bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Anti-Agglomerant Can Replace MEG to Mitigate Hydrate Risk in Mature Gas Field?
Authors: Rocoulet Simon , Khiari Rym , Shobaki Hani , Arnault Rudy , Labielle Emerick , Fidel-Dufour Annie , Lesage Nicolas , Drouilly Charlotte 
Published: April 2024

In normal operation, a gas condensate field can be operated in pressure and temperature conditions where hydrates are stable. To mitigate the formation and deposition of hydrates, Mono Ethylene Glycol (MEG) is injected in the subsea flowline at high concentration (30 to 60% vol. versus water) (Yong Bai, 2019). MEG is then separated from water in the MEG Recovery Unit (MRU) and reinjected in the flowline while the water is discharged to environment or reinjected in the reservoir.
When wells are aging, the water production is increasing and consequently the MEG flow rate. The increase of the liquid holdup (Water + MEG + condensate) in the production lines leads to a pressure buildup and increases the frequency of pigging outages for liquid removal. Therefore, finding a Low Dosage Hydrate Inhibitor (LDHI) could help to lower the volume of liquid (MEG) and consequently decrease the backpressure. (Bhajan Lal, 2020). This type of additive has shown that they can bring significant benefits in terms of additional production, HSE improvements and OPEX savings. (A. Singh; 2006; Orlin Lavallie, 2009)
This study is assessing the feasibility to replace MEG injection in the production lines to prevent hydrates formation by a Low Dosage Hydrate Inhibitor (LDHI), in this study Anti-Agglomerant (AA) because the subcooling is higher than 10°C. AA does not inhibit hydrates formation but prevents their agglomeration in the condensate phase. A viscous slurry, composed of condensate and hydrates will be transported to the surface installation. These last years, chemical suppliers have developed "green" AA to limit environmental impact when discharged to environment. These products efficiency will be evaluated during the study.
Flow Assurance Applied to CO2 Transport: Challenges of Modelling CO2-Rich Systems through Production, Processing and Injection Systems
Authors: Barreto C. V. , Ramos C. S. , Bocchi G. , Trujillo J. , Pasqualette M. , Carneiro J. , Costa F. , Graciano J. 
Published: April 2024

Abstract
High CO2 content fluids present a challenge to the design and operational aspects of production and process facilities due to their particularities related to thermodynamics, hydrodynamic effects, and flow assurance issues. To address these challenges, the present work suggests an integration between different simulation tools to handle the CO2 cycle comprising production, processing, and injection systems. This paper focuses on the modeling challenges imposed by such particular fluids. Traditionally, the state variables adopted for multiphase flow are pressure and temperature, but they usually fail to model phase transitions for pure substances and mixtures with narrow phase envelopes (CO2-rich mixtures). Therefore, to deal with such scenarios, a pressure-enthalpy formulation has been developed so that gas-liquid conditions can be better analyzed. Additionally, to better understand the entire production, processing, and injection system, a parametric analysis has been carried out using the integrated framework. The pressure of the first stage separator (processing section - TOPSIDE) has been varied, leading to an impact on all aspects downstream or upstream of the separator. Results showed that the increase in the first separator pressure decreases the compressor's power requirement per barrel of equivalent oil, but it also decreases the wells production flow rate, worsening the economic performance. In this manner, with the right values, it is possible to achieve optimum oil production while respecting economic and operational constraints.
Bonga FPSO: Corrosion Management in the First Deep Water FPSO in the Gulf of Guinea – A Methodical Approach to Inspections and Fabric Maintenance
Authors: Oluwatayo Moses , Atebe Orobome , Okafor Franklin , Nebo Obumneme , Etuk Ofonmbuk , Nwaonu Stanley , Akanni Joseph , Onukwugha Peter 
Published: April 2024

