bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bonga Main Life Extension Project: An In-Situ Life Extension of an FPSO Using FAIR+ER Methodology and Digital Twin Technology as Basis for Scope Identification and Definition
Authors: Ugbelase J. , Osadebe O. , Bhat S. , Adegoke A. , Nnoaham I. , Okwuosah S. 
Published: April 2024

Abstract
Production commenced in 2005 from the Bonga Main Field, which is a Floating Production Storage and Offloading (FPSO) + subsea development situated in between 950-1500m of water depth and about 120km offshore Lagos Nigeria. The Bonga FPSO has a nominal 20-year design life and at the time it was commissioned and till date, remains the largest FPSO in Nigerian waters with a nameplate capacity of 2,000,000Bpd, production handling capacity of 225,000Bpd and export capacity of 1,000,000Bpd through a single point mooring (SPM) buoy system.
By January 2014, the Bonga Field had produced its FID promised volume of 500 million Barrels, and by February 2023 had produced 1 billion barrels. The Bonga Main Life Extension (BMLE) Project aims to extend the life of the FPSO by additional 15 years to produce the tail volumes from the field in addition to infill volumes from further developments including the Bonga North tie-back project.
To assess the requirements to extend the life of the FPSO, a well-established process known as the Focused Asset Integrity Review (FAIR) + Equipment Review (ER) Life-Extension process which brings global performance standards into the evaluation of Safety critical elements (SCE) was used to identify status and to determine required actions for life extension of the FPSO. While the initial FAIR+ER LE, Corrective Actions Workshop & Scope challenge was carried out in between October 2016 and February 2016, it was repeated between November 2019 and April 2020 and this resulted in identification of 34 sub-project scopes across Topsides, Subsea, OHRM and pipelines. Each sub-project has pre-defined trigger points which are compared with the outcomes of relevant studies and/or inspections to determine if they should be matured to execution.
Further to the aforementioned, the decision for an in-situ life extension rather than dry docking was chosen after a concept selection for a 10-year life extension period. As of December 2023 a 15-year life extension was firm for Bonga FPSO based upon the outcome of analysis of the state of integrity of the FPSO Hull, using a Digital Twin Technology while working with Vendors. This study outcome was subjected to further reviews and challenge to check it for credibility and robustness, prior to support for 15-year life extension. This paper aims to provide an overview of BMLE portfolio, scope development and maturation process, project philosophy and governance, key challenges encountered on the project, the assessment to determine the remaining Hull life and current project status. This paper is part of a Deep-water Projects Nigeria presentation under the growth theme for OTC 2024, and the other papers are listed in the references.
Intervention and Completion Landing String Qualification for HPHT Application
Authors: C. Karlapalem Lalit , Hehn Lucien , Brown Glenn , Muradov Andrei , Dighe Sourabh , Pattillo David 
Published: April 2024

Abstract
To optimize offshore intervention and completions operations, drill pipe-based riser (DPBR) designs with proprietary gas-tight, rotary-shouldered connections are being evaluated as alternatives to traditionally used casing products. This paper describes the design and development process of a DPBR including material qualification and connector qualification, which was pieced together from various applicable industry codes, such as National Association of Corrosion Engineers (NACE) MR0175, NACE TM0177, American Petroleum Institute (API) 17G, API Spec 5DP, API TR 17TR8, and ASME Boiler and Pressure Vessel Code Section IX. Wherever applicable, the more challenging and stringent requirements were chosen.
Material selection and qualification were performed to meet the NACE MR0175 requirements for Region 2. Sulfide stress cracking tests were performed on all base materials and friction welds in accordance with ANSI/NACE MR0175andNACE TM0177. Sub-scale fatigue testing was performed to determine the environmental knockdown factor and used to determine the fatigue capacity of the DPBR in the expected fluid/environmental conditions.
Finite-element analysis was used to determine the worst-case design configurations. These results were then used in full-scale physical testing with nine samples. Validation of the connector capacities was performed by make-and-break (endurance) testing, sealability testing, and cyclic (fatigue) testing with internal pressure. Limit-load testing was performed to validate the static load capacity of the connector. A qualification bridging was performed comparing the results from FEA and physical testing. An independent third party witnessed and reviewed all relevant design and qualification activities per the Bureau of Safety and Environmental Enforcement requirements for high-pressure high-temperature equipment.
Anchor Project: Lessons and Challenges From Developing 20K Rated Wells Equipment
Authors: Ross A. J. , Ramirez R. 
Published: April 2024

