast states.
Offshore Wind Sediment Stability Evaluation Framework
Authors: Jones Craig , McWilliams Sam , Engelmann Georg , Thurlow Aimee , Roberts Jesse 
Published: April 2018

Abstract
Developing sound methods to evaluate risk of seabed mobility and alteration of sediment transport patterns in the near-shore coastal regions due to the presence of Offshore Wind (OW) infrastructure is critical to project planning, permitting, and operations. OW systems may include seafloor foundations, cabling, floating structures with gravity anchors, or a combination of several of these systems. Installation of these structures may affect the integrity of the sediment bed, thus affecting seabed dynamics and stability. It is therefore necessary to evaluate hydrodynamics and seabed dynamics and the effects of OW subsea foundations and cables on sediment transport.
A methodology is presented here to map a site's sediment (seabed) stability and can in turn support the evaluation of the potential for these processes to affect OW deployments and the local ecology. Sediment stability risk maps are developed for a site offshore of Central Oregon. A combination of geophysical site characterization, metocean analysis, and numerical modeling is used to develop a quantitative assessment of local scour and overall seabed stability. The findings generally show the presence of structures reduces the sediment transport in the lee area of the array by altering current and wave fields. The results illustrate how the overall regional patterns of currents and waves influence local scour near pilings and cables.
Cold Finger Benchmarking Study for Paraffin Inhibitor Selection
Authors: Peng Yun , Golchha Abhishek , Broze George 
Published: April 2018

Selection of effective paraffin inhibitors is critical for managing wax deposition risks in existing assets and for enabling potential CAPEX savings in new developments. Cold finger (CF) testing is a common method used for screening paraffin inhibitors (PI), but there are various kinds of in-house-developed and commercial CF equipment used throughout the industry. Additionally, there is no standard PI testing protocol. In some cases, there are inconsistent results between laboratories when evaluating PI performance.
To better understand the root causes of PI testing discrepancies and investigate the impact of key parameters on test results, a benchmarking study using both in-house and commercial CF equipment was conducted. Additionally, Shell (the Company) and BHGE (the Vendor) conducted a detailed joint exercise to understand and benchmark the commercial CF equipment used in both of their laboratories. Finally, the laboratory results were compared against field performance through a case study for a Gulf of Mexico operating asset.
PI performance was found to depend upon the particular oil as well as testing conditions, test procedures, and equipment. Good agreement in PI performance was observed between the two laboratories using the same testing conditions with the same CF equipment and equipment specifications, under similar procedures for a given crude oil. In this study, it was observed that shear and CF roughness can play a significant role on PI test results. Rougher CFs tend to make certain PIs less effective under low shear conditions. Hence, a PI chosen based on a specific set of conditions, equipment, and procedures might appreciably differ in its performance if any of the above parameters are changed. Therefore, selecting appropriate testing parameters is important to identify and qualify an effective PI suitable for a specific field application.
This work makes it possible to improve standardization between laboratories and helps to better understand the limitations, uncertainties, and suitability of CF tests for predicting PI performance in the field. It also provides insights on how to design tests and equipment to better represent PI field performance.
Looking Deep Beyond the Wellbore: Mid-Field Hydraulic Fracture Diagnostic
Authors: Stolyarov Sergey , Cazeneuve Eduardo , Sabaa Karim , Kotov Sergey 
Published: April 2018