Abstract
Corrosion failures contribute to high costs for oil and gas assets. This paper discusses the corrosion management approach for Bonga FPSO - the first deep water FPSO in the Gulf of Guinea. The paper details the step-by-step process utilized to control, identify, assess, prioritize, execute, and mitigate corrosion threats. This paper is one of a series of Bonga themed papers proposed for OTC 2024
The bedrock of the approach is the Corrosion Policy for the Floating Production Storage and Offloading (FPSO), whose concepts will be described in the paper. The policy describes the objective, scope, responsibilities, and performance indicators for corrosion management. A detailed corrosion risk assessment which identifies all critical components was carried out. The corrosion risk assessment feeds into the corrosion management framework, which houses the asset register, material selection report, inspection plan and fabric maintenance strategy. Continuous improvement studies are done to improve inspection methods and fabric maintenance approaches; some involve the deployment of robots to eliminate human entry in confined spaces like tanks. Furthermore, audits and lessons learned are used to update the corrosion management approach to ensure corrosion policy intent is continuously met.
This structured approach has led to sustained asset integrity, robust corrosion mitigation and top quartile fabric maintenance that has led to the safe operation of the FPSO for circa 18 years, improved asset availability that has led to the attainment of 1 billion barrels of oil production and driven deployment of next generation corrosion and fabric maintenance technologies that has provided the foundation for ongoing life extension of the FPSO for another 15 years.
This paper presents valuable corrosion management insights for an offshore production facility that promotes world-class availability, asset integrity and novel technology deployment.
Optimizing CO2 Transport and Injection for a Large-Scale CCS Demonstration Project in Korea: Flow Assurance in Repurposed Offshore Pipelines and Depleted Gas Reservoirs
Authors: Cho J. , Lee W. , Hwang S. , Tay B. L. , Sun X. , Kim J. , Lee H. 
Published: April 2024

Abstract
This study explores the feasibility of CO2 transportation and injection for Korea's 1st large-scale carbon capture and storage (CCS) project in a depleted gas reservoir in the East Sea, South Korea. In this study, the necessity of heating CO2 at the offshore platform is examined. Operating envelope of the CO2 injector in light of near-wellbore Joule-Thompson (JT) cooling and hydrate formation is also investigated. The study informs the basis of facility design to attain the CO2 injection target.
Transient thermo-hydraulic simulations using OLGA were conducted to establish the safe operating envelope and optimal injection strategy. The study considered re-using the existing flowlines, offshore platforms, and wells. Two development strategies were considered, with or without heating CO2 at the offshore platform. Two reservoir pressures were considered: early life and late life. Hydrate formation risk in flowlines, well and near-wellbore areas were assessed.
This study assesses various methods to mitigate hydrate formation in CO2 injection wells within CCS projects. Each tested concept has distinct advantages and drawbacks, emphasizing the need for optimizing transport and injection systems to minimize energy consumption during steady injection.
The primary discovery indicates that implementing an early injection strategy is crucial for preventing hydrate formation in CO2 injection wells. The study reveals that heating CO2 during the initial injection phase proves ineffective in averting near-wellbore hydrate formation, mainly due to substantial heat dissipation in the subsea flowline. Furthermore, even with heating, fluid temperatures near the sandface drop below freezing, creating favorable conditions for hydrate formation. This approach enhances the economic viability of CCS projects by eliminating the need for costly mitigation methods, rendering them more financially appealing.
This study addresses CO2 injection challenges in highly depleted reservoirs for geologic sequestration. Our systematic approach optimizes transport and injection systems, thereby improving CCS project economics and making depleted fields more attractive for CO2 storage. Our results provide valuable insights into the feasibility of large-scale CCS in depleted oil and gas reservoirs, offering cost-effective hydrate mitigation methods, supporting viable CCS solutions, and contributing to global greenhouse gas reduction efforts.
Deep Sea Minerals – Feasibility of Side-By-Side Offloading in Open Ocean
Authors: Sreenivasan Atheendra , Voogt Arjan , Taha Mohamed 
Published: April 2024

