bluuebunny/crossref_metadata_2025 huggingface dataset:
Flower stages, germination and viability of pollen grains of Annona squamosa L. in tropical conditions
Authors: Araújo Digelma Camila Barros , Chagas Pollyana Cardoso , Chagas Edvan Alves , Moura Elias Ariel , Oliveira Railin Rodrigues  de , Taveira Daniel Lucas , Ribeiro Maria Isabel , Grigio Maria Luiza
Published: August 2021

The success in the application of artificial pollination techniques, aspects of floral biology should receive special attention, especially regarding the viability studies of pollen grains. In this sense, two experiments were carried out, aiming to determine the floral stages: floral opening (anthesis), female, male and senescence stages of A. squamosa L flowers under tropical climate conditions, and to evaluate the germination and viability of pollen grains submitted to different storage conditions. In the first experiment, observations and data collection began when flowers were still closed. Readings were taken every two hours for 46 hours until all the flowers reached the senescence stage. For the second, the experimental design was completely randomized, in a 2 x 7 factorial scheme, with 2 storage conditions (environment at 27 ± 2°C and refrigerated at 5 ± 2°C) and 7 pollen grain conditioning times (0, 4, 8, 12, 16, 20 and 24 hours), with 4 repetitions for the analysis of pollen grain germination and 3 repetitions for the analysis of pollen grain viability, and each repetition consisted of one blade. The variables evaluated were percentage of viable and non-viable pollen grains and percentage of germinated and non-germinated pollen grains. For tropical climatic conditions, the flower anthesis (female stage) of the sugar-apple begins at 00:00 h, extending until 12:00h on the same day. The flowers of the tree reach a functionally staminate stage (male stage) from 6 a.m. the next day. Pollen grains stored at room conditions (27 ± 2°C) remain viable for up to 24 hours after collection, showing that storage in a cold environment at low temperatures (5 ± 2°C) is not necessary. Seed pollen grains have a germination percentage of 51.25% when stored under ambient conditions (27 ± 2°C) for up to 4 hours after collection.
Streptomyces sp. K47 alkaline proteases: partial purification and analysis by zymography
Authors: Çorbacı Cengiz , Özcan Kadriye
Published: August 2021

Microbial enzymes are used as organic catalysts in different industrial processes. In this study, we aimed to produce and investigate alkaline proteases from a novel actinobacterium strain isolated from a Black Sea marine sediment. The optimal production conditions for Streptomyces sp. K47 alkaline proteases was 4-days incubation at 28ºC in a salt-free medium buffered with 50 mM Tris-HCl buffer (pH 9.0) and containing glucose (1.0%, w v-1) and yeast extract (0.5%, w v-1). The enzyme solution was partially purified using (NH4)2SO4 precipitation (40-70%). After desalting, it was purified 1-84 fold with a recovery of 19.42%. Zymogram analyses revealed the presence of more than one protease enzyme. The enzyme solution exhibited maximum activity at pH 9.0 and 37ºC, remaining stable after a 2-hour incubation at all tested conditions. Streptomyces sp. K47 has the potential to be used in industrial processes because of its ability to produce multiple protease enzymes displaying stability in a broad pH and temperature range.
Proposal of a spatial database for indoor navigation
Authors: Sarot Rhaíssa Viana , Delazari Luciene Stamato , Camboim Silvana Philippi
Published: August 2021

This paper presents an approach to build a spatial database for indoor environments. It will be presented the main requirements for the implementation of an object-relational database for the representation and analysis of indoor environments, which considers the solutions for both type of representations, floor plan and schematic map. These representations consider the high number of information found in an indoor environment and the fact that they are disposed in different floors of the structure. The relationship between objects and their attributes defines the links and restrictions between them. Hence, the model should describe the entities and their interrelationships, as well as the attributes of the elements and their characteristics. After the database was developed, it was implemented an algorithm that calculates routes between points in the indoor environment, considering not only the shortest distance but also the floor change. The model was tested by Antunes and Delazari (2019) using an application and some interviews with users to evaluate the elements included in the database considering a navigating task. Some results pointed out the need to insert new information in the database regarding physical characteristics (color, material) of elements found in the indoor environment to assist users during orientation and navigation tasks. Moreover, it is necessary to include elements from the outdoor environment used as reference points in the cartographic representation.
Strengthening of Concrete Structures Using UHPC - Experimental Verification
Authors: Vitek Jan L. , Boháček Lukáš , Coufal Robert , Čítek David
Published: August 2021