Abstract
Understanding the stimulated reservoir volume and mapping hydraulic fractures away from the wellbore remains one of the biggest challenges in unconventional plays development. Currently available production logging and tracer technologies have shallow depths of investigation—only a few inches beyond the wellbore. Far-field microseismic mapping offers an image of micro-earthquakes that are caused by shear slippage during a hydraulic fracture treatment. Although the location of the associated microseismic events enables spatial mapping of the stimulated rock volume, particularly its orientation and growth characteristics, the microseismic deformation does not provide direct information about hydraulic fracture effectiveness.
The latest improvement in deep shear wave imaging processing (DSWI) provides a visual representation of geological features up to 100 feet from the wellbore. DSWI nicely fills the resolution space between conventional near-wellbore diagnostic technology and far-field microseismic mapping. The shear wave azimuthal sensitivity enables estimation of the hydraulic fracture geometry away from the wellbore. It also provides direct visualization of the actual reservoir volume that has been stimulated in the mid-field region with the extension of hundreds feet from the wellbore.
This paper presents a case study of the post-hydraulic fracture diagnostic in a shale reservoir using deep shear wave imaging technology. The information derived from the pre- and post-hydraulic fracture imaging enables a better understanding of the stimulation treatment effectiveness and fracture propagation away from the wellbore. This imaging can also be used for the completion optimization of the new drilled wells, as well as for the identification of previously unstimulated zones for re-fracturing.
The accuracy and credibility of the DSWI hydraulic fracture diagnostic was confirmed by running a cross-dipole acoustic log in a well with high water cut. Radioactive material present in the produced water caused up to 150 API increase in the gamma ray activity due to precipitation associated with the pressure drop in a hydraulic fracture. The study showed that the lateral intervals with a substantial increase in gamma ray activity matched the hydraulic fracture locations identified by the DSWI process.
These case histories highlight the value of the information obtained from the DSWI to enhance the fracture optimization, to improve ultimate recovery, and to reduce overall operational cost.
Quick Estimating Pipeline Walking Anchor Force - It is Much Less Than the Full-Length Mobilization
Authors: Carneiro Daniel 
Published: April 2018

Abstract
An analytical methodology for estimating walking anchor force is presented. Currently, anchor force calculation requires substantial FEA which is not compatible with early phase design schedules. At such stage, anchor force is typically assumed to correspond to full pipeline length mobilization. This is very conservative, in many cases by an order of magnitude, and can hence mislead important early design decisions.
The force on a walking anchor increases with cycles of pipeline operation, eventually approaching an asymptotic limit value, often of the order of 1 MN. Robustly identifying this limit requires extensive FEA, incorporating detailed bathymetry, simulating tens to hundreds of operational cycles, and covering numerous sensitivities to input parameters, which often yield counterintuitive results. The proposed analytical method does not require repetitive calculations. It derives the limit value straightforwardly, based on fundamental principles, and has been implemented in a spreadsheet.
Providing immediate results, it permits quick assessment of the effects of many parameters such as soil resistance, operating loads, as well as the number and location of global buckles, on the system's ultimate response. Results are shown to agree very well with extensive FEA results, and yield required anchor loads which are much lower than the full-length mobilization approach. Having such results early in design allows better informed decisions, for example making end anchors viable, and thus avoiding much more complicated mid-line ones. Pipeline ends can be anchored by either adopting piled foundations or by connecting them to a separate anchor pile. Mid-line anchors mobilize lower loads, however in most cases require additional attachments or structures, which bring additional concerns in terms of through-life integrity, and installation cost, safety and schedule risks.
The proposed tool permits proper estimation of anchor loads at early design stages, and can make otherwise too expensive concepts viable. Its capability of quickly assessing multiple sensitivity cases also allows early identification of the relevant aspects to be tackled later in the project, in a value engineering approach.
Insight into Pipeline On-bottom Stability, DNV RP F109 and DNVGL RP 114
Authors: Thusyanthan N. I. , Jegandan S. 
Published: April 2018

