bluuebunny/crossref_metadata_2025 huggingface dataset:
Prelude’s Remarkable Turbomachinery - The Story From Selection To First Drop Of LNG
Authors: Mossolly Mounir , Bustos Emmanuel , Messineo David
Published: April 2020

This is the story of the remarkable turbomachinery of the Prelude floating liquefied natural gas (FLNG) facility that was selected, designed, manufactured and extensively tested to achieve the highest levels of technical assurance, to serve what was the FLNG facility ever sanctioned in the world, a pioneering project destined to be an exemplary success.

The Prelude FLNG project is unique for its size and numerous innovations. Its large onboard turbomachinery is usually applied at this size only to onshore liquefied natural gas (LNG) plants. The technical requirements of the Prelude FLNG facility went far beyond the limits of offshore experience, with consequences on the selection and design of the onboard turbomachinery. The management of this new technical solution was successfully achieved using detailed modelling and engineering analysis, an extensive test campaign using purpose-built test beds, and the development of dedicated start-up and operating procedures.

This paper focuses on the pumping heart of this largest offshore facility ever constructed: the main refrigerant compressors and steam turbine generators, in addition to the seawater lift pumps that are used to extract seawater from a water depth of 150 meters, sustaining the main cooling capacity for the FLNG facility. The paper also mentions other sophisticated machines such as the combined boil-off gas (BOG)/end-flash gas (EFG) compressor, amongst others.

Extraordinary work has been performed to ensure that each step in the realization of the turbomachinery for Prelude FLNG was an incremental success. Proper preservations, precise and careful installations of turbomachinery in steel modules, as well as preparations for start-up during the pre-commissioning and commissioning phases are explained.
Common Gas Detector Guidelines that Result in Poor Designs
Authors: Marszal Edward M , Oulton Andrew Thomas
Published: April 2020

Fire and gas detection equipment placement has shown to be increasing in complexity over time. Over the years rules of thumb or heuristics have been developed to assist in the proper placement and optimization of the fire and gas system. Due to the judgement involved in these heuristics, the same set of "rules" can result in radically different designs depending on an individual's experience and expertise. Additionally, these heuristics can cause overall poor placement due to the fallacy that the underlying assumption is always valid.
Production Reinstatement and Facilities Enhancement Justification for a Hydrate Prone Deep Water Oil Field
Authors: Daramola Babalola , Alinnor Chidubem Martins , Orti Ngutor
Published: April 2020

This paper presents the lessons learnt during an intervention to remove a gas hydrate blockage and reinstate oil production from an oil well in Field D. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water oil field with 10 subsea production and water injection wells tied back to a floating, production, storage, and offloading (FPSO) vessel.

Field D was shut down for turnaround maintenance work during the summer of 2016. After the field was brought back online, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity.

A number of attempts were made to induce the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, and this restored oil production from the D2 well. To minimise hydrate blockage and oil production losses, the asset team completed a feasibility study to evaluate the viability of installing a second methanol umbilical and a test separator.

The hydrate clean-out intervention reinstated oil production from the D2 well, and the feasibility study suggested that installing a second methanol umbilical and a test separator are economically attractive as standalone or joint projects. It is recommended that flow assurance strategies are regularly updated as production fluids change over the lives of petroleum fields, from dry oil production to high water cut production.

This paper presents hydrate remediation steps in a producing oil field, and outlines practical methods to justify methanol umbilical capacity enhancement projects.
Prelude Turret Mooring System: A 10,000-Ton Mooring Force Challenge
Authors: Betthaeuser Francois , Mazarguil Vincent , Naciri Mamoun , Lefebvre Timothee , Masterton Stephen , Van Haaften Ewoud
Published: April 2020

The Turret Mooring System (TMS) for the Shell Prelude FLNG (Floating Liquefied Natural Gas) facility consists of a Top Mounted Internal Turret (TMIT) integrated at the bow of the FLNG hull. Permanently connected to the seabed through a dedicated mooring system, this Turret allows the FLNG facility to passively weathervane in response to prevailing weather conditions and enables transfer of fluids and utilities (in both directions) between the subsea wells and FLNG topsides. This paper describes the challenges faced during the engineering and construction of the most challenging TMS ever executed to date.

Prior to Prelude, SBM Offshore (SBM) had designed for Shell a TMS suitable for a large range of gas compositions from a portfolio of remote offshore gas fields, including North-West Australia, in water depths ranging from 165m to 1,350m, with the generic FEED vision "engineer one, build many". The Prelude TMS was finally developed with a detailed design to meet the specifics of the 250m field water depth and to remain safely on station for 25 years in cyclonic weather conditions. To achieve the robust design target, field proven solutions were revalidated for application at a greater scale, for a longer design life, harsher environment and the high reliability demands of the project. The execution strategy followed the requirements of TMS contractor direct and end Clients.