Abstract
20,000 psi (20k psi) technology is required for development of the Anchor asset. To deliver the 20K technology, the Anchor team undertook a world class technology development program. This paper will provide an overview of the 20K drilling, completions, intervention, and source control equipment development process for the Anchor project. The paper will touch on technical and process learnings associated with equipment development and qualification as well as the associated independent third party (I3Ps) and regulatory review processes.
A five-year equipment development and qualification process was initiated to define Anchor equipment requirements, award contracts, develop the 20K technology with partners, qualify to relevant American Petroleum Institute (API) standards including High Pressure, High Temperature (HPHT) Annexes, and work through the I3Ps and Bureau of Safety and Environmental Enforcement (BSEE) Review process as defined in NTL's 2019-G02 and 2019-G03.
Designed as the world's first fully capable 20k psi rig complete with two 20k psi Blow Out Preventer (BOP) stacks, the Deepwater Titan, commenced operations in the Gulf of Mexico (GOM) on June 1st, 2023. The first two Anchor wells have been drilled to total depth (TD) and all 20k psi completion equipment has been qualified in preparation for completions commencing end 2023. Two means of intervention, a Hydraulic Spanner Joint Assembly (HSJA) that can be interfaced with the Tubing Hanger Running Tool (THRT) or the subsea production tree and a Completion Workover Riser (CWOR), have been qualified and completed System Integration Testing (SIT). A 20K source control strategy has been developed along with the associated capping equipment.
During the equipment development process, interpretation of governing standards matured, particularly with regards to material fatigue. Similarly, regulator expectations around the I3P review process and requirements for well intervention (both planned and for a loss of containment event), also matured and required some revisions to the initial equipment development plan.
As one of the industry's leading deepwater, subsea 20k psi rated projects, the development of the 20k psi rated wells equipment for Anchor has generated considerable learnings with regards to interpretation of existing industry standards, particularly in relation to pressure cycle induced fatigue, and the navigation of the technical requirements of the regulatory review process required by NTL 2019-G02 and 2019-G03.
For clarity, the following terms are used throughout this paper. High Pressure High Temperature (HPHT) refers to equipment rated to pressures greater than 15,000 psi and/or temperatures equal to or greater than 350°F. Anchor is a high pressure project under the HPHT category. 20K refers to the Anchor project's technology development and qualification program.
Integrity Management and Condition Performance Monitoring of Shallow Water Subsea Field Development in Malaysia
Authors: Huang Farah Julieana Nasri , Hashim Muhammad Fikri , Omar Siti Aisyah 
Published: April 2024

Abstract
Managing the asset integrity of subsea field development is essential to ensure that the subsea production system delivers the design and operational requirements, and does not pose any risk to people, environment, and asset, throughout its operating life. This paper will provide an overview of the reliability and integrity management strategies that were adopted during the project design stage and highlight the optimizations that were implemented during operation stage for a shallow water subsea field development in Malaysia. The shallow water subsea field development consists of two (2) subsea wells that are tied back to a Central Processing Platform (CPP) and is capable of producing up to 200 MMscf/d. As the field is contributing around 40% of the overall gas production at the CPP, high emphasis was put on ensuring the subsea production system, along with its new technology equipment i.e. High Integrity Pressure Protection System (HIPPS) and Subsea Automated Pig Launcher (SAPL), is able to meet is availability target of 96%. The field commenced its operation in December 2012. During its initial production years, the field adopted a time-based inspection strategy where underwater inspection of the subsea production system was conducted annually. Operator then decided to change to a risk-based strategy, where inspection frequencies are prioritized and optimized by balancing the risk associated to the subsea production system to determine the inspection interval of the field. Company's internal guideline also mandates the requirement for full diagnostic and data monitoring to be conducted for the Subsea Production Control System (SPCS) installed on the Host Platform on monthly basis. With the abundance of data available from the field, the team leveraged on techno-digital ecosystem to ensure centralized data repository and established performance dashboards that have allowed us to gain valuable insights and improved collaboration between the Operation and Technical team, especially during unplanned shutdown and troubleshooting activities. Leveraging on digital platforms have enabled Operator to optimize the underwater inspection duration and enabled early detection of any system anomalies and degradations, hence preventing unplanned shutdown and preserving the subsea production system asset integrity.
Experiences from the Use of Thinner SRU Membranes on Existing Offshore Platforms
Authors: Garrote R. , Hepp R. , Banham J. , Huang X. 
Published: April 2024