UHPC is a material which exhibits excellent mechanical properties and durability. Beside new structures it is also convenient for strengthening of existing structures. The paper investigates the possibilities of strengthening experimentally. A part of the experimental program is presented which is focused on bond of UHPC and existing concrete and on behaviour in bending. Acceptable bond may be achieved when the existing concrete is clean and reasonably rough. Structural elements are exposed to positive and negative bending moments. If UHPC overlay is applied, it works in compression and in tension. The experiments were therefore focused on verification of both alternatives (UHPC in compression and in tension). Finally, the conclusions from the experiments are drawn, which may be applied in practical design.
Automation of Large Parametric Flow Assurance Analyses in the Cloud
Authors: Hubbard Rex Sinclair , Staaden Leon Geoffrey , Scales Derek John , Tran Andrew Chin Foong
Published: August 2021

The objective of this study was to determine the highest flowrate through a client's existing flowline without top-of-line condensation rates exceeding a critical value of 0.25 g/m2.s. Automation of the workflow allowed a large combination of operating conditions to be analysed within a shorter timeframe than a traditional flow assurance analysis process.

A multiparameter case matrix was developed to analyse the full range of process and environmental variables. A proprietary multiphase flow assurance software in the cloud was used to develop a reference case model. Then a software script was developed to read in the reference case model's code and produce input files for 1,080 cases. All cases were run within 30 minutes in the cloud. Another software script then extracted key data from the 1,080 output files into a single Excel spreadsheet to enable data visualisation and identification of a simple and effective flow rate criterion to limit condensation rates.

Automation of the workflow allowed all combinations of variables to be analysed within a shorter timeframe compared to the traditional flow assurance analysis process, which usually analyses a somewhat limited number of suspected worst-case scenarios selected based on engineering judgement.

The bulk data resulting from the automated workflow enabled a single integrity limit criterion to be applied with a high level of confidence, namely the fluid temperature measured at a subsea corrosion probe. This simplified integrity limit allows the operators to easily maximise production for any combination of process and environmental conditions, whilst maintaining confidence that they are not exceeding the critical condensation rate.
Wellhead Movement Analysis and Surface Casing Integrity in Pre-Salt Wells
Authors: Cutrim Fabio Sawada , De Souza Charlton Okama , De Souza Bruno Sergio Pimentel
Published: August 2021

As a general practice in the oil and gas industry, the well foundation, composed by the conductor and the surface casing, is designed with a strict tolerance regarding cement shortfall on the surface casing. However, in a pre-salt scenario, in order to reduce the costs of well construction, the surface casing shoe generally reaches the top of salt. In this case, it is quite hard to make the cement job reach the mudline due to problems like salt dissolution (generating high calipers) and presence of many geological faults in the post-salt zone (which can work as a lost circulation area). Besides that, an evaluation of the wellhead movement is necessary so that the structural restrictions of subsea equipment connected to the wellhead are not violated.

This work had the goal of presenting a coupled structural model to analyze the foundation of a subsea well with a partially cemented surface casing, where the safety factors of surface casing are evaluated in the whole well life cycle along with the wellhead movement due to the loads related to each step of this cycle. A sensitivity analysis on the top of cement (measured from the casing shoe) is made, varying it from 300 m to 800 m.

The results showed wellhead movement consistent with what is observed in the field, once no axial movement has been reported. Additionally, it was highlighted that the foundation design depends on the operations during the well construction and its future purpose, production or injection, because the thermal loads associated with operations have different impacts.
Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout
Authors: Gasparetto Vinicius , Hernalsteens Thierry , Britto Joao Francisco Fleck Heck , Leao Joab Flavio Araujo , Dos Santos Thiago Duarte Fonseca , De Oliveira Ricardo Caldeira
Published: August 2021

Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned.

This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts.

The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers.

Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections.

As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.
Guyana Operations and First Oil
Authors: Ryan Mike F. , Unietis Brian , Kaverzin Alexander , Townson Travys , Steves James , Chew Celine , Maggard Mark , Jones Justin , McGehee Brendan R. , Minnaar Karel
Published: August 2021

The Liza Phase 1 development project features the Liza Destiny Floating Production, Storage, and Offloading (FPSO) vessel, moored 190 km offshore Guyana in 1,743 m (5,719 ft) of water, and four subsea drill centers supporting 17 wells. Not only was this a Greenfield development that required an integrated team to prepare for Operations; it was also located in a New Frontier that required development of logistics and marine infrastructure to support multi drillship and FPSO operations in challenging metocean and tidal conditions. In addition, early operations and production testing was further complicated by the COVID-19 pandemic and safety protocols put in place to keep the workforce safe.