The TMS, located very close to the bow, moors the 488m long, 74m wide Prelude FLNG hull. The system will ultimately accommodate 8 production risers, although only 4 are presently installed. The mooring system design is governed by the 10,000-year storm, resulting in a weathervaning system comprising 40 bogies, 40 radial wheels and 32 lower pads transferring the load to the hull. The mooring arrangement is composed of 4 bundles of 4 lines each, with 175mm R4 chains at top and bottom, and a mid-water section of 162mm sheathed diameter steel wire rope.

Several challenges have resulted from the requirement to comply with a complex set of codes and standards, the severity of the cyclonic conditions, the record size of the FLNG hull, and from the required capacity of mooring components pushing beyond the existing industry experience base.

Lessons learned from a selection of key challenges encountered during the engineering and construction of this one of a kind TMS will be presented with a view to facilitating future developments offshore North West Australia.
Developing Environmental Performance Indicators for Early Phase Engineering of Facilities and Fields
Authors: Purse Luke
Published: April 2020

Environmental performance indicators are a tool for engineering service providers to enhance the visibility and understanding of environmental impacts amongst study teams when designing offshore facilities.

This paper presents the rationale for selecting certain indicators, and some of the challenges inherent to certain facility functions, and limitations set by various study types. It explores publicly available indicators which may be usable as benchmarks, and covers field, topside (both greenfield and brownfield) and subsea facilities.
Genetic Algorithms to Solve the Jonswap Spectra for Offshore Structure Designing
Authors: Rueda-Bayona Juan Gabriel , Guzmán Andrés
Published: April 2020

This research applied a Genetic Algorithm model to identify suitable JONSWAP spectra parameters for specific locations, solving restrictions such as the influence of bathymetry and met-ocean events that could limit the coefficient selection of the spectra. Also, this study assessed available parametrized equations of the JONSWAP spectra in order to verify their applications for easing the application of the GA model. The modeled results demonstrated the capability of the GA model to find the best alpha and gamma values of the spectra for normal and extreme sea state conditions. In addition, the assessed spectra parameterized equations evidenced limitations to represent the wave energy distribution at the study area, then, this study performed a successfully modification of one of these parameterized equations to model the proper JONSWAP spectra. According to the results was evidenced the necessity to apply numerical approaches such as Genetic Algorithms to solve wave spectra equations for offshore structure designing, and the assessing of support parameterized equations before their application because the wave loads could be wrongly estimated.
Digital Transformation through Integrated Power & Process
Authors: Lau Constantine Chuan , Mancuso Bernardo Martin , Jalal Shebin , Oguro Aislan
Published: April 2020

Integrated automation and electrical control systems are vital for project optimization, system simplicity and operational flexibility in electro-intensive O&G plants. Value of integrated systems through the life-cycle of the plant from design & engineering to construction and operation is widely understood as having a positive impact on CAPEX and OPEX as well as the reliability of operations. Digital twins of the plant and the process hold key information to maximize operational profitability and optimize asset performance. Next generation of digital-ready integrated process and power management system architectures enables digital performance management of plant-wide assets and processes. An evolving approach is the integration of power and process systems throughout the lifecycle of the plant, commencing at the plant design phase and progressing to the operational stage. The improved operational efficiency brought up by integrated power and process control systems through greater situational awareness, improved reliability, and faster troubleshooting extends the value of this integrated approach to operations & maintenance lifecycle. The comprehensive approach to power and process integration is achieved through seven value driven strategies that spans the lifecycle of a process plant.
Effective Boiled Off Gas/Fuel Gas Balance between Floating Liquefaction Facilities and Carrier Resulting in Zero Flaring During Offloading
Authors: Wong Kinfai , Hashim Rose Sapinah , Yamamoto Yosuke , Furubayashi Yugo
Published: April 2020

The interest of achieving zero flaring during Liquefied Natural Gas (LNG) offloading operation is governed by the following factors, i.e. safe operation with zero Loss of Primary Containment (LOPC), green environmental impact with lower greenhouse gas emission, maximizing the profit value of LNG, increasing the asset reliability and bringing good reputation to the company. The proper fuel gas and Boiled Off Gas (BOG) balance management between Floating LNG (FLNG) facility and LNG Carrier (LNGC) is critical during offloading operating to ensure the system reaches equilibrium and lead to zero flaring. This paper is to demonstrate the process study of identifying the potential causes of flaring during LNG offtake and the corrective measures to accomplish zero flaring without any plant capital modification. The gas flaring minimization study was based on the actual offloading operations data with multiple enhancements throughout the study. The intent is to identify the most optimum conditions that bring in the highest efficiency with the least amount of gas flaring. The outcome of the study suggests two methods which involve procedural changes during offloading operations as follows: Alteration of Boiled-of-Gas (BOG) compressor suction pressure controller set point to a higher value to accommodate additional BOG vapor accumulation in the storage tanks as temporary buffer, preventing sudden fuel gas flow surge to the fuel gas system which lead to excess flaring.Application of new offloading pattern by balancing BOG/ fuel gas flow to avoid pressure spike due to large amount of ship vapor return flow at certain LNGC tanks level.

