bluuebunny/crossref_metadata_2025_split huggingface dataset:
Forearc Crustal Structure of Ecuador Revealed by Gravity and Aeromagnetic Anomalies and Their Geodynamic Implications
Authors: Aizprua Carlos , Witt C. , Brönner M. , Johansen S. E. , Barba D. , Hernandez M. J. 
Published: November 2020

AbstractAlong the Western Cordillera of Ecuador, fault-bounded ophiolites derived from the Late Cretaceous Caribbean Large Igneous Province (CLIP) have provided key petrotectonic indicators that outline the nature and the mechanism of continental growth in this region. However, most of the forearc basement across Western Ecuador is buried under sediments impairing its crustal structure understanding. Here, we propose a first crustal model throughout the spectral analysis of gravity and aeromagnetic data, constrained by observations made both at the surface and at the subsurface. Three main geophysical domains, within the North Andean Sliver in Western Ecuador, have been defined based on spectral analysis and augmented by 2D forward models. An outer domain, characterized by magnetic anomalies associated with mafic rocks, coincides with evidence of a split intraoceanic arc system. An inner domain is governed by long-wavelength mid to deep crust-sourced gravity and magnetic anomalies possibly evidencing the root of a paleoisland arc and the residuum of a partial melting event with subsequent associated serpentinization, the latest possibly associated with an obduction process during the middle Eocene-Oligocene. In addition, our model supports the presence of a lithospheric vertical tear fault, herein the southern suture domain, inherited from an oblique arc-continent interaction. Our interpretation also brings new insights and constraints on the early geodynamic evolution of the Ecuadorian forearc and provides evidence on the structural style and preservation potential of the forearc basement, most likely the roots of a mature island arc built within an oceanic plateau.
Alternative Chemistries for H2S Scavenging – Total Feedback
Authors: Baraka-Lokmane Salima , Nwankwo Chidiebere , Hitta Jérôme , Atherton Lee 
Published: November 2020

Abstract
Hydrogen sulphide (H2S) is naturally occurring in many oil and gas production streams. H2S scavengers are used as additives to reduce the concentration of H2S gas in order to meet export gas/crude specification or for mechanical integrity requirement. Most Total installations today use conventional chemicals such as monomethyl amine (MMA) and monoethanolamine (MEA) triazines for H2S removal. According to Total affiliates, deposit formations have been observed when triazine based scavengers are used. In this paper alternative chemistries for H2S scavenging are assessed. Six H2S scavengers have been evaluated, these are: Methylene bis-Oxazolidine (MBO), Ehylenedioxy Dimethanol (EDDM), 2-Ethyl Zinc Salt, Glyoxal, Hemiacetal and MEA Triazine. For the evaluation of H2S scavenger's efficiency, an experimental method has been developed.
For the selection of H2S scavengers, the following tests have been carried out: (i) evaluation of H2S scavenger efficiency in the oil and gas phase and (ii) production chemical compatibility test. The three-best performing H2S scavengers have been analysed for (i) the impact of H2S scavenger on foaming; (ii) impact of H2S scavenger on emulsion; (iii) compatibility between H2S scavenger and production water; (iv) effect of H2S on the scale inhibitor efficiency; (v) effect of H2S on the corrosion inhibitor efficiency.
Laboratory tests have shown that the three best H2S scavengers, based on the performance test, are Zinc 2-ethylhexanoate, Methylene bis-Oxazolidine (MBO) and Triazine. Methylene bis-Ozaxolidine tested on North Sea site in the multiphase and gas phase has shown preliminary good results. No impact on emulsion, foaming and corrosion were observed from the three-best H2S scavengers selected. Test performed on site with zinc-based product showed very good performance on H2S removal but impacted produced water quality. The zinc-based product formed deposits when mixed with production water therefore this H2S scavenger should not be used for scavenging H2S in the water phase. Though Triazine and MBO based scavengers increase water pH, potential scaling issues can be mitigated by scale inhibitor, however dithiazine deposits formed with the use of triazine based scavengers limits its use for H2S scavenging in oil gas installations.
An experimental method has been developed for the evaluation of H2S scavengers. Alternative scavenger chemistries have been identified. These chemistries reduce the risk of deposit formation in the H2S removal process during oil and gas production.
An Innovative Digital Solution to Support Pipe Welding Assembly Operations
Authors: Masse Thibault , Gotusso Nicolas , Feroldi Jerôme , Mailfait Thibault 
Published: November 2020

