bluuebunny/crossref_metadata_2025_split huggingface dataset:
Diverless Support Systems for an Improved Rigid/Flexible Risers Competitivity on Pre-Salt Fields
Authors: Reis B. P. , Brito R. M. , Ferreira C. V. , Ferreira R. P. , Gonzaga R. R. , Reckziegel G. , Medeiros J. G. , Mello F. B. , Aires G. D. , Lima J. T. 
Published: April 2024

Abstract
Riser pull-in is a time-consuming activity. It is required to start the Floating Unit Production (FPU) and its ramp-up. In additional, conventional systems are dedicated to install rigid riser or flexible riser in the Floating Production Storage and Offloading (FPSO). This article presents the challenges overcome and ongoing on developing the riser & hull interface system for the pre-salt fields to speed up the riser connection and to provide flexibility for the riser technology a posteriori of the design system.
This work details the functionality, design, manufacturing, and pull-in activities of two different systems developed for pre-salt fields: (i) the Diverless Bellmouth with hydraulic actuators (BSDL-SI), intended for flexible riser or umbilical; (ii) and the Unified Diverless Support Tube (TSUDL), a device with the capability to support either flexible or rigid risers, with reduced dependance on shallow diving operations, allowing a broader competitivity on the riser technology solution and therefore more possibilities for the subsea layout design.
Improving a diver-assisted equipment to a diverless design significantly increases its complexity by means of enhanced mechanisms, hydraulic actuation, and monitoring systems. The authors present, for both systems BSDL-SI and TSUDL, the challenges overcome for the different project phases: design, manufacturing, and pull-in activities.
It is presented pull-in activities comparison between the developed and standard support riser & hull interface systems to illustrate the efficiency improvement in the operations with using of those new technologies. They enable to anticipate the production and to reduce the overall project cost and greenhouses gases emissions.
Moreover, the diving assisted activity is one of the riskiest to the professional in the oil and gas industry. Therefore, by eliminating these activities it will make the project of oil and gas industry safer.
These new concepts of diverless riser supports are disruptive on the offshore industry, as they consider control & monitoring by the FPU, although using field proven components. Considering this strategy, a new approach to the market is being used to reduce the implementation and schedule risks, such as an early engagement during the design phase with the suppliers, leading to a new concept of technology licensing and pre-qualification that will be presented on this paper.
Pile Driving Predictions for Pile Driving from Floating Installation Vessels
Authors: Verbeek Gerald E. , van Dorp Rob , Bielefeld Marcel , Buitenhuis Rutger 
Published: April 2024

Abstract
A common approach for offshore windfarms is the installation of the turbine on top of a steel monopile that is driven into the seabed with a vibratory hammer. The use of that hammer type has distinct advantages over that of an impact hammer. First, the installation time is shorter, and secondly, during the installation the vibratory hammer and the pile are both hanging from the winch of the onboard crane, which provides the option to redo the installation. And with the availability of reliable simulation software for pile driving with a vibratory hammer, with which the appropriate hammer size can be determined and optimized, the installation process is now a routine activity. But as windfarms are installed in increasingly deeper water, the size of the monopiles and thus their weights are increasing. As a result, one of the advantages of vibratory driving, i.e. that the pile is hanging from the winch, is also creating a problem, especially when the installation is done from a floating installation vessel. In that case it is essential that a site specific or even a pile specific installation protocol is developed, with which the target penetration depth can be achieved. This paper will describe the process of developing such an installation protocol and illustrate the process through a generic example.
Bonga North Story: Beyond 1 Billion Barrels – Driving Growth with Subsea Tiebacks in Deepwater Nigeria
Authors: Adegoke Areje , Ayenor Gary , Nnoaham Iyke , Okwuosah Steve , Osadebe Olisaemeka 
Published: April 2024

