bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Temperature, Reeling Speed and Pipe Tension on the Performance of Field Joint Coating During Reeling of Offshore Pipelines
Authors: Dhole Rajaram , Ripoll Ismael , Rajaratnam Sabesan , Jablonski Celine
Published: August 2021

Pipelines are coated with insulating material that minimizes heat losses to the environment. Reeled pipe can experience nominal bending strain in the order of 1% to 2%. Thick coating on the pipe is inherently more highly strained, because of concentrations that occur at the interface between parent coating and field joint coating. Occasionally, contractors who specialize in pipe-lay using the reeling method have experienced difficulties relating to unexpected disbondment and cracks in coating at these interfaces. Any disbonded coating is routinely identified and repaired, but it is important to understand the influential factors that could lead to this type of coating disbondment. It is known in the industry that parameters such as temperature, reeling speed and pipe tension are influential but the relative influence of the factors is not well understood. In addition, there is currently no industry code or recommended practice that proposes the strain levels that the coating could safely withstand prior to cracking. This paper addresses thermo-mechanical aspects of coating design and presents a novel approach to quantify which parameters have the largest influence.

In the presented assessments, coating strain was assessed using finite element analysis. Material input was selected from a combination of typical values and specific laboratory test results for polypropylene (PP) and injection molded polypropylene (IMPP). An essential aspect was that the mechanical and thermal properties of the PP were related to temperature and strain rate. Strain rates in the coating during reeling operations were obtained from global FE models. Detailed local FE models incorporated all the material and load inputs and temperature conditions that are necessary to determine peak strain values in the coating; the peak strain values would indicate the locations of potential coating disbondment.

The study is purely a strain assessment and excludes any potential for defects or delamination in the coating that could result from its manufacturing process. This strain-based study revealed that coating temperature during reeling is the most influential factor on strain level in the coating. Reeling speed and pipe tension are parameters providing secondary influences.
The Auger TLP: Calibration of Minimum Bottom Tendon Tension Based On Field Measurements
Authors: Chen Jinbo , Chen Yong , Barras Justin P. , Nadathur Varadarajan , Tang Zhaoxiang , Huang Edward
Published: August 2021

The Auger Tension Leg Platform (TLP), which was installed in 1994, is Shell’s first TLP in the Gulf of Mexico (GoM). The Auger TLP was designed during the time when the industry had not yet been able to fully investigate the global dynamic characteristics of TLPs, especially the high frequency dynamic responses of tendons, and the design tensions of the Auger tendons were not calibrated to scaled wave basin model tests like the later TLP projects since the Auger TLP. Based on the accumulated experience from more than two decades’ operation and a number of studies conducted on the Auger TLP global performance, it is revealed that the Auger tendon tension is conservative given the current operational limit; however, the extra conservatism has not been fully quantified due to the lack of model test data. With the recorded Auger global motions and tendon tensions from the on-board measurement system, the performance of the Auger TLP in extreme storms is becoming fully unveiled by calibrating the analytical predictions (both time-domain analysis and frequency-domain analysis) with the measurement data. Thus, the objectives of this paper are (i) to calibrate the TLP minimum tendon tension design recipe based on the high-fidelity field measurement data from Tropical Storm Cindy 2017 and Hurricane Laura 2020 using both time-domain and frequency-domain simulations, and (ii) to propose the new allowable vertical center of gravity (VCG) and the new tendon pretensions for the Auger TLP for the extreme storm conditions. It is concluded that the current allowable VCG can be increased or the current required tendon pretension can be decreased without compromising the safety to the platform during the extreme storm conditions.
Lateral Buckling Mitigation in Deep Waters - A Total Installed Costs Comparison
Authors: Priyadarshi Hemant , Fudge Matthew , Brunner Mark , Jose Seban , Weakly Charlie
Published: August 2021

The paper introduces lateral buckling mitigation techniques (sleepers, distributed buoyancy sections, and residual curvature method or RCM) used in deep water fields and provides a total installed cost comparison of these solutions in relative terms. A hypothetical deep-water scenario is used to compare all techniques within the same site environment. Historic benchmarks have been used to make a relative comparison of these buckle mitigation methods on the engineering, procurement, fabrication, and installation fronts.