Abstract
An innovative digital solution to transform pipe fit-up operations had been developed. It relies on an algorithm providing a full batch of pipes compatibility analysis, and a smartphone app to be used in full autonomy by welding staff providing live fit-up outcomes. This results in optimized welding assembly operations.
Providing pipe-end dimensional measurement and using pipe-end identification technology, the algorithm provides a deterministic analysis of the data to accurately predict the Hi-Lo resulting from all possible pipe-end combinations and then anticipate operational constraints.
The developed app provides tailored recommendations to mitigate risks associated with Hi-Lo specification compliance (such as grouping, quarantine management or non-compatibilities identification) considering operational constraints such as quarantine capacity, welding line cycle time or even accessibility.
During welding operations, no sequencing is required. By scanning two random pipes intended to be welded together, a smartphone app provides live recommendations on the pipe rotations to respect welding requirements. The solution also includes quarantine management, displaying real-time notifications to reintroduce pipes that have been segregated due to limited compatibility.
This results in secured line pipe assembly workflow, improved weld quality and production time reduction.
Innovation lies into bringing full autonomy: in the field, the solution is a simple mobile app to be used by the existing personnel. No additional workforce on-board is required. Additionally, compared to existing solutions, the developed tool brings a deterministic analysis instead of a probabilistic one, and does not require sequencing - thus removing the need for extensive pipe handling.
The Practical Value of Workplace Diversity and Inclusion in the Oil and Gas Sector
Authors: Hamp Roland , Ryan Deborah , Carreras Patricia E. 
Published: November 2020

Abstract
Organisations have long recognised the potential for diverse teams to improve overall creativity, innovation and productivity, thereby achieving consistently better business outcomes - the so called ‘diversity bonus’. This is particularly true and relevant to the oil and gas industry, which constantly has to manage technical and economic uncertainty, major operating hazards, and continually seek business performance improvement and efficiencies, in order to operate sustainably and meet ever higher stakeholder expectations.
However, developing successful diverse teams presents practical questions and challenges, including what type of diversity will really add value to a task, how will a diverse group of people relate to and support one another, how can major innovation be delivered consistently whilst working within highly structured management systems and standards which aim to achieve a high degree of consistency and minimise failure frequency, and what is the most useful role of the manager/leader for such teams?
This paper describes diversity and inclusion in its broadest sense, and its benefits and challenges within the context of the oil and gas industry, in particular with regard to Petroleum Engineering and subsurface teams. A number of common and practical industry situations are considered, and the merits of further opportunities are discussed. The fundamental actions and behaviours that help oil and gas companies promote and establish more diverse and inclusive teams and cultures, in order to deliver outstanding results, are examined.
Application of Cemented Multi-Entry Ball-Activated Frac Sleeves in Multistage Stimulation: Fracture Modeling and Production Prediction
Authors: Bagci Suat , Stolyarov Sergey , Gomez Ricardo , Yang Junjie , Elliott Christopher 
Published: November 2020

Abstract
Plug and Perf (PnP) completions have been the most widely used multistage hydraulic fracturing methods in unconventional wells. In a PnP completion, isolation between stages is achieved by setting frac plugs inside the horizontal liner. The number of perforation clusters and perforation holes are designed using limited entry perforating techniques.
While PnP is a proven method, there are also some downsides, particularly when considering the inability to pump plugs due to changes in casing integrity and casing deformation occurring in 20-30% of horizontal wells. Casing damage has been increasingly recognized as a challenge to well integrity in active or child wells during multistage hydraulic fracturing. Casing deformation and reduction in casing inside diameter (ID) prevent the use of PnP operations due to frac plugs being unable to pass through deformed casing.
Cemented multi-entry ball-activated fracturing sleeves (ME-BAFS) allow users to imitate the limited entry effect of PnP completions while eliminating the need to deploy large OD frac plugs for each stage. The multiple entry points are activated using various-sized frac balls dropped from the surface as the stimulation treatment is pumped, eliminating the need to rig up and rig down between stages. After fracturing is complete, the frac balls either dissolve or are flowed to surface allowing production to begin immediately eliminating through-tubing intervention. The multi-entry ball-activated fracturing sleeves use graduated balls and ball seats to open as many as five sleeves per stage with a single frac ball for increased efficiency. Number of clusters and entry points are calculated based on limited entry techniques similar to PnP.
Within this study, two limited entry techniques, PnP and multi-entry sleeve systems, are evaluated using commercial fracture modeling software, and well production modeling to compare the steady-state production between PnP and multi-entry ball-activated fracturing sleeves. Hydraulic fracture modeling is also used to evaluate limited entry perforation design, perf erosion, stress shadowing, and fracture propagation.
3D Geomechanical Modeling for an Extra Deep Fractured Carbonate Reservoir, Northwest China
Authors: Chen Xiuping , Li Shuangui , Zhang Jun , Wang Shanshan , Gui Feng , Younessi Ahmadreza 
Published: November 2020