The flaring gas minimization techniques were applied in actual LNG offloading operation in June 2019 and successfully achieved zero flaring through the collaborative effort between FLNG and LNGC. This optimization methodology is proven to provide advantages by bringing in cost recovery and maximizing the profit values of LNG production. The methodology does not involve additional capital modification and the achievement during the actual implementation can serve as benchmark study for other FLNG facilities. This paper also provides insight on the potential area of improvement opportunity to the FLNG facilities that are currently under detailed design or construction phase.
The Newly Published BSEE Guidance Documents for the Approval of HPHT Equipment, Wells, and Projects in the Gulf of Mexico
Authors: Lan Christy Michelle
Published: April 2020

The Bureau of Safety and Environmental Enforcement (BSEE) first published High Pressure/High Temperature (HPHT) regulations at 30 CFR 250.807 in 2010. Additional HPHT regulations were published in 2016. In 2019, BSEE published three (3) Notices to Lessees and Operators (NTLs) to provide clarification and guidance regarding BSEE's implementation of the regulations. The NTLs also provide recommendations, which if followed, facilitate BSEE's review and approval of HPHT equipment and well designs.

The following NTLs formalized the guidance BSEE has been providing operators through the Conceptual Plan approval process: NTL No. 2019-G03 "Guidance for Information Submissions Regarding Site Specific and Non-Site Specific HPHT Equipment Design Verification Analysis and Design Validation Testing" provides guidance on information that an operator should submit concerning material selection, design verification analysis, design validation and functional testing processes, and procedures. It also explains BSEE's recommendations on how an operator could prove that HPHT equipment is fit-for-service in the applicable HPHT environment. Lastly, it provides guidance on Independent Third Party (I3P) and Operator Expert Reviewer (OER) reviews and reports.NTL No. 2019-G02 "Guidance for Information Submissions Regarding Proposed High Pressure and/or High Temperature (HPHT) Well Design, Completion, and Intervention Operations" provides recommendations and clarifications regarding operator HPHT well design, completion, and intervention operations information submittals that, if followed, facilitate BSEE's review and approval. Additionally, it provides guidance on I3P and operator reviews and reports.NTL No. 2019-G04 "Requesting Approval to Consider External Hydrostatic Pressure Effects When Calculating Internal Pressure Containment Capability for Pressure Containing and Pressure Controlling Subsea Equipment" provides guidance regarding the information that BSEE needs to analyze an operator's alternate equipment request, pursuant to 30 CFR 250.141, seeking approval to consider external hydrostatic pressure in the design and calculation of internal pressure containment capability of subsea equipment.

The paper will focus on NTL No. 2019-G02 and NTL No. 2019-G03 (HPHT NTLs). The HPHT NTLs walk the reader through the required plans and reports an operator must submit and the voluntary plans and reports an operator may submit when requesting a review of HPHT equipment or a HPHT well design by BSEE. The HPHT NTLs describe the information BSEE requests in each plan and report in order to complete a review. They also outline the requirements for independent reviewers of HPHT equipment and well designs and provide guidance regarding report preparation and presentation. If any statement in this paper is inconsistent with the regulations or the NTLs, the regulations and NTLs govern.
How Technology Enables A Lower Cost for Subsea Tiebacks
Authors: Bacati Fabrice , Arcangeletti Giorgio , Breuskin Bruno , Giolo Riccardo , Muguerra Philippe , Radicioni Alessandro , Shaiek Sadia , Sibaud Elvire
Published: April 2020

Maximizing the use of existing topside facilities is an attractive approach to reduce project CAPEX and therefore unlock new reserves. However, as the tieback length to the host increases, technical and economic challenges arise. These include flow assurance, and costs of the umbilical and flowlines which inherently increase with length. These aspects, together with others independent from the length, such as power and space availability, have a significant impact and could result in making the project unfeasible or uneconomical.

Technologies developed in recent years, or in their final stage of qualification, play a significant role, not only in solving the technical challenges, but also in finding cost-effective configurations, either by reducing and/or staggering capital and operational expenditures or by extending reserves recoverability or also by reducing significantly the risks associated with a development.

In order to appreciate these advantages, different configurations have been outlined starting from those allowed by the conventional technologies and comparing them to the ones enabled by the new technologies. Actual advantages of each technological "bricks", considered alone or in synergies, depend on the specific projects and can be identified in a timely manner thanks to early engagement of Contractor in the architecture and associated pricing of subsea tiebacks.

