bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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.
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

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

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

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

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

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

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

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

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

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

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.
What to Learn from a Hydrate Remediation Operation in a West-African Deep-Water Production Well?
Authors: Alborzi G. , Seal H. , Azarinezhad R. , Watson M.
Published: April 2024

Hydrates are one of the most serious issues in deepwater production systems. Remediation operations are usually time-consuming and expensive, especially if the low-cost methods using the existing infrastructure e.g. injecting thermodynamic hydrate inhibitor (THI) at the vicinity of the hydrates are not feasible or have been tried without any success. Nonetheless, in most cases, should the incident occur, the benefits of removing the blockages and resuming production outweighs the cost of intervention. There are a variety of techniques for hydrate remediation such as using chemicals, mechanical, depressurization and thermal methods. Hydrate remediation operations usually constitutes of a method whereby the ins-situ temperature or pressure conditions are changed in a way that the condition is outside hydrate formation region (HFR). Alternative methods are using THI's to shift the hydrate curves to the left so that the hydrates are dissociated at a lower pressure at the same temperature.

One of the scenarios that carries a relatively high level of hydrate blockage risk is the initial start-up of a brand new well. This work describes a hydrate blockage incident in a West African deep-water infill well tubing, and associated attempts in remediation. The remediation work included forming a team of experts to investigate the root cause of no-flow during the initial start-up, propose the feasible methods to unblock and re-establish the flow using the existing infrastructure such as methanol injection from the wellhead. However, given that methanol could not reach the depth at which the blockage(s) were formed, a Hydrate Remediation Skid (HRS) was hired from the relevant contractors, adequate system isolations were made and depressurization carried out which eventually removed the hydrates and unblocked the production tubing. There has been a number of lessons learnt from this remediation operation which can be extended to other hydrate remediation activities with minor adjustments.
Subsea Reinjection of Methane-Rich Gas: System Design and Injection Pump Testing
Authors: Hill A. C. , Gyllenhammar E. , Olderheim T. , Torres G.
Published: April 2024

Many oil and gas fields rely on gas injection for production support or disposal. However, methane gas injection in an offshore development is energy inefficient, limits throughput capacity, and requires sizeable infrastructure. Hydrocarbon transportation and processing result in pressure losses, which must be compensated for by multiple stages of compression. Subsea reinjection of methane-rich gas is a novel solution that could alleviate the downsides of the traditional topside approach. Subsea processing technologies enable the full reinjection process to occur subsea, without the gas stream having to travel to an intermediate topside facility.

The potential benefits of subsea gas reinjection are significant, and extensive study work and flow loop testing was performed to verify the technical feasibility of this approach. This paper discusses the selection of a subsea gas reinjection concept, system design, benefits, engineering challenges, and successful full-scale, low-density gas pump testing.

Subsea reinjection of methane-rich gas leverages qualified subsea processing technologies using arrangements that are flexible depending on operating conditions. The subsea gas reinjection system design incorporates high-pressure subsea separation to optimize efficiency and liquid yield, while subsea boosting pressurizes the supercritical gas. A comprehensive test campaign validated the ability to pump supercritical gas through subsea single-phase pumps, even for low-density gas applications. With subsea gas reinjection, system efficiency is increased because pressure losses are minimized, emissions are decreased, safety is improved, and flowline and host facility infrastructure can be reduced. Economics are optimized through facility debottlenecking and accelerated production.

Subsea gas reinjection is a novel, promising concept for offshore oil and gas projects. It uniquely repurposes existing technology to improve system performance while decreasing costs, greenhouse gas (GHG) emissions, and complexity. Although system designs for the subsea injection of carbon dioxide (CO2)-rich gas exist, the boosting of low-density methane-rich gas for injection is unprecedented.