Abstract
New thinner SRU (Sulfate Removal Unit) NF (Nano Filtration) membrane was developed to boost the more efficient available water productivity per treatment module for energy and space saving benefits. Two module designs have been offered to the offshore service, with one targeting a more efficient fouling control with expanded surface area, and another targeting utmost compact design to save energy and space consumption. This new technology is currently available and has been used at offshore fields since 2020. With the replacement of the new NF membranes, existing SRUs can either increase by 10 to 16% capacity without modifying the actual system or use a thicker feed spacer (34 mil vs. 26 mil), allowing for operation at lower Differential Pressures (dP) reducing Cleaning-In-Place (CIP) frequency and alleviating the hassle and downtime stress brought by fouling management. New systems can be designed with 9.1-13.7% reduction in size for the same capacity when compared to standard SRU membranes. This paper investigates the benefits achieved in the real field on thinner NF membrane installation through the analysis of fouling control, production capacity boosts and membrane longevity extension. Existing platforms where the thinner SRU membranes are in use side by side with regular membrane product were tracked for direct comparison, which reveals remarkable gaining on energy consumption, chemical reduction, and downtime control with new thinner membrane installation.
Delivery of Flexible, Reliable, and Scalable Power and Communication Network in Subsea Environment Using Power and Communications Distribution Module (PCDM)
Authors: Sen Raj , D'Arcy James , Dandy Nick , Spinola Alexandre 
Published: April 2024

Abstract
Subsea production field development is an evolving process. This paper describes subsea power and communications distribution network solutions that are designed for life of field and can be configured to meet the evolving needs of a production field. It also highlights the capabilities and limitations of such solutions to facilitate its application with the goal of minimizing capital expense and maximizing performance and reliability.
Leveraging the design and flexible configurability of deployed product, a novel design has been established to make the product suitable for brownfield applications. The product design has been reviewed and matured from three key aspects – signal analysis, hardware prototyping and communications testing. For analysis, models have been developed in tool (ORCAD) to determine the performance capability of the novel design. Hardware prototyping and API 17F Q1/Q2 tests establishes the reliability benchmark. Lab based communication bench tests provides insights on data transfer and integrity such that boundary conditions are established. Holistic requirements-based testing, based on experience of deployed product, is key to successful launching of novel design.
Early analysis revealed areas to improve the design margin when applied in novel design. Analysis also highlighted areas that can be further utilized beyond current capability of the product. Hardware prototype is built to determine the packaging in subsea modules and functional performance. Functional performance is determined using API Q1 tests and Q2 tests are executed to understand the design margin when physical stress(es) is applied. Lab based bench tests revealed communication performance and established data related specifications for the novel design. Assimilating the results has allowed the boundary conditions to be established for which the product is deemed suitable in multiple applications. Successful implementation of the product allows it to be applied in greenfield and brownfield opportunities. Novel design implementation enabled leveraging existing equipment and not require significant investments on new umbilicals in extending or tied back of production fields. It also shall allow phased introduction of well by leveraging the switching feature (controlled from Topside) in the module.
The paper discusses flexibility aspect (multiple configurations) of the product and touches upon how it is leveraged for brownfield application with a novel design. Using same building blocks of an existing product in multiple applications allows to accelerate reliability growth and benefit the industry.
Wet Christmas Tree and Control System Standardization and Interchangeability - More Than 10 years of Lessons Learned
Authors: Beppler R. V. , Rabello A. , Coelho E. J. J. , Seraco E. P. , Dendena M. , Fagundes H. 
Published: April 2024