Abstract
On-bottom stability of pipeline is a one of the key factors that affects the design and installation methodology of subsea pipelines. With ever increasing demand for energy, the need for new pipelines in harsher seabed conditions is on the rise and hence accurate on-bottom stability assessment of pipelines plays a vital role in cost effective pipeline design and ensures the long-term integrity pipelines. The recommended guideline DNV RP F109, "On-bottom stability of assessment of submarine pipelines" and American Gas Association/Pipeline Research Council International (AGA/PRCI) stability methodology are the most commonly followed guidelines in the industry for the on-bottom stability assessment. This paper provides insight into on bottom stability assessment, effect of soil classification system on on-bottom stability assessments and compares results from DNV RP F109 and AGA/PRCI methods. It is often assumed that the seabed is stable while undertaking pipeline on-bottom stability of pipelines. However, this may not be case due to seabed mobility and wave induced liquefaction, especially in sandy seabeds. Therefore, insight into how to evaluate the seabed mobility and wave induced seabed liquefaction is provided in this paper. Results from parametric study of on-bottom stability of a typical pipeline are presented to highlight the key influence of seabed classification on the on-bottom stability assessment results. Seabed mobility and wave induced liquefactioin results are presented in graphical form such that they can be assessed quickly for Front End Engineering Designs (FEED). Comparison of soil models from newly released DNVGL RP F114 with that in DNV RP F109 is also presented and discussed. The results presented in this paper are a vital source of information for all pipeline design engineers.
Optimized Mixed Refrigerant System Using Advanced Vessel Economizer
Authors: Kim Taeyun , Park Hyunki , Kim Chulwoo , Oh Youngseok , Lee Donghun , Kim Seunghyuk , Min Joonho 
Published: April 2018

Abstract
The purpose of this paper is to demonstrate the following features of the Advanced Vessel Economizer, derived from the principle of the Advanced Vessel Economizer and comparison with the Conventional Vessel Economizer. Equipment which needs a host refrigerant process.Maintains the characteristics of the host process.Improves efficiency of host process.Is able to be applied not only to marine, onshore and offshore, but also to industrial refrigerant processes and household appliances.Is able to be applied not only to the plant to be built in the future, but also to the plant that is currently being operated thanks to the simple configuration of this technology.
Two case studies were conducted for this purpose:
The first case study is a comparison of the newly developed process with the commercialized process. Since the Advanced Vessel Economizer is not a process but equipment, it requires a process to be a host therefore the one of commercialized SMR process [3] has been selected and the Advanced Vessel Economizer is applied for optimization. As a result of this, the newly developed process shows that it not only improves the performance of the host process [3] by about 7.4%, but also maintains the properties of the host process.
The second case study demonstrates efficiency of the newly developed process by comparing the commercialized BOG reliquefaction processes and the offshore liquefaction processes (see table below) to show the possibility of commercialization.
It is concluded that the BOG SMR process [2] was the most efficient among BOG reliquefaction processes and LNG SMR-II process [3] was the most efficient in offshore liquefaction processes. However, the newly developed process showed about 7% higher efficiency than these two processes. Also, thanks to the small number of equipment which is similar to LNG SMR process [3] and BOG SMR process [2], a low capital cost, a compact configuration in terms of layout and simple operating and control can be expected. That is, the newly developed refrigerant system using Advanced Vessel Economizer can be commercially attractive.
Through two case studies, the features of the Advanced Vessel Economizer described above are demonstrated as well as the performance of the newly developed process using the Advanced Vessel Economizer.
Mooring Chain Wear Experiments and Findings
Authors: Jayasinghe Kanishka , Potts Andrew , Kilner Andrew , Melchers Rob 
Published: April 2018