The paper will present a platform of technologies, their maturity status and how they can be integrated in novel architectures in an economic manner. Such technologies include:

Boosting

Distributed and local heating

Subsea water treatment and injection

Subsea separation

Subsea chemical storage and injection

All electric control system

Local power generation
Digital Representation of an Offshore Greenfield on the Sakhalin Island Using Integrated Modeling Involving Subsea Production System
Authors: Shakirov Roman , Khaliulin Ruslan , Boyarskiy Sergey
Published: April 2020

Development of greenfield-type fields with a gas cap and oil rims on the shelf of Sakhalin Island is always associated with a high level of geological and technological risks.

To assess the investment attractiveness of the projects, it is necessary to provide an in-depth elaboration of the concept, considering many uncertainties of both the geological structure and the development strategy and the subsea construction scenarios.

A modern approach to risk assessment involves the mathematical modelling arrangement of the entire chain of technological processes from the interpretation of seismic data to the calculation of the material balance of the installations for the preparation of produced products.

Integrated modelling at the current stage of technological development allows exploring many combinations of uncertainties in terms of the impact on the final hydrocarbon production profile and, accordingly, the economic indicators of the project.

Possibilities of integrated modeling today are not limited to conceptual field design development. The result was the creation of an effective production planning tool for one of the most promising offshore fields of Sakhalin Island.
Upscaling CO2 Foam for EOR as CCUS from On- To Offshore
Authors: Alcorn Zachary Paul , Fernø Martin A. , Graue Arne
Published: April 2020

Two major challenges in CO2 enhanced oil recovery (EOR) are the high mobility of CO2 and reservoir heterogeneity. High CO2 mobility, related to the low density and viscosity of CO2, compared to in-situ fluids can cause viscous fingering, gravity override, and flow in thief zones resulting in poor reservoir sweep efficiency and low oil recoveries. Mobility control foam can improve CO2 EOR and CO2 storage potential by mitigating unfavorable CO2 properties and reducing the impact of reservoir heterogeneity. CO2 foam injection involves injecting a foaming agent (surfactant) with CO2 to generate stable foams in porous media. This work presents an incremental physical upscaling approach that moves from the pore- to core- to field-scale for characterizing and optimizing foam systems for CO2 mobility control, EOR, and CO2 storage. An additional focus was to visualize and describe in-situ fluid saturation dynamics during CO2 storage processes. We address the challenges associated with transferring CO2 foam EOR technology offshore, using lessons learned from an ongoing onshore pilot in the Permian Basin of west Texas. The aim is to encourage co-optimized CO2 EOR and long-term CO2 storage foam technology as part of carbon capture, utilization, and storage (CCUS) for offshore applications.
Iceberg Towing in Ice Conditions
Authors: Efimov Yaroslav Olegovich , Kornishin Konstantin Alexandrovich , Buzin Igor Vladimirovich , Gudoshnikov Yuri Petrovich , Nesterov Alexandre Valerievich , May Ruslan Igorevich , Sochnev Oleg Yakovlevich , Tarasov Petr Alexandrovich
Published: April 2020

This paper presents field results and analysis of iceberg towing experiments performed in the Barents and Kara Sea in 2016-2017. For the first time ever in the industry, this research was based on a complex study of the icebergs origin and properties. For that purpose prior to the trials outlet glaciers of Novaya Zemlya, Franz Josef Land and Severnaya Zemlya were examined with airborne radar that allowed to measure their thickness and to build 3D models. Satellite remote sensing data were used to derive glacier fronts position, ice surface flow velocity, changes of glacier margins, and parameters of iceberg distribution. The data on the flow rates of the main glaciers were compared with the satellite beacons equipped with GPS (ARGOS) installed on several glaciers. Empirical relationships were derived to determine the mass and geometry of icebergs based on instrumental measurements and airborne data in the Barents and Kara seas. All this information was used to estimate iceberg towing possibilities in different conditions, analyze obtained data and deeper understand the process. Influence of oscillations during the towing process was studied. For a wide range of towing speeds, drag force coefficients were determined for icebergs of various sizes and shapes. Experimental iceberg towing operations performed in ice fields during the early stages of ice formation are described. These works were conducted in October 2017 in the Kara sea. Limitations of iceberg towing under different ice conditions are determined and discussed. Technological features of towing operations within negative air temperatures and the presence of sea ice are also highlighted.
Development of Detailed Reeling Analysis for Electrically Heat Traced Flowline EHTF System
Authors: Rajaratnam Sabesan , Bedrossian Arek , Roy Alan , Lacerda Narciso , Cherkaoui Saad , Giraudbit Sonia , Gitahy Leonardo
Published: April 2020

The Electrically Heat Traced Flowline (EHTF) is characterised by a combination of high performance dry annular thermal insulation of Pipe-in-Pipe (PiP) with a restricted electrical heating capability provided by helically wound copper wires laid between the inner pipe and the insulation in the annulus. The main advantage of EHTF are: future tie-back integration, unlock marginal reserves, access to HPHT pipeline, extend field life and maximise economic recovery and reduction in chemical and energy usage operational flexibility in controlling the flowline temperature and preventing the formation of wax and hydrates in shutdown conditions. Fibre optic cables are deployed in the EHTF system to measure the temperature of the flowline.