Three aspects of achieving First Oil are discussed, highlighting challenges and lessons learned:

Managing subsea completions, well cleanup, and flow assurance while drilling was ongoing Enabling accurate data collection from Multi-Phase Flow Meters (MPFMs) and downhole pressure gauges, which was critical to developing foundational understanding of well performance for reservoir characterization and management Establishing an integrated asset team and workflows to ensure life cycle value capture by managing complex marine operations, commissioning, and surveillance while meeting stringent COVID-19 protocols

Lessons learned from Destiny Operations will be incorporated into future projects, including a robust digital strategy centered on a fiber ring to shore, which will enable high-speed communications for future FPSOs, and an onshore integrated operations control center for improvement of long-term operations. Early understanding of reservoir connectivity and performance from data collection will continue to inform the reservoir management strategy so as to maximize asset value for the country of Guyana.
Predictive Maintenance Using the Executable Digital Twin xDT
Authors: Goodheart Kevin , Mas Peter , Ismail Maged , Badiali Umberto , Hendicx Wim
Published: August 2021

Through the introduction of programmable logic controller (PLCs), Dynamic Process & Controls modeling, integrating with Multiphysics Mechatronics & 3D equipment simulation modeling, companies can work in the online real-time environment. This modeling of equipment or processes builds the foundation for digital transformation of subsea, topside, onshore and plant environments.

In the design and operation of field equipment, the physics based Digital Twin is getting more and more traction to develop virtually the equipment because of recent prediction accuracy improvement and faster calculation times. Such digital twins allow to find the optimal operating conditions and predictive maintenance schedules for operation.

In this timeslot we will explain, based on few industrial examples, a new set of capabilities that allow companies to get the maximum out of digital twins to be able to use them on their equipment. By applying a structured process using Digital Twins to be able to convert the existing knowledge & data at Companies into solution to be more predictive on their equipment. This will deliver substantial return on investment (ROI) for the Oil and Gas Industry.

An AI based methodology to perform Model Order Reduction on the digital twin to be able to get real time response in connection to online unit information An AI based methodology to convert the reduced model into a virtual sensor for online quality predictions or predictive maintenance scheduling as well as to use it for creating an optimal controller of the unit based on the product requirements Fast edge computing hardware that can collect data from sensors and, in real time, run the Executable Digital Twin (xDT) and suggest corrective action to the operator or run in closed loop control
PEKK Poly Ether Ketone Ketone for High Temperature High Pressure Oil & Gas Conditions
Authors: Geslin Alexis , Paul Clément , Bussi Philippe , Barsotti Robert , Hollahan Jonathon , Calvin Mary
Published: August 2021

Poly Aryl Ether Ketones (PAEK), and in particular Poly Ether Ether Ketone (PEEK), have established themselves as polymers of choice for extreme environments. This is especially true in the Oil & Gas industry, with its very harsh conditions (high temperatures, high pressures and corrosive fluids). Within the PAEK family, Poly Ether Ketone (PEK) and Poly Ether Ketone Ether Ketone Ketone (PEKEKK) were later introduced to address the need for higher mechanical and thermal properties than PEEK; unfortunately, their chemical resistance has been reported as not matching that of PEEK.

In this paper, we report on novel, high viscosity, Poly Ether Ketone Ketone (PEKK) polymers that combine PEEK-like processing, high mechanical performances, barrier properties and very good chemical resistance in the NORSOK M710 test, positioning PEKK as a strong candidate for demanding Oil & Gas applications, such as O-rings, seals or electrical connectors.
Delivering Low Cost Wells at Matured Field with Enhanced Statistical Approach
Authors: Mhd Yusof M Hatta , Sulaiman M Zarkashi , A. Halim Rahimah , Ahmad Fauzi Nurfaridah , Sella Thurai Ahgheelan , Mahictin Masseera , Tg Yahya Tg Zuhaili , Muslim Fadli Adlan
Published: August 2021

This paper discusses the Case study of Field A in offshore Sarawak, Malaysia which focus on re-thinking development based on statistical analysis of the fields. Conventionally, well design is driven by subsurface requirement by targeting the high-reserve sand and well is designed to meet subsurface objectives. However, the conventional way may not be efficient to develop matured field environment due to the high CAPEX and the inconsistencies among well design especially in current volatile oil price period. The objective of this fit-for-purpose approach which is called "Cone Concept Statistical Approach" is to steer away from the conventional way of targeting only sweet spots whilst leaving the remaining potential resources undeveloped. Based on the statistical analysis and subsurface fields pattern, the "Cone Concept Statistical Approach" in which standardizing well design and trajectories was developed to extract the whole fields’ reserve at maximum. Well design boundaries were introduced to ensure this approach can be replicated throughout the field. Not only this study covers drilling perspective, completion perspective was also taken into consideration by exploring a cheaper and fit for purpose sand control method, considering it is a matured field with relatively short remaining field life. The Well Cost Catalogue for this field-specific was also developed which contains different types of design and completion, in order to holistically evaluate sand control method and identify the best option for the project moving forward.