In addition, risks associated with engineering, procurement/fab and installation have been listed to illustrate the risks versus rewards tradeoff. While sleepers and distributed buoyancy have been previously used in deep water, RCM doesn't have a significant track record yet. RCM is a proven and cost-effective buckle mitigation solution in shallow water. This paper compares its application in deep water to the prevailing buckle mitigation methods and confirms if it creates value (savings and reduces risks) for an offshore installation project. It is assumed that each mitigation method is appropriate for the hypothetical deep-water scenario.
Qualification of AM-Parts for The Offshore Industry
Authors: Moe Ole-Bjørn Ellingsen , Benoit Maillon Bertrand Henri
Published: August 2021

Use of additive manufacturing (AM) technology is quite mature in medicine and aerospace industries but adoption of the technology has been limited in the oil and gas industry. One of the reasons behind the slow adoption is the non-availability of industry standards and recommended practices. DNV aims to help the adoption of AM in the oil and gas industry by providing the needed industry standards and recommended practices. DNV is one of the largest classification societies in the world and provides classification, technical assurance, software and independent expert advisory services to the maritime, oil & gas and energy industries.

DNV has been running several projects globally to help the industry qualify materials and products produced by additive manufacturing. DNV has been working since January 2018 together with main stakeholders in a joint Industry Project (JIP) to develop requirements necessary to introduce components made by AM for oil and gas and related applications. The outcome of the JIP was released to the industry in 2020; a standard that describes the qualification and quality assurance of AM parts. The AM technologies addressed in the standard are laser based powder bed fusion (PBF-LB) and wire arc additive manufacturing (WAAM).

In this paper, the standard is presented, and a systematic way to qualify parts made by PBF-LB and WAAM technologies described. A case study, leading to a qualified part according to the standard will be presented. It has been led by Vallourec, a world leader in tubular solutions for the energy sectors. Vallourec embraced additive manufacturing a few years ago and is currently developing and offering WAAM components for various industries.
Real-Time Prediction of Choke Health Using Production Data Integrated with AI
Authors: Alghamdi Ahmed , Ayoola Olakunle , Mulhem Khalid , Otaibi Mutlaq , Abdulraheem Abdulazeez
Published: August 2021

Chokes are an integral part of production systems and are crucial surface equipment that faces rough conditions such as high-pressure drops and erosion due to solids. Predicting choke health is usually achieved by analyzing the relationship of choke size, pressure, and flow rate. In large-scale fields, this process requires extensive-time and effort using the conventional techniques. This paper presents a real-time proactive approach to detect choke wear utilizing production data integrated with AI analytics.

Flowing parameters data were collected for more than 30 gas wells. These wells are producing gas with slight solids production from a high-pressure high-temperature field. In addition, these wells are equipped with a multi-stage choke system. The approach of determining choke wear relies on training the AI model on a dataset constructed by comparison of the choke valve rate of change with respect to a smoother slope of the production rate. If the rate of change is not within a tolerated range of divergence, an abnormal choke behavior is detected.

The data set was divided into 70% for training and 30% for testing. Artificial Neural Network (ANN) was trained on data that has the following inputs: gas specific gravity, upstream & downstream pressure and temperature, and choke size. This ANN model achieved a correlation coefficient above 0.9 with an excellent prediction on the data points exhibiting normal or abnormal choke behaviors. Piloting this application on large fields, where manual analysis is often impractical, saves a substantial man-hour and generates significant cost-avoidance. Areas for improvement in such an application depends on equipping the ANN network with long-term production profile prediction abilities, such as water production, and this analysis relies on having an accurate reading from the venturi meters, which is often the case in single-phase flow. The application of this AI-driven analytics provides tremendous improvement for remote offshore production operations surveillance.

The novel approach presented in this paper capitalizes on the AI analytics for estimating proactively detecting choke health conditions. The advantages of such a model are that it harnesses AI analytics to help operators improve asset integrity and production monitoring compliance. In addition, this approach can be expanded to estimate sand production as choke wear is a strong function of sand production.
Real-Time Water Injection Monitoring with Distributed Fiber Optics Using Physics-Informed Machine Learning
Authors: Sadigov Teymur , Cerrahoglu Cagri , Ramsay James , Burchell Laurence , Cavalero Sean , Watson Thomas , Thiruvenkatanathan Pradyumna , Sundin Martin
Published: August 2021

This paper introduces a novel technique that allows real-time injection monitoring with distributed fiber optics using physics-informed machine learning methods and presents results from Clair Ridge asset where a cloud-based, real-time application is deployed. Clair Ridge is a structural high comprising of naturally fractured Devonian to Carboniferous continental sandstones, with a significantly naturally fractured ridge area. The fractured nature of the reservoir lends itself to permanent deployment of Distributed Fiber Optic Sensing (DFOS) to enable real-time injection monitoring to maximise recovery from the field. In addition to their default limitations, such as providing a snapshot measurement and disturbing the natural well flow with up and down flowing passes, wireline-conveyed production logs (PL) are also unable to provide a high-resolution profile of the water injection along the reservoir due to the completion type. DFOS offers unique surveillance capability when permanently installed along the reservoir interface and continuously providing injection profiles with full visibility along the reservoir section without the need for an intervention.