Abstract
The Bonga North (BN) project is a greenfield oil development located in the Gulf of Guinea, approximately 130km offshore, in water depths ranging from 900m to 1300m. A Field Development Plan proposing a standalone Floating Production Storage and Offloading (FPSO) to develop the field was proposed but not supported due to a misalignment in the allowable number of FPSOs in the Oil Mining License (OML) 118 block. The block has an existing FPSO with a 20-year design life that ends in 2025 and an oil capacity of 220 Mbopd but has come off the initial production plateau and is producing below capacity, with further decline in production anticipated. This paper discusses the journey of the Bonga North project, highlighting the challenges and resolution strategies in a constantly changing environment.
Post the demonstration of the feasibility of a 10 to 15-year extension of the design life of the Bonga Main (BM) FPSO, flow assurance studies confirmed the feasibility of an 18km tie-back of the Bonga North fluids. The Bonga North concept was then revised from a standalone FPSO to a tie-back to the Bonga Main FPSO in a risk-based, competitive, and scalable approach. As a result, the Bonga North project was tranched to take advantage of the available ullage in the Bonga Main FPSO. The first tranche of development initially consists of 7 producer-injector well pairs and associated subsea infrastructure to keep the FPSO full. Further subsurface studies incorporating learnings from recent drilling results from the analogous Bonga Main field, including improved understanding of reservoir behaviours, resulted in a BN Tranche-1 development that was not optimal to fill the ullage in the FPSO. Consequently, a study was initiated to accelerate some of BN Tranche-2 wells, while simultaneously integrating design flexibility and robustness during Front End Engineering Design (FEED) and incorporating the same within Invitation to Tender (ITT) as an optional scope. This strategy optimized field development, addressed schedule issues, and showcased the benefits of adaptable design and execution.
Bonga North Tr1 has the potential to add over 100Kbopd to the Bonga Main FPSO. The project execution is via three Engineering, Procurement, and Construction (EPC) contracts and a Wells Drilling and Completion Contract. The P50 FID date is in Q3 2024, however, the project team is working assiduously to deliver FID in Q2 2024. In accordance with proactively meeting the requirements of the Production Sharing Contract (PSC), the Project team has been engaging the concessionaire and the regulators, in a collaborative manner. Issues resulting from macro-economic perspectives and challenges, such as inflation, supply chain disruptions, supply constraints, and elevated input costs from the tenderers, are being timely resolved.
This paper is part of a Mega Project series at OTC 2024, and the other papers are listed in the references.
Global Performance and Structural Digital Twins for a Floating Offshore Wind Turbine
Authors: Lim H.-J. , Koo B. , Choi S. , Kim H. , Jang H. , Sablok A. 
Published: April 2024

Abstract
The design and maintenance of Floating Offshore Wind Turbine (FOWT) platforms demand accurate global performance and structural analysis. Traditional frequency domain approaches fall short due to strong non-linear coupling among the turbine, tower, and substructure. Time domain analysis offers superior accuracy but requires significant time and computational resources. This paper introduces novel response-based time-domain global performance and structural analysis methodologies for digital twin applications.
The approach involves using Finite Element Analysis to derive stress transfer functions for various load components, including wave, wind, current, mooring, cable, turbine operating, and floater motion-induced loads. Load components are synthesized with environment and platform responses, and total stress time history is processed at each location. This methodology enables efficient calculation of structural strength, consumed fatigue life, and prediction of remaining fatigue life. The approach allows for simulation of the entire service life responses of a FOWT during the design phase and creation of digital twins.
Comprehensive prediction analysis during the design phase accurately estimates structural strength, fatigue life, and critical locations under various load cases. Real-time strength and fatigue analyses during the operating phase using digital twin models can be compared with predicted results, providing quick structural strength and fatigue damage assessments.
The present methodology considers all non-linear loads without simplification, ensuring a comprehensive load mapping and synthesizing of stresses. This approach contributes to the efficiency and accuracy of digital twin models and asset integrity applications for FOWT. The presented method serves as a valuable tool for both new design and ongoing monitoring, offering quick and precise structural strength and fatigue assessments.
New FPSO for Marlim and Voador Fields Revitalization Project
Authors: de Oliveira C. A. M. , de Padua M. M. , Romeiro C. L. , Araujo D. P. , de Araujo R. S. 
Published: April 2024

Abstract
The purpose of this paper is to present a general overview of the new FPSO for Marlim and Voador Fields Revitalization Project, its features, challenges, and main achievements so far. The project considers two FPSO, Anna Nery and Anita Garibaldi, designed to manage a large amount of liquids and with specific characteristics, such as settling tanks as a separation stage and the biggest water injection and produced water treatment plants available in Petrobras’ chartered fleet nowadays. The paper will explore all the challenges faced in the project, starting with the bidding process phase, passing through the construction and integration which occurred during COVID-19 pandemic, until reaching the first oil milestone. The conclusions are toward the success of the project making the two units available to start the production, as a relevant milestone of the Marlim and Voador fields revitalization project.
Sururu Central: Appraisal and Development Plan for a Marginal Presalt Reservoir
Authors: Azevedo T. E. S. , Hayashi L. M. , Leal R. R. S. , Martins P. H. A. , Mello V. C. , Navarini J. P. , Pinheiro N. C. , Pinho S. P. G. , Siqueira M. E. A. 
Published: April 2024