This paper presents the development of a detailed finite element model to predict the mechanical behaviour of the helically wound cabling during reeling operations. The wires and cables were represented explicitly in the model as initially straight and then wound helically around the inner pipe with specified pre-tension. The EHTF PiP system was then cyclically deformed against a former to simulate the reeling process. A fibre optic cable (FOC) containing a local imperfection due to denting was included in the model to assess the impact of reeling process on the continued acceptability of accidentally dented FOC.

The effects of friction between the cabling and the inner pipe and insulation surfaces, the pre-tensioned helical winding process and helix pitch, and the restraint provided by the thermal insulation layer and centralizers, were all investigated. Physical tests were conducted to establish the cyclic material properties of the electrical wires and results from these tests were used to calibrate the FE model.

This paper details Subsea 7's technical expertise in modelling the highly complex behaviour of the EHTF cabling system as it experiences multiple bending cycles due to reeling. The paper highlights some important key results describing the behaviour of the wires and consequent predictions of integrity which have since been verified through full scale physical tests. The FE modelling also contributed to the insight gained regarding the overall behaviour of the system.
Underwater Intervention Drone Subsea Control System
Authors: Abicht Daniel , Torvestad Jan Christian , Solheimsnes Pål Atle , Stenevik Karl Atle
Published: April 2020

To support the digitalization trend in the industry, a higher degree of automation is required. Equinor has launched an Underwater Intervention Drone (UID) initiative backing this trend and paving the way for new, flexible and cost-efficient operation and maintenance philosophies. To cater for this technology the subsea control system infrastructure must be prepared for.

The target of the UID initiative is to develop concepts and solutions to establish cost effective technologies equally striving for standardisation of products and interfaces. The UID initiative aims to have a system approach and examine the impact on all elements of a subsea development, i.e. covering topside, umbilical, SPS, docking station and drone. This will safeguard the benefits during technology implementation and operation. As part of that, the UID control system needs to be designed under consideration of aspects such as safety, application, robustness, simplicity, standardization, cost of ownership and project execution philosophy.

While most of the main technology elements are available and proven in use there is a great potential for interface standardization by introduction of new equipment such as the Subsea Docking Station (SDS). New interfaces between well-established subsea disciplines such as subsea control and distribution, subsea production, and intervention systems will have to be handled to ensure seamless integration. This provides the possibility of open-standard solutions ensuring interoperability and interchangeability from day one.

With focus on UID control system infrastructure, this paper will present the current status of the UID initiative with focus on the UID subsea control system covering: the fundamental features of the UID control system technology and conceptthe consequences of UID technology for the design of production control systemsstatus of the UID subsea control system initiative with respect to technology maturitythe activities required to close the identified technical gapsthe implementation strategy
The Spar Platform – Transforming Deepwater Development
Authors: Sablok Anil Kumar , Weaver Tim Otis , Halkyard John Edwin
Published: April 2020

This paper reviews the evolution of spar designs, focusing on the progression of work that ultimately lead to the application of this new concept to the oil industry. This papers updates and expands on a previous paper by one of the co-authors. This paper discusses the evolution of spar designs from "classic" deep draft caisson designs to the truss spar and the cell spar. The paper discusses the reasons the spar was successful in the first place, and how its design has been tailored to varying field development requirements over the years. It discusses specific considerations in supporting risers from spars, and the unique motion characteristics in waves and currents. The simplicity of the early spar hulls is discussed. Finally, the role of key players especially the inventor Ed Horton that helped make the history of the spar a successful one is discussed.

The spar is the only successful dry tree solution for deep water production that can successfully operate in the deepest fields today and in the most severe environments. Its deep draft results in natural periods outside the range of waves, which has led to its wide acceptance for different field scenarios. The largest disadvantage of the spar is arguably the logistics of deck installation, which normally requires an offshore heavy lift. The paper discusses the research that was done on heavy topsides floatover for the spar, and the successful floatover operations both offshore and inshore.