This "Cone Concept Statistical Approach" aims to enable operator to drill more simple wells within the same allocated budget in which poses low-to-none risk in the design and execution phase, promoting learning curve to improve operation & HSE, and ultimately to get positive project economics. Since this simple approach can be implemented early on even during the pre-FEL stage, the FDP team & host authority can come together to jointly discuss the targets/platform ranking and segregate them into various phases. Hence, the number of platforms or drilling centers, and its location also can be optimized early on with this concept, and again, translating into further reduction in overall project cost. This paper will help other operators and host authority to understand better on how a specific development concept on statistical approach can result and turn the matured-challenging fields into more economically attractive projects – low overall development cost and maximizing the recovery.
Decommissioning Offshore Structures by Extraction of Foundation Mono piles Applying a Vibratory Hammer
Authors: van Dorp Rob , Middendorp Peter , Bielefeld Marcel , Verbeek Gerald
Published: August 2021

The vibratory hammer is one of the tools for the extraction of offshore foundation piles as well as monopiles for the decommissioning of offshore structures. In addition to the standard application, where a pile is driven downward to be installed, a vibratory hammer can also be applied to extract piles. For an efficient and commercially attractive application of vibratory hammers for this purpose, the extraction process needs to be modeled during the planning phase to ensure that the appropriate equipment is used. This paper describes how pile driving simulation software can be used to model the extraction process. This is further illustrated through a case study covering the extraction phase of the 1st (onshore) and 2nd (offshore) part of the Delft Offshore Turbine Project. A monopile with a diameter of 4.0 m was extracted approximate 6 months after installation onshore and then extracted several times offshore shortly after installation in the 2nd phase. The paper will not only present the actual extraction predictions, but also the monitoring data obtained during extraction and the results of the post-analysis.
Novel THOR Technology for Orientation of Vertical XT to Completions
Authors: Katsounas Nicholas Paul , Pathak Parth Dilip , Quates Daniel Ronald , Mosscrop Guy
Published: August 2021

On conventional vertical trees (VXTs) with a tubing hanger (TH) in the wellhead (WH), orientation of the VXT to the TH system is a complicated and expensive process. Leveraging patented technology, the tree to hanger orientation ring (THOR) and tooling were implemented to save CAPEX and OPEX while eliminating risks associated with conventional orientation solutions. An open-water tool installs an external alignment feature onto the wellhead, which is oriented with the tubing hanger already installed in the wellhead. The VXT then orients onto the wellhead with the help of this external alignment feature, resulting in correct orientation with the tubing hanger. This paper discusses the novel technology and its successful development and installation for a subsea project, which revolutionizes the VXT portfolio.

Rapid development of THOR technology was required along with expedient project execution. Utilizing digital-twin design techniques such as finite element analysis and operator simulations, the operating life of THOR tooling was investigated in parallel with project engineering. The novel nature of the THOR required unconventional testing, which was performed in-house. Project execution plan was implemented for engineering and manufacturing to successfully build the production equipment on schedule. Comprehensive system integration testing was completed upon the first attempt. The system was deployed to staging facilities before being delivered offshore to the customer and installed subsea in stages during April 2020. Involvement of the operators and installation contractors during the development stage made THOR's first deployment attempt a major success with zero recorded nonproductive time, even during COVID-19.

THOR technology reduces the number of components as well as the weight and size of the equipment. The novel THOR equipment can be run by a light intervention vessel rather than conventional equipment, which requires mobile offshore drilling units. The time spent to deploy the VXT system is also reduced, minimizing indirect supply-chain and field-service-related carbon emissions. This further enables reduced carbon emissions and overall carbon footprint of the entire project.