Abstract
This paper presents a multidisciplinary view of the evolution in the concept of a development project for the central area of Sururu and the method applied to address the challenges and propose solutions for the project in progress.
The central area of Sururu reservoir presents distinct characteristics from typical Brazilian Presalt fields, with low permeabilities despite of high porosity. This context brings challenges to define the best production development plan for the area, since its reservoir features, with low productivities, make conventional Presalt development architectures not suitable.
To support the production development strategy, an extensive but budget-oriented appraisal plan was carried out, including an early production system connecting one well to an existing Floating Production Storage and Offloading (FPSO). This data acquisition effort was extremely important to enable an evaluation of the long-term productivity as well as a better understanding and dynamic characterization of the reservoir.
As a natural outcome of this comprehensive appraisal plan, the project base case has undergone drastic conceptual changes during its evolution, from a first concept including a stand-alone Floating Production Unit (FPU) to drain the area, to the current production strategy, comprising a reduced number of wells to be connected through a long tie-back to an infrastructure already installed in the area.
The current development solution comprises a manifold with four production wells connected to it and a subsea Multiphase Pump (MPP) to lift the fluids. To improve reservoir management in this shared production configuration and allow production allocation, one Multiphase Flow Meter (MPFM) for each production well will be included in the manifold. The drainage system also contains a water injection well to support the reservoir pressure, in a reversed five-spot configuration.
Gathering the wells, flowrates at a manifolded system are higher than conventional satellite configuration and contribute to reduce some flow assurance risks. Moreover, a Hydrate Mitigation Cross-Over (HMXO) equipment allowing the connection between service and production lines at the riser base will be installed to reduce hydrate issues.
The low productivity and the decreasing reservoir pressure mean that artificial lift is mandatory. Subsea multiphase boosting will bring an increment in production due to the favorable conditions for this type of technology and to the limitation of gas processing in the existing FPSO, which will reduce the gas available for gas lift.
The appraisal, project optimization and non-conventional technologies for the Brazilian Presalt environment have allowed Petrobras and its partners to point out a promising production development solution which reduces risks and improves economic results in a highly challenging reservoir environment.
DC/FO Subsea Control Lean Umbilical Infrastructure for CCS
Authors: Michel Ronan , Danskin Daniel , Journe Julien 
Published: April 2024

Abstract
Onshore, some industries produce large quantities of CO2, that may need to be disposed of, in a controlled manner. Offshore, some O&G fields produce high amounts of CO2, that is ideally reinjected to increase production. But at some point, the CO2 needs to be injected in a dedicated geological formation. Those reservoirs may be located very remote offshore.
CO2 w/r to Gas production from a geological reservoir, is a homogeneous product, without water and its associated risk of hydrates that may block the conduits. It can be transported over long distances (∼ 100's of km). CO2 business is not yet mature and flies only with marginal margins. Typically, the business developers want a layout that can start with 1 well to kick-off the initial opportunity, and that can scale to 10's of wells as the business develops or as the reservoir gets filled. The initial CAPEX shall be as low as possible. The expansion plan may vary, and the design shall be flexible. As the distance increases, as the system needs to be expandable and as the cost needs to be reduced, the legacy electro-hydraulic subsea control may be superseded by All-Electric well-heads and by lean subsea control infrastructure such as the DC/FO.
Regulators may require reservoir monitoring solution, to control potential caprock leakage or for injected CO2 plume expansion to unplanned areas. These monitoring solutions shall be capable of detecting leakage events, shall be cost effective and shall be in-service and thus reliable over the lifetime of the reservoir.
The DC/FO infrastructure when combined with DAS, offers the leanest and most flexible infrastructure to distribute power, coms and ASN Distributed Acoustic Sensing (DAS) fiber sensing applications (in-well monitoring, assets integrity, reservoir monitoring, pipe monitoring, etc.) to monitor the injection in CCS wells and to protect the assets from external aggression.
DC/FO has already been successfully deployed on several North Sea fields, for either Oil and Gas production or for Carbon Capture and Storage (CCS) systems.
Offshore Hydrogen Production, Storage and Transportation: Which Solutions for Short Term Deployment?
Authors: Aloigi E. , De Bacco P. , Borghi D. , Solfanelli J. , Arcangeletti G. , De Rinaldis S. , Delaplace T. , Diaz O. 
Published: April 2024