Abstract
Whilst mooring chain design practice has traditionally considered wear and corrosion together under a single allowance for material loss, the two phenomena are influenced by different factors whereby they may act synergistically to accelerate degradation rates or act completely independently. As chain wear has been attributed to both the acceleration of corrosion-related degradation and the cause of chain failures and early mooring repairs by itself, it was investigated as part of the SCORCH JIP.
An extensive literature review and meta-analysis of wear research was carried out in order to determine a framework for assessing the wear of mooring chains. The literature review found that the phenomenon of wear in general and mooring chain wear in particularly was not well understood, with little agreement as to a general analytical model for wear prediction. The particular wear regimes under which mooring chain wear occurs was identified and a critical analysis of available data on mooring chain wear was carried out where it was determined that experimental conditions were likely to have been outside of the bounds of validity for what would be experienced in the field. A generic formulation for chain wear was presented, where the amount of wear is proportional to the work done at the interlink contact due to the relative sliding of the chain links.
Supplementary to the literature review, a series of wear tests of full-scale mooring chain links were carried out under varying load conditions for different grades of chain. These tests were used to determine empirical coefficients for the prediction of chain wear. A model for wear prediction was presented based on the position of the chain in the mooring line, the tension in the line and the relative motion of the chain links.
The evolution of the contact surface between chain links was modelled using 3D geometries of idealized chain links in order to determine a relationship between the volume of worn metallic area and the depth of wear, which can be more easily measured in-service.
Repeat AUV MBES Surveys for Deepwater Seafloor Change Detection
Authors: Haneberg William C. 
Published: April 2018

Abstract
Repeated multibeam echosounder (MBES) surveys conducted using autonomous underwater vehicles (AUVs) have the potential to document the magnitude and areal extent of seafloor changes associated with both human and natural causes, including seafloor subsidence, fault or slope movements, fluid expulsion, volcanism, and biological activity. If AUV survey design does not consider the practical limits to change detection and include best practices to minimize noise, however, the results may be ambiguous or even useless. Using a series of simulations combining real bathymetric digital elevation models (DEMs) with idealized perturbations representing seafloor subsidence and faulting, this paper examines limits to seafloor change detection using repeat MBES surveys in terms of the standard deviation of the noise in the surveys. In general, the magnitude of vertical change between surveys should be greater than the standard deviation of the noise (also known as uncertainty or error) in each of the surveys compared in order reliably recognize seafloor change. Filtering can suppress noise and recover the real seafloor change, possibly even if the magnitude of the change is less than the standard deviation of the noise. Based upon the simulations in this paper, filtering is more effective for broad features like subsidence bowls than localized features like faults even if the amount of vertical change is identical. A probabilistic threshold based upon the standard deviation of the noise appears to be less useful than filtering in the simulations undertaken for this paper.
A New Practical Water Injection System in Offshore Fields
Authors: Martinez V. , Ascencio F. 
Published: April 2018

Abstract
This work proposes a new system to perform the water injection for pressure maintenance in offshore fields without the need of installing additional facilities for water treatment. The main objective is to directly communicate an active aquifer with the depleted reservoir through existing vertical or deviated wells, of which trajectories enable the completion in both formations. It takes advantage of the pressure support from the aquifer, thus, avoiding the requirement of additional infrastructure. It is an artificial crossflow between two formations, where the water-injection rates will basically depend on two parameters: the formations flow capacity and the pressure difference between the aquifer and the reservoir. The injectivity indexes of the communicating wells can be determined using a combination of pressure drop equations. Finally, an example of possible application in an offshore field is presented; the analysis indicates that its implementation would carry many benefits in a short period of time.
Field Life Extension and Integrity Management in Campos Basin
Authors: Müller D. T. , Nogueira D. C. , Gonzalez E. C. , Nicolosi E R. , Dutra E. S. S. , Campello G. C. , Muniz T. J. C. , Capella M. M. 
Published: April 2018

The integrity management of Campos Basin platforms, subsea systems and wells and its risks control due to ageing process are key priorities for HSE. With this awareness, Petrobras is implementing initiatives to improve the production viability of mature fields and to extend the life of current facilities.
This paper will describe some of these initiatives, which include: carrying out platforms maintenance campaigns using UMS (Units for Maintenance and Safety); subsea facilities and platforms life extension studies; well integrity evaluations; compliance with the new regulatory aspects of ANP (Brazilian National Petroleum, Gas and Biofuels Agency); development of business decision-making methodology based on break-even point; implementation of decommissioning projects of non-operating structures that have reached their technical and economic limit. As an example, it will be presented the extension of the concession contracts for the Marlim and Voador fields until 2052, which were originally due to expire in 2025.