Abstract
The development well drilling for the deep carbonate reservoir in Shunbei field, located in Tarim Baisn in Northwest of China, has been challenging because of the great depth, complex lithology, highly fractured reservoirs and the stress condition of the field. Although vertical wells could mostly be drilled to over 7,000 m deep by continuous reaming, deviated well drilling turned out to be extremely challenging. These wells are associated with frequent hole instability related issues such as stuck pipe and pack off, which results in sidetracks. To help understand the different drilling behaviors in different parts of the Shunbei field, a pilot area was selected to construct a 3D geomechanical model to understand the lateral variations in stress and rock properties by integrating the spatial structural and lithology changes. A 3D geomechanical model is built using the well-based models as foundation and integrating the surface seismic interpreted surfaces, attributes and velocity volumes. Based on detailed well-centric geomechanical modeling, an understanding of the three principal stresses, pore pressure and rock mechanical properties and parameters of the formations was previously developed at the offset wells locations in Shunbei field. Rock mechanical properties, pore pressure and stresses were populated in 3D space using inverted seismic volumes and relationships developed in the well-centric models, honoring the 3D static geological and structural models. 3D geomechanical modeling is an effective method to capture the lateral variations away from the offset wells and helps to diagnose and understand the drilling problem in the complex deep carbonate reservoir.
When can Perforating, Wash and Cement PWC Reduce Abandonment Costs?
Authors: Leeson Thomas , Larsen Arne Gunnar 
Published: November 2020

Abstract
PWC is now a field proven method for restoring cemented isolation in casing annuli and has been successfully applied to casing exit repairs, zonal isolations as well as side-track and permanent abandonments. It is a viable alternative to section milling or cutting and pulling casing, with field history also demonstrating that it offers more reliable results than simple ‘perf and squeeze’. It is now accepted in many regulatory locations and is used by a large number of major operators around the world, but it is important to understand the limits of its application.
This paper focuses on illustrating the application envelope for PWC in well abandonment. It will examine the trade-off of service costs versus saved duration, highlighting where a low rig spread rate may drive a decision towards choosing an alternative conventional approach. Furthermore, the paper features and discusses the well parameters such as casing sizes, hole angle, rig capability and annulus content which are key parameters when designing a PWC operation.
Operators and Service Companies have undertaken a large portfolio of Computational Fluid Dynamic (CFD) modelling of PWC operations and more than 70 operations have been subjected to verification by cement quality logging. The paper considers the options for PWC barrier verification and shares when and how CFD and historical cement quality logs from the track record to date has been used to provide confidence in, and verification of, subsequent operations.
Alternative Abandonment Material: Bismuth
Authors: Fulks Jeff , Carragher Paul 
Published: November 2020

Abstract
Well abandonment has traditionally not been thought of as a crucial part of a well’s life, though it is as much a part of a well’s life cycle as drilling and production. As such, traditional methods of abandoning a well utilizing cement and bridge plugs are still common practice among most operators throughout the world. Recently, however, operators have been challenged to find more cost-effective ways to abandon wells without jeopardizing the sealing integrity and have begun to look for "alternative" abandonment materials. Materials such as resins have been utilized by some as an alternative, but there have not been any major new developments in well abandonment materials for nearly 100 years. Although cement, bridge plugs and resins have their benefits, there are also limitations to their sealing capabilities. Bridge plugs lack a high expansion ratio required in some wells and rely on elastomers to seal, limiting their ability to seal in damaged tubing or open hole environments. Due to the unique properties of bismuth, plugs can be achieved with an expansion ratio of 3:1 and take the shape of the environment they are being set in. Cement is porous and lacks the ability to block gasses from migrating through it while bismuth has no porosity, making it an ideal material for stoping gas migration. Resins must be squeezed into an area and can take days to fully cure before a seal is created as opposed to bismuth which flows in a a well via gravity and solidifies to create a seal in a few hours. This paper will demonstrate a new way to create gas tight seals during well abandonment, overcoming the limitations of traditional methods and reducing the operator’s liability and potential environmental impact after decommissioning has been completed.
Real Time History-Matched Models for Unconventional Well Ensures Reliable Forecasting and Rewarding Optimization
Authors: Vahedi Arman , Muruais Miguel , Hernandez Anthonny , Mills John 
Published: November 2020