The paper provides a unique look at the history and evolution of this concept showing how the idea originated and how the design was improved and adapted as data on its performance became available and new requirements emerged.
Integrated Production System Modelling and Optimization for Advanced EOR Application in Pre-Salt Offshore Carbonate Reservoir
Authors: Hamedi Shokrlu Yousef , Pathak Varun , Kumar Anjani , Salazar Victor
Published: April 2020

Objective/Scope

Applicability of Enhanced Oil Recovery (EOR) processes is gaining interest among offshore operators in recent years. CO2/miscible gas injection and Water Alternating Gas injection (WAG) are the most attractive EOR methods being considered by most offshore operators. Due to limitations imposed by the surface facility, any process optimization done through standalone reservoir simulation could be unreliable as the facility constraints and its effects are neglected. In order to minimize risk and reduce uncertainty, successful modelling and optimization of such projects requires integration of subsurface modelling with surface facility model.

In this work, field development and optimization of a complex offshore production system, from a Pre-Salt carbonate reservoir offshore of Brazil is studied. Different field development scenarios, including water flooding, miscible gas injection, and WAG injection, are considered. Compositional fluid model is used in order to correctly model the fluid mixing effects and miscibility. Pressure change and thermal effects are considered in all the facility equipment. The complexities of the surface network, including gas sweetening, compression, and fluid blending are included in the integrated model.

A new multi-user, multi-disciplinary Integrated Production System Modelling (IPSM) tool is used to fully-implicitly couple reservoir simulation with surface facility model. Production from the offshore asset is optimized for different development scenarios. The provided IPSM approach optimized operational schemes that were consistent with the constraints of the offshore facility. Additionally, with this new approach, all users from different disciplines were able to collaborate seamlessly, and any possible inconsistencies and discontinuities that could occur due to use of multiple decision making tools were removed.

The use of integrated production systems modelling for optimizing EOR schemes in offshore assets, particularly miscible WAG, is proved to provide more robust answers. The complexities and Uncertainties of such processes, for both reservoir and facility models, are successfully studied.
Floating Offshore Windfarm Integrated in the Subsea Field Development - Saipem Windstream Concept, Applied to a Case Study
Authors: Mauries Benjamin , Arcangeletti Giorgio , Colmard Christophe , Di Felice Annalisa , Delahaye Thierry , La Sorda Enrico , D'Amico Amerigo , Temeng Kofi-George
Published: April 2020

Oil and Gas Operators are moving active production and injection equipment onto the seabed with the aim of reducing CAPEX and/or topside space requirements. Moreover, they want to minimize new production floating facilities (e.g. through tie-back to existing FPSO/Floaters).

Given this scenario, the overall electric power needs may become an issue because of the extra power demand due to the increasing number of electric consumers placed subsea. These electric loads may include the subsea boosting (pumps or compressors) operations, pipeline heating or the typical subsea water, chemical injection and valves actuation (in the case of all electric control systems), just to mention some of potential subsea power consumers, and may exceed the existing FPSO/Floater power production capacity. A potential solution to overcome this issue consists of the deployment of wind generators combined with topside Island power generation.

Offshore wind power is indeed more and more considered for shore power supply, but also by the Oil and Gas industry with the objective of reducing the carbon footprint of their facilities. High power marine wind generators are already consolidated technologies for near coast, and today they are evolving in the short-term to floating solutions for the open sea.

Saipem has developed its own floating wind turbine solution, called Hexafloat, consisting in a pendular floating foundation made of tubular elements and connected through tendons to a counterweight. This solution is particularly cost-competitive for deepwater locations (thanks to the low mooring costs) even for harsh environmental conditions (thanks to an excellent stability), and will unlock the possibility to deploy large wind power generators far from the coastline in deep water.

The system composed by the Hexafloat base and the wind generator may be equipped with onboard back-up generation utilities to provide continuous power supply for subsea, despite wind intermittency, and to provide support to certain subsea field development services, making the assembly a kind of supporting device for the subsea field or for the FPSO.

This is the Windstream concept that is under internal development and that will be better described in the present paper through the explanation of the results achieved within a couple of case-studies analyzed.
Real-Time Composition Measurement for Fiscal, Allocation and Process Optimization
Authors: Potten Gary M , Wright Stuart F , Moreau Jon F A
Published: April 2020

The global oil industry has a large installed base of mature offshore platforms and facilities, often with declining production. A trend is to use this infrastructure to produce and process new discoveries, reducing time to production and recovery costs while extending infrastructure operating life.

However, production of new oil fields using existing infrastructure presents unique technical challenges. Accurate, repeatable and reliable measurement of produced oil and water is vital for fiscal, allocation or royalty purposes, as well as automation and control. This challenging measurement requires high-energy mixing with low power consumption and negligible pressure loss in a very small footprint.

The measurement uncertainty of net oil (oil minus water) for fiscal and allocation purposes is defined by international standards and contracts. With the increase in the use of declining facilities, a new technical challenge has emerged. To be able to accurately allocate the new fluids to the field, partner or different tax regimes they must be measured to fiscal accuracy prior to being mingled with other fluids for processing. Oil and water measurements are often performed at the output of first stage separation. This creates a challenge, as the fluids are close to the critical pressure, meaning that any pressure drop potentially results in cavitation. In addition, production pipelines are generally less than 8 inches, so any obstruction causes an undesired pressure loss or restriction.