The field-proven THOR technology is an evolutionary orientation technology that simplifies the installation operations for the vertical tree and tubing hanger. This technology maintains the robust conventional system configuration post installation and hence does not affect reliability of the VXT system.
Searay Autonomous Offshore Power System AOPS: Results of Sea Trials and Payload Support Demonstration
Authors: Lesemann Arvid Reenstjerna , Hammagren Erik Joel
Published: August 2021

As the offshore energy sector looks to fully implement resident, autonomous, robotic, digital systems offshore, one missing piece of the puzzle is remote power generation. Further complicating these efforts are the owner/operators’ move towards net zero operations. The combination represents a significant dilemma for the offshore energy industry: if gensets and topside vessels are not appropriate or practical power sources for future resident systems, how will these needed cost and carbon-saving innovations come to market and get deployed in the field?

Objectives/Scope

The proposed paper will provide an overview of a new platform solution, an autonomous offshore power system (AOPS), that looks to complete the puzzle. A number of AOPS’ are under development world-wide. The paper will review the state-of-the-art, including the SeaRAY AOPS, which will undergo sea trials off the coast of Marine Corp Base Hawaii, on Oahu, Hawaii, USA. The sea trials are expected to last for six months.

Note: Because of COVID-related delays, the sea trials originally planned for late 2020 will now start in 2Q21. The August presentation at OTC will include the latest information available on the sea trials and co-deployed payload testing.

Methods, Procedures, Process

The SeaRAY AOPS is the result of a project co-sponsored by the U.S. Department of Energy, U.S. Navy, and C·Power, to design, build, and test a novel AOPS technology. The SeaRAY AOPS provides kW-scale power generation, energy storage, and real-time data and communications capabilities for remote, offshore systems, including unmanned subsea and surface vehicles (e.g., AUVs, ROVs, USVs), sensor payloads (e.g., environmental monitoring or methane emissions) and operating equipment (e.g., emergency power for failed/failing umbilical, field modernization, or redundant power for BOP systems).

Satisfying the need for cleaner operations, the SeaRAY and other AOPS devices capture and convert ocean energy into electricity to charge the energy storage system. The payloads, in turn, receive their power from the intermediate energy storage system, allowing campaign-based or extended residency.

Results, Observations, Conclusions

The paper will review the initial results from the planning, permitting, deployment, operation, and maintenance of the SeaRAY AOPS and the co-deployed sensor and vehicle payloads, which include a seafloor acoustical environmental monitoring system and a hybrid AUV.

Novel/Additive Information: The market impact of AOPS’ for the offshore energy industry can be significant, as the class of systems is intended to enable reductions in operational costs, carbon emissions, and complexity, while enabling a fuller implementation of autonomous and semi-autonomous resident systems. The paper will outline these features and benefits for the offshore energy industry, along with the results to-date of the novel SeaRAY AOPS’ sea trials.
Value Tracking Thru Digital Fields Countrywide Solution Big Data Analytics Project
Authors: Karim Anak , Abu Hassan Hairulirwan , M Izdihar Muslimin Sayyid , Fuenmayor Roberto , Kamarulzaman Ammar , Mokhlis Mohamad Mustaqim
Published: August 2021

The Digital Field initiative is transforming the daily operations on the oilfield and it is now part of PETRONAS corporate wide digital strategy.

This transformation is done by onboarding multiple disciplines such as subsurface team, facilities, and operations, HSSE and Business Planning and is designed to replicates the performance of an oilfield in the computer, combining business process management and technical workflows. Digital Field has enabled the customer to execute their work collaboratively, by providing decision support system (technical workflows and business process management tools) subsequently improving their process efficiencies and optimizing their production. It is believed that by conducting a systematic review of the improvement and tracking the values that has been achieved, it will help to promote and accelerate digital adoption faster.

The main objectives of the Automated Value Tracking are:

To promote opportunity generation through collaborative environment. To track stages of every opportunity of the following categories of Production Optimization, Unplanned Deferment and Process Cycle Efficiencies. To quantify values associated with opportunities generated from automated workflows and current business process. To promote ownership of the actions associated with the assigned opportunity and to help to quantify on individual level contribution to the corporate goal in terms of production volume and time savings. To measures optimized number of opportunities generated against production volume associated with Production Optimization activity according to Field category and Quality of Opportunity Generated from Optimization Advisor.

The process is summarized as follow:

Opportunity generation: Automated opportunity generation generated through current Production Optimization Advisory framework. Integration with existing Petronas business process tools i.e. Daily Operational Tracking System, Alpha projects, Opportunity Management system, etc. Manual opportunity generation. Opportunity evaluation and analysis: Provide quantitatively confidence level of production incremental volume from automated Optimization Advisory through machine learning. Establish relationship between numbers of opportunity completed and categories versus production volume gain. Opportunity tracking and approval: Tracking the opportunity generation according to the process level. Escalating Opportunity and value recognition through business process approval.