Abstract
Amid the global energy expansion, where diverse energy sources are needed to meet rising demand, minerals like nickel, cobalt, and lithium become imperative for the renewable energy supply chain. While these minerals are almost exclusively mined from land, when utilizing offshore industry expertise, these critical minerals become accessible by deep sea minerals harvesting of the seabed, where vast reserves of such minerals remain untapped. This paper highlights a test of the feasibility of side-by-side mooring for offloading such minerals in the offshore environment. The study employs frequency and time domain simulations to evaluate the operation of a two-vessel system. The setup involves a production vessel with dynamic positioning (DP) and a transport vessel moored side-by-side, connected with mooring lines and fenders. Simulations span various wave heights, periods, and directions. Critical metrics like line tensions, fender loads, and vessel motions are then contrasted against predefined criteria, pinpointing scenarios where the operation could be viable.
The simulations revealed that the primary determinant of operability is line tensions. Factors such as the direction of incident waves, wave period, and the shielding effects from the DP vessel also significantly influence outcomes. Particular care should be taken to manage the drafts of the vessels to prevent thruster impact on the transport vessel, which would elevate line loads. The DP settings of the production vessel should also be tuned to account for the vessel moored alongside.
Additionally, the paper discussed further work needed to establish guidance on the approach and departure of the transport vessel. The maneuvering characteristics of the transport vessel will be pivotal during its approach and departure, especially given the operations' remote open water location and unpredictable tug support availability as a result thereof.
Enhancing FPSO Control Systems: A Dynamic Simulation and Virtual Commissioning Approach
Authors: Badia Jordi , Calzado Sergio Juan , Vega Andrés , Nougués José M 
Published: April 2024

Abstract
In the domain of Floating Production, Storage, and Offloading (FPSO) facilities, the growing complexity of process configuration and control poses challenged in the Integrated Control and Safety Systems (ICSS) development. Traditional testing practices, such as ICSS Factory Acceptance Testing (FAT) and Site Acceptance Testing (SAT), are supplemented by the use of dynamic simulation for virtual commissioning. This paper explores the integration of a Distributed Control System (DCS) with a process simulator model, as an innovative solution to address common challenges in FPSO design and operation. The synergistic benefits include risk mitigation, optimized control logic, realistic scenario testing, reduced downtime, and validation of control system performance. Virtual commissioning enables early ICSS debugging and verification of operating procedures, and it proves particularly relevant in the offshore oil and gas operations of FPSOs, enhancing safety, efficiency, and operational effectiveness. Two case studies demonstrate the benefits of virtual commissioning in expediting and optimizing startup processes in greenfield project one if FPSO other in comparison the benefits of the first start-up of a chemical process.
Drilling Practices, New Technologies and Well Integrity in Brazilian Pre-Salt Wells: A 15 Year Review and Performance Evolution
Authors: Tomita R. A. , dos Passos A. G. L. G. , de Resende D. L. , de Lima F. M. , Weidlich M. C. , Moreira R. P. M. 
Published: April 2024

Abstract
In the past 18 years, since the first discovery, the evolution of drilling technologies and techniques applied in the development of Petrobras’ fields in Brazilian pre-salt have overcome many challenges, considering well design, drilling performance, wellhead systems, cementing and conductor installation. The improvements in terms of well integrity, as well as construction time and cost, have led to better economical outcome from this area that produces around 80% of the oil from this operator.
In the development of the Brazilian Pre-Salt, Petrobras has drilled over four hundred wells, and this long-lasting campaign and history allowed an extensive development and application of drilling technologies, equipment and techniques. This paper will summarize the historical application of some of these technologies and techniques that have been applied in the development of the Brazilian pre-salt, specifically in Petrobras fields in Santos Basin, to show the challenges involved, solutions applied, and results in terms of well integrity improvements and time reduction. The implementation of these applications permitted a time reduction of 60% on the total drilling duration.
Framework to an FPSO Digital Avatar
Authors: Affonso I. D. , Rodrigues L. T. , Queiroz J. L. , Vieira P. F. , Castelli L. C. , Moreira P. C. , Rocha A. O. , Silva A. C. , Zeilmann R. P. 
Published: April 2024