Abstract
The scope of this work is to present the main results obtained with the interfaces standardization on Wet Christmas Trees (WCTs) and its Electrohydraulic Multiplex (EHMUX) Subsea Control Systems in pre-salt scenario, in Brazil, which completes more than 10 years since their first installation. This work also presents how much the standardization of interfaces reduced the OEM (Original Equipment Supplier) dependance, how it helped to mitigate field operational issues, and how new opportunities of broader applications are being pursued in recent projects.
The WCT-interfaces standardization has been developing in Brazil since the beginning of the 90's, where Pre-Salt WCTs is the last generation. A review of the cases where this standardization succeeded was made, allowing the demonstration of its value to mitigate suppliers’ delays, to minimize cost in projects’ implementation, to increase flexibility and to overcome o perational issues faced in the field.
Several examples of successful cases were found where standardization helped to mitigate issues in delivery schedule, changes in projects schedule and scope, and equipment failures faced in the field. Statistics have been carried out on this data showing estimated gains obtained. Additionally, for global service-only contracts with tools owned by the operator, to project-oriented services and tools availability contracts, the interchangeability level provided by the standardization became much more relevant, since it opens more alternatives for services’ contracting, from the OEM or other suppliers. Some challenges to become completely independent of OEM were identified and will be presented in this paper, as well as different scenarios where the standardization application is wider or narrower. Some opportunities were identified in recent projects, fostering new equipment suppliers, softening the transition to next equipment generation from the same supplier and enable the use of all-electrical shared actuation systems in subsea manifolds connected to WCTs from a different supplier.
Besides, this paper discusses on the main achievements obtained with the philosophy of standardization of the EHMUX-type Subsea Control System (SCS) for WCTs and subsea manifolds, also standardized for applications of the Brazilian pre-salt, which in 2023 completed 10 years since the first installation of the combination of standardized SCS and WCT, in the Sapinhoa field. The use of this standardized SCS allowed full operational interchangeability between SCS equipment and both the Brazilian pre-salt standards of WCTs and subsea manifolds, supplied by the main vendors of subsea equipment. The standardization of the SCS has also been helping to deal with operational problems that arise during the productive life of fields, minimizing the number of failures and their related costs.
Semi-Submersible FOWT with Small Mooring Footprint
Authors: Xu Qi , Ling Qi 
Published: April 2024

Abstract
A novel Vertically Moored Semisubmersible (VMS) for deep water is proposed as a small footprint and cost effective floating offshore wind turbine (FOWT). In contrast to the stiff tendons in a conventional Tension Leg Platform (TLP), VMS is a ‘soft’ system with long natural periods in its heave, pitch and roll modes and alleviates the technical difficulties and cost challenges associated with the tendons of a TLP in deep water while maintaining a small footprint to avoid interference with neighboring mooring systems and power lines. In this paper the motion response of a VMS is investigated in both frequency domain and time domain for extreme and operating sea states. It is demonstrated that a VMS meets all the relevant design requirements and has a superb redundancy compared to a spread moored system. The heave stiffness of a vertical mooring system makes it possible to tune the heave natural frequency closer to the heave cancellation frequency thus minimizing heave resonance response. A VMS also have better pitch and roll motions than a conventional spread moored semisubmersible because of the additional rotational stiffness from the vertical moorings.
Production Optimization in Bonga Deepwater Through Rigless Intervention
Authors: Okosun Augustine , Ugbor Ifeanyi , Ezeokafor Tobechukwu 
Published: April 2024

Abstract
Maximizing oil recovery and production remains paramount in Deepwater operations. This paper focuses on enhanced oil recovery and production optimization in the Bonga Deepwater project. Amidst the enduring challenges of sustained low oil prices in 2015, the team developed an optimized rigless intervention technology to manage the escalating cost associated with conventional rig base well intervention operations. Unlike traditional well interventions that often rely on expensive drilling rigs, the rigless approach provides a streamlined and economically viable alternative.
In the first quarter of 2017, the Shell Nigeria Exploration and Production Company (SNEPCo) Deepwater team undertook a groundbreaking rigless well intervention initiative in Deepwater operations. The objective was to optimize well intervention procedures and reduce operational expenditures by introducing a cost-effective rigless technological approach for Deepwater well intervention in the Bonga field. This innovative technique effectively executed tasks like electric line, slickline, and acid bullhead stimulation operations. These operations aimed to bolster production rates and curb intervention expenses while maintaining stringent process safety.
The outcome of the various well intervention campaigns was a game changer, as evidenced by the successful execution of twenty-two wells with diverse complexities and well intervention issues. These operations led to production enhancement and restoration, all achieved without process safety incidents or accidents. The implementation and subsequent adoption of this groundbreaking technology also set new records in the Deepwater environment. Notably, the deployment of the rigless technology at a water depth greater than 3281 ft emerged as an unprecedented and untested task. The technology also gave rise to other new sets of challenges. Establishing the reliability of the rigless intervention approach within the framework of the Bonga Deepwater operations posed a significant hurdle. Through detailed front-end planning, the challenges were effectively surmounted, underscoring the feasibility and potential of the rigless intervention strategy in overcoming complex well intervention operation scenarios.
This paper presents details of the successful application of the Subsea Intervention Lubricator (SIL) package in conjunction with a Vessel of Opportunity for a rigless campaign. In response to the evolving operational demands and challenges, particularly those involving thru-tubing intervention, the study also showcases the development and effective use of an Integrated Riser-Based Vessel (Q7000). This novel approach addressed the limitations of conventional systems and provided valuable knowledge to asset owners seeking advanced techniques for offshore well intervention operations.