These requirements highlighted the need for an effective, nonintrusive mixing device to enable operators to accurately measure and control the new fields being developed with today's greater capital constraints. Research was conducted, as part of a Joint Industry Project, at Imperial College in London followed by extensive computation fluid dynamics modeling to develop a conceptual design. The design was independently tested at the National Engineering Laboratory at East Kilbride, UK. The test independently verified that the design met the uncertainty performance criteria of the international API and ISO sampling standards across the wide range of water cut seen in both mature and new production. Once verified, the design was scaled for operating line sizes seen in the targeted application, and early deployment sites were identified.

The paper discusses the application envelope identified by offshore operators and the technical challenges they were seeking to solve. It follows the design process, highlighting the choices made and the results and methodology used in the independent testing to verify performance.
Johan Sverdrup: Lessons-Learned from the Field-Development of a North Sea Giant
Authors: Meling Trond Stokka , Bjarke Therese , Veire Gunnar , Bokn Trond , Thorsen Terje
Published: April 2020

In the same year that the Norwegian Continental Shelf (NCS) celebrates 50-years since the Ekofisk discovery in 1969, which in earnest established Norway as an oil and gas nation, the start-up of the Johan Sverdrup development will extend profitable oil and gas production with lower carbon emissions from the NCS for another five decades.

The third largest oil field on the NCS, after the Ekofisk and Statfjord fields, and with recoverable reserves estimated at 2.7 billion barrels of oil equivalent, Johan Sverdrup certainly has the resources to be a North Sea giant. However, being a giant is more than having the necessary resources in place, it is also about turning these resources into recoverable reserves that can be produced in a safe, profitable and – increasingly in today's context – carbon efficient way.

This paper provides a high-level summary of the experiences and lessons-learned from the development of the Johan Sverdrup field, and has the objective of serving as an introduction to the technical session papers that follow. As such, the paper aims to highlight what it took to make Johan Sverdrup a true North Sea giant, fit for the 21st century: a safe and successful execution of a mega-project, with next-generation facilities adapted to a more digital way of working, with an ambition to profitably recover more than 70% of the resources, while limiting carbon emissions from production to a minimum. The Johan Sverdrup development has set a new standard for project execution in Equinor, the paper concludes with lessons-learned of relevance for both Equinor's future project portfolio and projects globally.
Subsea High Voltage Substations for Floating Offshore Wind Applications
Authors: Eidsvik Håkon , Bekhouche Christophe
Published: April 2020

Over the last few years, the oil and gas industry has been challenged by prolonged volatile hydrocarbon prices and market instability. As a direct consequence of these challenging conditions, the industry has experienced a shift of focus to the development and application of more advanced and efficient technologies.

One of the most revolutionary subsea technological developments implemented in the latest years has been the subsea compression system installed at the Åsgard field, located offshore Norway. It has successfully been in continuous operation since September 2015. This has proven the feasibility of installing a compressor on the seabed, and at the same time verified a large number of power and control system technologies required for the control and operation of the subsea compressor. This includes large subsea transformers, power cables and terminations and high voltage wet-mate connectors, all of which are essential technologies for subsea substations for offshore wind application.

Today, the rapidly expanding offshore wind power industry could benefit from utilizing some of these high voltage power techonlogies recently qualified for subsea oil and gas processing applications. Many of the subsea power technological developments, skills and expertise gained in the oil and gas industry can be adapted for offshore wind application.

This paper presents the concept of a subsea high voltage substation applied to floating offshore wind parks. Both the system characteristics and the individual power technology features that are required to make the substation compact, efficient and reliable are emphasized. In addition, the differences and benefits of a subsea substation versus a floating substation will be highlighted.
Improve the Performance and Mitigate the Risk of Brownfield Infilling Project
Authors: Shi Hongfu , He Yifan , Luo Xianbo , Shu Xiao
Published: April 2020

The characteristics of a primary well pattern in offshore oilfields are: large well control reserves, large well spacing, thin well pattern, multi-layer combined production and develop highest quality reserves. Infilling adjustment project is of great significance for field life extension, full utilization of facilities, efficient production, remaining oil tapping, well pattern improvement, water flooding optimization, reservoir pressure maintains and production stabilization for offshore This paper takes an oil field in Bohai as an example to analyze the potential and risks of the infilling project.
Forecasting Intelligent-Well Completion Production through a Coupled Reservoir Model with Custom Functionality
Authors: Avila Juan Carlos
Published: April 2020

Intelligent well completion (IWC) or smart wells have been used in the industry for more than two decades. Numerous benefits from this technology have been reported in the literature. These benefits are associated with improved field development economics and better reservoir management. The field economics are mainly impacted by reduction of the well count and the increase of the estimated-ultimate recovery (EUR) and net-present value (NPV) by commingling different reservoirs. The reservoir management benefits are less tangible and more difficult to quantify. They have to rely on certain assumptions that may be controversial among the team members and management. Therefore, the IWC business case is usually supported only by the improved economics.