Abstract
The concept of digital twin has evolved over the years, from a product-oriented approach to an asset-oriented one. However, this shift in scope has also brought challenges and confusion for owners and stakeholders, who may have different expectations and requirements for a digital representation of their physical assets. In this paper, we propose the term 'digital avatar' to describe a digital asset that enhances the capabilities of a real asset, rather than replicating it. The ‘Digital Avatar’ can be seen as a digital extension of the asset, providing additional capabilities and insights that cannot be available in the physical realm.
Based on our experience and ongoing digital products, we constructed a framework to summarize the foundational technologies and concepts behind implementing a ‘digital avatar’ for an Oil and Gas production facility. These technologies have been categorized according to their purpose and laid out on an implementation timeline for greenfield projects. The main products we used as reference to build the Framework are also briefly presented to illustrate how this framework can support design, asset lifecycle management and performance optimization. This framework can help owners and stakeholders to align their objectives and priorities for developing and implementing digital avatars, as well as to evaluate their benefits and limitations.
Bonga Field: A Phased Development to One Billion Barrels
Authors: Olatunji Idris , Aderibigbe Olatubosun , Ogunlana Ayodeji , Gogo Oforiokuma , Umeh Nnaemeka , Bhushan Vikas , Aginah Chike , Chikezie Chima 
Published: April 2024

Abstract
Bonga field is located 120 km offshore and lies in water more than 1,000 meters deep across an area of 60 square kilometers. The hydrocarbon-bearing reservoirs are at depths of 6000 – 1000 ftss. The field was discovered in 1993 and came onstream in November 2005 as the first deepwater development project in the Gulf of Guinea It was developed with subsea wells, production manifolds and water injection terminals connected to a Floating Production, Storage and Offloading (FPSO) facility through a series of subsea flowlines and risers.
Over a period of 18 years, the field has achieved a cumulative oil production of over 1.0 billion barrels, 815 Bscf of gas export and 1.5 billion barrels of water injected through a total 39 oil producer and 36 water injector wells.
This performance is grounded in extensive early exploration & appraisal efforts and a continuous revision of the field development plan (FDP) to accommodate new opportunities and optimizations of the existing facilities as more data became available. The field took final investment decision (FID) based on an Estimated Ultimate Recovery (EUR) of 579 MMbbls in 1999. By 2019 the EUR had increased to 1300 MMbbls due to an increased Stock Tank Oil Initially in Place (STOIIP) estimate, better reservoir connectivity than expected and the appraisal of additional hydrocarbon bearing intervals.
Bonga has been developed in phases, with Phase-1 development consisting of 9 oil producers and 7 water injectors targeting five deeper and relatively better-quality reservoirs. Subsequent phases targeted shallower reservoirs and added further infill wells into the deeper reservoirs.
In 2014 the Bonga North-West (BNW) near-field opportunity, identified in the early 2000s through exploration & appraisal drilling, was developed as a subsea tie-back to the Bonga Main hub. BNW added an additional 4 oil producers and 2 water injectors to the well stock and increased the field's daily production by ca. 60 kbopd.
A key enabler of the exceptional value delivery from the Bonga field has been a robust Well, Reservoir and Facility Management Plan integrating a reservoir management strategy (water injection for pressure maintenance and sweep efficiency), surveillance and data acquisition including 4-yearly Ocean Bottom Node (OBN) 4D seismic data acquisition, vigorous well interventions, creative management of limited slots and drilling of infill wells to maximize oil production and ultimate recovery.
This paper provides an overview of the Bonga field development journey to achieving one billion barrels of oil produced, highlighting the key role of exploration & appraisal and continuous update of field development and production strategies, enabled by the application of new data, new understanding, and new technologies.
MPD Deepwater Evolution and Interinstitutional Development
Authors: Fernandes A. A. , Vanni G. S. F , Terra F. S 
Published: April 2024