This workflow helps to improve to understand the current update of the different levels such as well, field, region and upstream with the help of integrating the value realization and allows "cards" to show information that can trigger opportunities to increase production, reduce time of decision and fast action.
Planning for Unknown in The New Age of Digital: A Paradigm for Offshore Oil and Gas Risk Assessment and Management
Authors: Hamedifar Hamed , Wilczynski Herve
Published: August 2021

Major Oil and Gas operators and service companies look to undertake large scale digital transformations aimed at producing integrated, connected, and intelligent enterprises. These transformations require accelerating the journey to the cloud to modernize the entire application portfolio. By transitioning to the cloud, firms enjoy improved data analytics which allow for evolution to next generation digital work environment. This shift, however, comes with workforce challenges. Employees in all categories and at most levels will require significant cross- and up-skilling to take full advantage of the digital transformation. As vendors, suppliers, service companies, and operators move products and equipment around an expanding ecosystem of assets, security threats are likely to increase due to further geopolitical instability. Data based decision making, which enables the optimization of assets and automation of operations to minimize workforce risk exposure must be implemented with consideration of enterprise risk reduction (across the asset and workforce operational risk life cycle).

As Oil and Gas operations become more geographically dispersed and diverse, they are exposed to new and evolving risk factors which can directly impact value. These risk factors make asset acquisition, development, management, and maintenance all more challenging. Analyses of risk in a digital foundation risk-based platform is most valuable at the earliest stages of asset development in determining whether to proceed with the planned development through to end-of-life decommissioning. Successful firms must create an end-to-end digital roadmap which delineates between technical and transactional activities and outlines effective stakeholder engagement at each project stage.

The fundamental thesis of this paper is that although risk can be mitigated and reduced through the introduction of digital tools into oil and gas operations, it can never be completely removed. Furthermore, while industry research on the impact of digitalization usually rely heavily on cost savings, optimization, and health, safety, and environment (HSE) related cases, they typically fail to consider the contribution of digitalization on risk assessment and management. This paper argues that we need to move away from the focus on cost savings, process optimization, and HSE metrics improvement metrics. This paper sets up a mechanism for developing risk-based strategies for implementation of digital solutions.
From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil
Authors: Santos Paulino Bruno , Junior Teixeira Gilberto , Nogueira Leonardo De Souza , João Vilain Leonardo , Torres Simas G Milton , Costa Leonardo De Menezes
Published: August 2021

In the last three years, COMPANY has started the production of eight Surface Production Systems (Floating, Production, Storage and Offloading Units) in the Búzios and Lula fields of the Brazilian pre-salt that have generated technical knowledge, organizational learning and many opportunities to explore in upcoming projects. The lessons learned as well as the organizational knowledge acquired in this period, resulted in a new approach for the commissioning process to apply in COMPANY's coming FPSO projects.

During this period, COMPANY identified improvement opportunities and stablished structuring programs focused on adding value to these new assets. The main opportunity identified was to reduce the period required for ramping-up the oil production, considering aggressive target dates for start-up, with high up time on the gas compression systems with minimum flaring.

In this manuscript, will be described some of the important actions and changes made in commissioning process that allowed COMPANY to achieve better efficiency and safety in ramp up of new FPSOs in Brazilian pre salt fields.
Seismic Attributes and Acoustic Inversion for Shallow Marine Slope Stratigraphy Analysis
Authors: Son Jungrak , Boon Rebecca , Kuhn de Chizelle Julien
Published: August 2021

Geophysical seismic surveys have been used in marine site characterization for subsea engineering and the design of offshore structures. Signal processing plays a key role in obtaining seismic attributes from observed seismic data to identify subsurface geological features within complex shallow sediments. Instantaneous amplitude, phase, and frequency are the most widely used seismic attributes to indicate geological features, but those time-domain data are too limited to define an accurate subsurface model in depth. Therefore, seismic inversion is also required to generate additional geospatial subsurface model information to aid in shallow stratigraphy interpretation. In this paper, we applied both geophysical signal processing and stochastic seismic inversion to a high-resolution multichannel seismic dataset from the Eastern North American Margin (ENAM). Seismic attributes from the Hilbert transform and inversion modeling results (acoustic impedance and modeling uncertainty) were integrated to define better geological horizons and discontinuities. The results show the integrated geophysical subsurface models can support seismic interpretation and improve shallow marine site characterization.
Unlocking Potential Thru Sand Management Insights in Digital Fields
Authors: Mohd Shabarudin Shazana Ezza , Salleh Mohamad Salhizan , Abu Bakar Hizamal Afdzal , Jamaluddin Nasri Muhamad , Vo Tri Nghia , Hermann Roland , Fuenmayor Roberto , Mokhlis Mustaqim Mohamad
Published: August 2021

Sand production is creating sand erosion and deposition issues at multiples levels such as tubing, choke and pipeline, therefore causing multiples undesirable events such as unplanned production deferment, integrity and sand handling capacity issues in each field.