Abstract
Formulating a robust and efficient production optimization and forecasting tool for unconventional oil and gas assets is a challenging task. This is mainly due to the high number of wells involved and the limited predictability of detailed individual well performance until there is sufficient production history.
Current methods to optimize and forecast production rely on type curves and surface network models, neither of which account for changes in the wellbore condition. Generally, these activities are conducted separately and are rarely fully integrated.
A solution that can automatically match real-time performance of an unconventional asset well is presented in this paper. The implemented solution replicates performance of unconventional wells using transient models. Input parameters for all models honour a given range of realistic operational conditions and are automatically regressed to match the historical performance. At a specified interval, historical production is updated in the models and regression is performed automatically to keep the multiple models updated.
This solution can address challenges related to historical well allocation given by lack of remote sensing, by coupling the well model to a network model. The use of automated regression tools to identify outliers reduces the requirement for routine engineering review, thus making forecasting for thousands of wells manageable. Having accurate well models coupled with a network model allows automatic allocation matching at separator levels and hence a calibrated network model leading to production optimization and better field management. Consequently, a robust optimization and forecasting tool for unconventional assets is achieved.
Erosion and Sand Detection Testing of a Subsea Multiphase Meter with Integrated Erosion Monitoring System
Authors: Streeton Richard , Sanchis Arnaud , Helgaker Jan Fredrik , Piotrowski Pawel 
Published: November 2020

Abstract
This paper presents results from a flow test performed by TechnipFMC (TFMC) in December 2019 at the DNVGL Materials Laboratory in Oslo. A replica subsea multiphase meter (MPM) that includes a Venturi was used firstly to calibrate an Acoustic Sand Detector (ASD) for the X-mas Tree (XT) specific geometry, and secondly to monitor the impact of sand over the life of a typical high-rate subsea gas well.
The replica subsea MPM body was built to mimic the subsea installation on a 5-inch TFMC Subsea 2.0 XT. Several sensors were then mounted on the test rig – including ASDs and Wall Thickness Monitors (WTM) on the MPM block. Phase 1 testing was conducted over a range of air velocities with various sand particle sizes and with water injection to assess ASD sensitivity. In Phase 2, high air velocity and simultaneously high sand loading were applied to evaluate the response of erosion monitoring sensors and the mechanical robustness of the system.
It was shown that the sensitivity of the ASD mounted on the MPM block was satisfactory and that furthermore, standardized calibration curves can be generated, thereby allowing a more accurate measurement of the sand mass flow rate for the specific XT geometry. The capability of WTMs placed at the meter Venturi to monitor long-term erosion was also demonstrated.
To our knowledge, such a complete flow test with sand has never been performed on a full-scale subsea MPM geometry. The knowledge produced has allowed the verification of the accuracy of CFD erosion models, ASD calibration and the potential for development of an Erosion Monitoring System (EMS) using inputs from a range of sensors integrated into a single ROV-retrievable XT mounted metering system.
Pressure and Rate Transient Analysis via Permanent Downhole Gauges – Application and Challenges at Wheatstone Field
Authors: Xia Zhi , Haynes Andrew , Ong Cheng-Sun 
Published: November 2020

Abstract
The Wheatstone gas field located in the Northern Carnarvon Basin offshore Western Australia achieved first gas in mid-2017. All seven foundation producers are equipped with permanent downhole gauges (PDHGs) for real-time pressure monitoring. Data from these gauges have been instrumental in understanding dynamic reservoir performance and reducing static uncertainties. The scope of this paper specifically covers the use of pressure and rate transient analyses (PTA and RTA) and the insights that have been gained during the first two years of production.
Significant offset distances exist between each PDHG and the reservoir. Corrections were developed to convert the gauge pressure to a reservoir datum, which primarily account for frictional and gas density changes with varying rates and temperatures within the wellbore. Other physical constraints and effects have been found to be more challenging to overcome, limiting the quality and interpretability of the pressure transients, particularly in the middle-time region. These include interference from non-reservoir pressure signals such as liquid fallback during shut-in, extremely low signal-to-noise ratios in the higher quality formations, and proximity to boundaries that render a short infinite-acting radial flow (IARF) period that could be masked by wellbore storage.
Attempts to circumvent these issues have included the use of drawdown transient analysis to complement build-ups. The step-rate test can eliminate liquid fallback entirely, which allows for better resolution of the IARF period. Rapid choke movements were also trialled to boost the reservoir response in some instances. Interpretations using the drawdown data were further verified in one producer through analysis of the buildup data acquired following a routine downhole safety valve closure, which benefitted from the trapping of condensed liquid above the closed valve. This provided the cleanest PTA data seen outside of drill stem testing during field appraisal. While successful in the example presented, no methods have yet been found to reliably increase IARF interpretability in those wells producing from the best quality sands.
Regarding RTA, the authors have found very few documented cases in the literature of applying this technique to conventional gas fields. To field-test its applicability in such an environment, evaluations of drainage volume by producer were performed and found satisfactory when compared with other estimates of gas in-place. It is hoped that a presentation and discussion of this finding will be additive to the reservoir engineering toolkit.