Abstract
The application of MPD offshore deepwater began on early 2010s. Although the technology is used for over 60 years onshore, the deepwater environment and risk demanded a new approach. Over the last 10+ years there was noticeable evolution of usage of MPD technology and the correlated interinstitutional development among different industries players, such as IADC, IOGP, API, among others. This paper presents key aspects of the evolution of MPD application, and the correlated interinstitutional developments achieved recently. The experience of 100+ wells using MPD on deepwater scenarios, and active participation on the creation of recent relevant international documents and committees provides the authors the opportunity to present key points of the recent industry evolution. Regarding the MPD evolution, a revision of the internal and external operations, through several papers and publications allows the identification of different factors that changed over the years while applying MPD on deepwater scenarios. A description of some of the documents released by several international institutions and impacts on new deepwater MPD projects. This provides an overview of the interinstitutional correlational efforts.
MPD operations are consistently being performed in deep water well construction for +10 years. Some even may advocate it has become commonplace. Current practices widely used today were unthinkable less than 10 years ago. The use of underbalanced fluid, where the hydrostatic pressure of the fluid in the well is below the open formation pore pressure, was one of the initial milestones of the application of the technique deepwater. The DPPT, Dynamic Pore Pressure Test, where a small amount of influx is planned to enter the well permitted the construction of wells with almost inexistent operational window to be drilled on a repeated and reliable basis. The expansion of the use of MPD for well control practices is relatively new but allows safer and quicker actions on the event of an influx. New forms of MPD usage are not limited to drilling operations, with successful results completing and on workover operations. Parallel to the development of the deepwater MPD technique different institutions began the development of new MPD documents. The objective of this ongoing development is to guarantee that the proper analysis and safety on the application of MDP deepwater.
This paper will present the recent evolution of application of the MPD technology on deepwater wells and make a parallel to the interinstitutional development of the industry. The objective of this paper is to provide a clear picture of the true capabilities of the technique deepwater and different industry documents. Giving the reader a broader understanding of the past, present and future directions that the MPD usage can take.
FPSO Value Creation Portfolio Conception and Management
Authors: Brochado M. C. , Nascimento C. A. M. , Melo M. V. , Cervo R. F. C. , Manoel R. P. 
Published: April 2024

Abstract
In the beginning of 2021, Petrobras created its future vision for floating production storage and offloading (FPSO) projects and decided to create a value creation program based in the following aspects: build an interdepartmental effort (Engineering, Research & Development [R&D], and Operation), with a strategic approach through key topics, channeling resources to add value to our projects. Besides, the idea was to concentrate the innovation pipeline in a single governance, creating a discussion forum apart from projects schedule (conceptual and front-end engineering design [FEED] development). The challenges related to future projects were mapped and objectives and key performance indicators (KPIs) were defined: increase net present value (NPV) of FPSO projects and reduce human exposure to risk and greenhouse gas (GHG) emissions.
The program, currently called FPSO+, is based on a portfolio of optimization and innovation projects (incremental and disruptive) to evaluate improvements in the designs (concept and FEED phases) where key problems are mapped, and solutions are searched inside the project teams, R&D initiatives, supply chain and through industry benchmark. Challenges and the required solutions are evaluated considering an integrated future vision for FPSOs, where Engineering, R&D and Operation work together to optimize total lifecycle cost of ownership (TLCO), reduce emissions and reduce human risk exposure.
It was achieved a reduction around 16% in GHG emissions (kgCO2 e/boe, per new FPSO), 30% increase in NPV and approximately 4% reduction in man-hours exposed to risk (engineering, procurement, and construction [EPC] phase and offshore phase). These results are related to 2021 and 2022. The portfolio includes a variety of areas, from digital solutions to new processing concepts and from new coatings and non-metallic materials to design simplification. Management procedures were created for portfolio planning and execution, including a valuation guideline, new technologies risk assessment and KPIs for the teams involved. The valuation components (capital expenditure [CAPEX], operational expenditure [OPEX], GHG emissions, oil and gas production impacts) required a strategy to be obtained from solid technical data and reliable sources.