Traditionally, each field has common practices to address sand issues. However, this creates non-standard procedures and prevents sharing best practices around all the assets. Managing sand production and related risks are keys where a multi-disciplined team (from subsurface to the surface) is required to ensure safe operations in more than 45 offshore fields.

To efficiently manage such a challenge at scale, there was a need to develop a single common digital platform for all. The digital platform provides unified user experience and proactive actionable insights to all assets with characteristics such as;

Scalable to all fields Solution architecture to allow fast implementation Same company-wide user interface/user experience platform

To achieve this ambition, it was necessary to move away from traditional waterfall project development to agile approach, automating ingestion of data from multiple sources, integrating the in-house development tool as engine based on equations develop specifically for Malaysia fields.

The solution was deployed to all fields during 2019. This had created additional benefits such as

Transparency on the data: Anyone can access to any field Visible Metrics: All fields sharing the same metrics, also improving and developing adjustments according to each situation Regulatory Compliance: Helping to keep up to date with sand sampling

There are already fields reporting examples of value realization in the form of Cost Avoidance and/or reduction in unplanned deferment due to improved Sand Management handling from the solution. It is expected that the value realization will increase by taking actions of protecting the field of any Loss of Primary Containment (LOPC), saving time of deciding as Process Cycle Efficiency (PCE). The solution can potentially be utilized for annual field forecasting for work program and budget cycle.
Design Perspectives for Selection of Subsea Gas Lift Technology for Deep Water Fields
Authors: Tornisiello Ligia , Taxy Stephane , Curto Rick
Published: August 2021

Riser base gas lift is conventionally used in deep water fields to minimize backpressure on wells, smooth start-up transients, and mitigate slugging in the flowline-riser system which can cause disruption in the topside facilities. The effectiveness of riser base gas lift depends on several factors, such as the reservoir performance, the fluid properties, the field architecture, and the topography. There are several technical solutions available to deliver the lift gas to the riser base. Such technical solutions differ in terms of lift-gas supply method (distributed vs point-to-point), riser specifications, and overall system complexity. The selection of technical solution has the potential for minimizing infrastructure. Available solutions include bundled risers and concentric riser configurations that allow gas lift functions to be integrated with the main production conduit. The evaluation of riser base gas lift effectiveness and the selection of the most appropriate technical solution is typically performed early in the field development cycle. This paper presents a review of the available subsea gas lift technical solutions and discusses an evaluation process, including criteria for the selection of the most appropriate solution. The presented case study assumes a deep water Gulf of Mexico field, in which the main subsea system consists of two wet insulated piggable flowline loops. Key decision drivers were flow assurance requirements, complexity, operability, impact on field layout, interfaces, installation, and schedule are discussed. This holistic approach aids the selection of the most appropriate riser base gas lift system in the early field development cycle.
An AI-Based Detection System for Mooring Line Failure
Authors: Sidarta Djoni Eka , Tcherniguin Nicolas , Bouchard Philippe , Lim Ho-Joon , Kang Mengchen , Leridon Aurelien
Published: August 2021

Safe and productive offshore operations are of utmost importance, with monitoring the integrity of mooring lines on floating offshore platforms being one of the key factors. The conventional method uses sensors installed on mooring components, which may fail over time and can be costly to replace. Alternative methods using dry and non-intrusive monitoring systems offer a lot of potentials to the industry.

An alternative method that uses only Differential Global Positioning System (DGPS) data has been proposed by Sidarta et al. (2018, 2019), and it does not require any information on environmental conditions. This alternative method is based on monitoring shifts in the low-frequency periods and mean yaw angles as a function of vessel positions, mass and added mass. The method utilizes Artificial Intelligence, specifically Artificial Neural Network (ANN), for the detection of mooring line failure, which is a pattern recognition and classification problem. The ANN model learns to recognize and classify patterns of intact mooring lines and those of a broken line. One of the proposed models is a group identification model, in which the model identifies the mooring group that has a broken line.