A key input on the economics is the production forecast. The industry lacks a standard workflow to predict the production from an IWC. Reservoir engineers have to be creative using their available tools to model the performance of this complex well operation. The methods regularly used are simple inflow-performance relationships (IPR), nodal analysis, well modeling with pipeline-network simulators, and 3D reservoir simulators with multi-segment well capabilities. The latter is the most appropriate to capture the value for new developments, but still extensive customization is required to optimize the production forecast while honoring all the constraints in the field operational philosophy; the others are more suitable for routine production optimization. In our case, deepwater Gulf of Mexico (GOM), the operating philosophy is (1) use primary well-head choke to control well production, (2) limit the pressure drop across the inflow-control valves (ICV), and (3) limit the producing zone drawdown. In addition, the productivity index (PI) degradation mechanism has to be included in the forecast. None of the commercial reservoir simulators have these requirements built-in.

This paper presents an approach that integrates detailed wellbore modeling, reservoir simulation, and the field operating philosophy. The workflow is based on a pipeline network simulator (GAP™) coupled to 3D reservoir simulation models in INTERSECT™. The IWC optimization under the operational philosophy is executed through a Python script—INTERSECT custom functionality—that manages the GAP network information obtained from OpenServer™ and the reservoir simulation data to select the ICV settings that optimize the well production while honoring all constraints. This workflow provides an accurate production forecast assuring all critical operating constraints are incorporated.
Holistic Production Enhancement for Life of Field
Authors: Avery Mike , Greenaway Robert , Bridge Christopher , Rice Phillip , Mcilroy Thomas , Giraud Charlotte
Published: April 2020

This paper summarizes enabling technologies that operators can utilize when planning their field lifecycles, from development and construction through to decommissioning. By approaching field development in a holistic manner, it is possible to minimize total expenditure (TOTEX; the sum of both capital and operational expenditures), whilst also maximizing return on investment and hydrocarbon recovery.

With long-term regulatory compliance and production enhancement in mind, early introduction of flexibility into a subsea field infrastructure can enable simplified well or equipment access for common life of field activities, such as erosion sensor replacement. The resulting systems also permit execution of appropriate interventions by utilizing modest and therefore lower cost multi-service vessels (MSV) in place of larger multi-functional rigs at a premium.

In the following sections, eight different examples of various subsea production problems are presented, with an overview of how they were successfully resolved. These examples serve to demonstrate that the technologies required to deliver advanced production enhancement solutions are sufficiently mature. The paper concludes by demonstrating how more robust planning and provision for flexibility within subsea production system (SPS) design can lead to more rapid resolution and improved financial returns. Supporting these examples, discussion is provided on how digital analysis and hydraulic treatments can be used to help provide early identification and resolution of issues, thereby themselves acting as means of ultimately achieving production enhancement.

By adopting the approaches outlined within this paper, a step-change in production performance is within reach. Subsea systems designed for life of field may include digital technologies to perform on-going advisory services, live fluid sampling capability to assess production performance, and flexible architectures with access points. The optimization of on-going production and necessary intervention can drive informed operational decisions and continual optimization of the field.

The results include a reduction in operational risk exposure, maximized ultimate oil recovery, and the ability to effectively manage unplanned changes in performance. This forward-looking approach to field development, combined with a high degree of flexibility, is crucial for supporting prudent investment within today's challenging environment.
The Relevance of Annulus Seal Assemblies Qualification for Long-Term Subsea Well Integrity
Authors: Weidlich Marcos Correa , Pereira Gustavo Henrique , De Souza Bruno Sergio Pimentel , Borges Alexandre Thomaz , de Melo Everton , Santos Rodrigo Ossemer
Published: April 2020

The annulus seal assembly is an essential component of the subsea wellhead system, providing hydraulic isolation to other annuli. A failure of that device can lead to a very costly replacement intervention, due to the need of removal of the subsea equipment and production string, or even serious integrity consequences, such as underground blowout or cascade collapse of the casing strings. During the well lifetime, the annulus seal assembly is submitted to various types of loads, depending on the well temperature and the operated pressure of the "A" annulus. The analysis of those loads identified critical moments for the annulus seal assembly, which could exceed the capacity of that device if the proper lock mechanism is not installed, and cyclic loads could further depreciate its capacity. The objective of the present paper is to present a methodology to evaluate the critical loads, failure modes and qualification procedures for long-term well integrity.