Abstract
Scope of the paper is to present a portfolio of promising design solutions currently available for the hydrogen value chain offshore and identify the most promising architectures for their deployment.
Hydrogen value chain is broken down by function and then by single process unit where applicable. Comparison of different design choices (i.e centralised vs. decentralised) is provided based on the application of different Hydrogen production pathways and technologies and use of intermediate or final energy carrying methods (e.g. Liquid Organic Hydrogen Carriers, ammonia and ammonia carriers). A section is dedicated to pipeline transport offshore analyzing at high level the technology readiness also in terms of in-line subsea equipment. There are technologies or solutions at a lower readiness or in need of testing activity for confirming on a scientific basis the suitability for both Hydrogen and Offshore environment. The tests or initiatives required for gap areas are described.
In the analysis of the value chain, the "direct offshore use" for decarbonizing the shipping business is also analyzed considering the strong contribution of the sector in reaching the decarbonization target.
The analysis of the data collected through design cases application and market scouting offers a valid compass in the selection of the most suitable solution, even though, momentarily, some scenarios seem to be far from being achieved in the short term.
The paper gives a picture of how the energy transition focused on Hydrogen technologies and applied offshore is taking shape through a critical review of the data, the initiatives, the claims available along the supply chain from energy production to energy storage, transport and use. The overall conclusion is that the hydrogen value chain offshore is not only applicable but when based on lean, simple solutions, it promises to be very effective to concur to the net zero objective.
Innovative Flow Assurance-Based Asset Integrity and Risk Mitigation Strategies for High-Pressure Gas Storage and Injection System
Authors: Jain Arun , Lakshmipathy Jagan , Homaid Fahad 
Published: April 2024

Abstract
Risk of asset failure due to planned/unplanned operational upset conditions in a high volume, high pressure gas storage injection system is mitigated through rigorous simulations. Dynamic flow assurance analysis of the process parameters along with operational constraints were performed to establish safe operating envelope during depressurization.
A detailed flow assurance simulation model representing a 24" injection trunk line and 30" gas gathering manifold (GGM) was developed to calculate pressures and temperatures during depressurization. Rigorous compositional simulations were performed considering a range of pressures from 2,600 psi(G) to 5,500 psi(G) and cooldown durations (up to 24 hours) to study important factors affecting the metal temperatures during depressurization. Single sided depressurization via 4" blowdown valves was considered with the goal to depressurize the entire system to atmospheric conditions. A safe operating envelope was developed to ensure the metal transition temperature of 68°F (95°F with margin) was not violated.
The work identified operating conditions required for a safe depressurization of high volume, high pressure gas storage/gas injection system. These simulations considered system constraints that prevented fluid temperature exceeding 160°F and results from material tests that recommended maintaining the 30" section of the GGM above 95°F to avoid transition of the material behavior from ductile to brittle. These simulations indicated the cooldown duration had a considerable impact on the Joule – Thomson expansion with the system. Further, it indicated the allowable cooldown duration reduced substantially at elevated operating pressures, greater than 5,200 psi(G), the margin between the allowable and lowest temperature is less than 2°F. An empirical correlation was developed based on regression analysis to determine the material temperature for a given initial pressure and cooldown duration. In addition, stress analysis test was performed to validate the new temperature limit.
In order to eliminate any risk of brittle fracture, the West Jefferson test and Drop Weight Tear tests results recommend maintaining the GGM temperature above 95°F which is greater than the ambient temperature. This article demonstrates the requirement for a rigorous modelling procedure considering all constraints and the need for establishing an integrated approach for the safe operation of the system. This work allows the operator to identify key parameters to consider while performing depressurization and help maintain the system integrity
Applications, Results, and Lessons Learned From Using Roller Reamers in Hard, Abrasive Formations – The FORGE Project Application
Authors: Almanza E. , Morrison G. , England K. , McLennan J. 
Published: April 2024

Abstract
The expanding geothermal energy market faces unique drilling challenges such as long intervals in hard, abrasive igneous or metamorphic formations at high temperatures. In some cases, drilling is further complicated by significant interfacial severity or a high potential for stick-slip. Drilling at the Department of Energy's Frontier Observatory for Research in Geothermal Energy (FORGE) site in Utah has provided an opportunity for improving drilling performance and reducing dysfunction in a relatively homogeneous granitoid.
Activity at this field laboratory has included running and evaluating roller reamers while drilling multiple vertical monitoring wells and two, 65º laterals in high-strength granite at temperatures more than 400ºF. Reamers were run in the bottomhole assemblies (BHAs) of one of the vertical wells as well as in the two deviated wells with vibrational sensors in the drill bits and BHA bodies. Although most drilling experience qualitatively supports the beneficial use of reamers as a mitigation tool, the data collected during this project provided field-based validation and evidence of the merits of using roller reamers in a hard rock environment.
A significant amount of data were collected from downhole measurements during the drilling of the production Well 16B(78)-32, enabling a detailed analysis of challenges faced by the reamers and the benefits obtained from their use in the drillstring. While drilling Well 16B(78)-32, downhole drilling parameters were collected continuously at the bit and in the BHAs. This supplemented standard electronic data and extensive logging operations. Vibration information was collected routinely while drilling this well, enabling detailed analyses for developing recommendations to capitalize on the lessons learned during the operations.
This paper includes previous experience with roller reamers at Well 16A(78)-32 and Well 78B-32 in the same area and provides lessons learned based on reamer use in these wells.