This paper shows that an ANN model can be quite robust and tolerant in dealing with conditions that are somewhat different from its training. As an example, an ANN model for detecting mooring line failure on a spread moored FPSO has been trained using MLTSIM hydrodynamic simulations with quasi static model of the mooring lines and risers to significantly reduce the computational time to generate the ANN training data. The trained ANN model can properly function when tested using fully coupled OrcaFlex hydrodynamic simulations with environmental conditions that are not included in the training. Moreover, although the ANN model has been trained using simulations with a completely removed line, the trained model can still function for a line broken at the bottom.

This ANN model is an ANN-based status detection model, which is one of the key components in the ALANN (Anchor Lines monitoring using Artificial Neural Networks) System. The system also composes of an ANN-based system evaluation model, an algorithm-based status detection program and an event detection program. A series of fully coupled dynamic simulations have been used to test the ALANN System. Most of the simulations have a single mooring line failure that occurs randomly during simulation, and the failed line varies for different simulations. Each simulation lasts for six hours. The ALANN System uses a two-hour time window at a time and moves every 20 minutes. The tests demonstrate how each component of the ALANN System contributes to and improves the robustness of the overall solution.
Assessment of Internal Tubular Coating Using Flow Loop
Authors: Zakaria Muzdalifah , M Sauri Shalabi A.
Published: August 2021

Assessment of coating performance under flowing condition by using a proprietary flow loop system has been established. The 2 3/8" flow loop was designed to maintain a flow rate of 0.03-0.04 m3/sec, pressure of 3300kPa and temperature of 150°C to simulate actual field condition. Test section consisting of two 35" straight tubes with 45° elbow was internally coated and connected to the flow loop which was run continuously for 14 days with deionized water under the specified test condition. Upon completion, visual inspection, EIS and linear abrasion test were done on the test section to evaluate the coating integrity post exposure. Small blisters were noted at the elbow section potentially due to the improper surface preparation and/or higher fluid velocity at the bend section. Impedance value of 107 Ω/cm2 is a magnitude higher than the acceptance limit of 106 Ω/cm2 while abrasion resistance was found less than the set limit of <100mg/1000 cycles. The flow loop test has been shown to be a reliable tool to evaluate the effect of wall shear stress and fluid erosion on internal tubular coating.
Sensor Ball: Autonomous, Intelligent Logging Platform
Authors: Buzi Erjola , Seren Huseyin Rahmi , Deffenbaugh Max , Bukhamseen Ahmed , Zeghlache Mohamed Larbi
Published: August 2021

Recent developments in automation and electronics have enabled modernization and miniaturization of oilfield instruments. One product of these trends is our autonomous logging platform called "Sensor Ball". The Sensor Ball is a handheld, untethered logging tool that one person can deploy and recover from a pressurized well with no special equipment and crews (Deffenbaugh, 2016). The only tool needed is a wrench to open the cap of the wellhead. The operator puts the sensor ball in through the cap, then sequentially opens and closes the crown and master valves. This process takes only a few minutes. Once clear of the well head, the Sensor Ball falls down the well, logging data as it travels downhole. During this time, all the wellhead valves are closed and there is no need for the field crew to stay at the well site. We present data from recent Sensor Ball deployments to log pressure and temperature profiles and bottom-hole pressures. Depth information is provided by a novel onboard sensor that detects the connections between casing or tubing joints like a casing collar locator. A small dissolvable metal weight is magnetically attached to the housing and is sized to make the Sensor Ball descend at about 1 foot per second. At the desired depth, Sensor Ball drops the weight to become buoyant in the wellbore fluids and return to the surface. As it returns, it repeats the logging measurements, storing temperature and pressure data in its internal memory. After a typical four-to-eight hour mission, the operator returns to the well, opens and closes the well head valves in reverse order, removes the cap and takes out the Sensor Ball. The logged data are downloaded wirelessly to a laptop or cell phone. A lightweight, syntactic foam housing provides buoyancy and protects the electronics from the well fluids. The small thermal mass of the housing minimizes the temperature distortion in the downhole environment. This miniaturized technology simplified logging to a one-person job and shortened the time at the well from multiple hours to a few minutes.

This work describes a novel method of retrieving downhole data, which is a practical and inexpensive alternative to wireline or slickline logging and permanently-installed sensors (Deffenbaugh, 2017). In this paper we present the system design and our recent field results from vertical and deviated wells. We also describe a new application of the Sensor Ball where we perform extended bottom-hole pressure measurements in addition to logging temperature and pressure along the wellbore.