The real-time injection monitoring application uses both distributed acoustic and temperature sensing (DAS & DTS) and is based on physics-informed machine learning models. It is now running and available to all asset users on the cloud. So far, the application has generated high-resolution injection profiles over a dozen multi-rate injection periods automatically and the results are cross-checked against the profiles from the warmback analyses that were also generated automatically as part of the same application. The real-time monitoring insights have been effectively applied to provide significant business value using the capability for start-up optimization to manage and improve injection conformance, monitor fractured formations and caprock monitoring.
Three-Phase Flow Profile Determination of A Horizontal Well in Offshore by Tracer Technology
Authors: Katashov Alexander , Novikov Igor , Malyavko Evgeny , Husein Nadir
Published: August 2021

Over the past few years, the oil and gas industry has faced a situation of high fluctuations in hydrocarbon prices on the world market. In addition, the trend for the depletion of traditional hydrocarbon reservoirs and the search for new effective solutions for the management and control of field development using horizontal and multilateral wells is still relevant.

The most common method for horizontal wells testing is production logging tools (PLT) on coiled tubing (CT) or downhole tractor, which is associated with HSE risks and high cost, especially on offshore platforms, which limits the widespread use of this technology. The solution without such risks is the method of marker well monitoring, which allows obtaining information about the profile and composition of the inflow in a dynamic mode in horizontal wells without well intervention.

There are several types of tracer (marker) carriers and today we will consider an approach to placing marker monitoring systems as part of a completion for three-phase oil, water and gas monitoring.
Hydrate Management Strategy for Subsea Development in Gulf of Mexico
Authors: Soroush Samaneh , Lu Debbie , Golczynski Tommy , White Christopher Jake , Spratt Tony
Published: August 2021

Gas hydrate formation in natural gas systems and subsea infrastructure can block pipelines and instruments, restrict flow, and lead to safety and environmental hazards in production and/or transportation systems. These problems can lead to substantial economic and HSE risks. Therefore, understanding how, when and where hydrate formation occurs are important factors in developing the hydrate management strategies. This paper addresses the hydrate management strategy in one of the subsea developments in the Gulf of Mexico (GOM). The effects of salinity, water cut, and amount of methanol on hydrate formation and plugging risk were studied in this paper. The experimental results and modeling in advanced thermodynamics software showed that an increase in the concentration of methanol and salts in the autoclave cell leads to a shift of the equilibrium curves, reducing subcooling and hydrate volume fraction while increasing induction time. The results also show that for some under-inhibited systems, the volume fraction of the hydrate slurry is low enough to allow for safe transportation of fluids during various operational conditions.
Lessons Learned from Optimising Sand Control and Management Strategies in a Low Permeability Sandstone Oil Field
Authors: Daramola Babalola , Alinnor Chidubem Martins
Published: August 2021

This paper presents the lessons learned from optimising the sand control and management strategies of an oil field (Field E) after multiple sanding events and well failures. It presents how the old sand control solution was selected, the failure root causes, and the remediation options considered. The new sand control method, and the performance of two re-drilled wells after two years of production are also presented.

Field E is a sandstone field with oil and gas-cap gas at initial conditions, and was initially developed with 5 production wells, 2 water injection wells, and 2 gas injection wells. The development wells were drilled from an offshore platform, and completed with stand-alone screens (SAS) in 2013. Oil production commenced in late 2013, and within three years, sand production was observed, and 4 of the 5 oil production wells had failed. The 4 wells were re-drilled in 2017, and the sand control strategy was changed from stand-alone screens to frac-packs.

Key lessons learned include completing sand strength studies pre-development, avoiding off-the-shelf sand control solutions, and completing sand control design studies based on service contractor capability, fines control, oil production rates, and sand control as key selection factors. Nearby wells should be shut in during infill drilling operations to avoid short circuits, drilling mud losses, completions damage, and well integrity failures.

It is recommended that the bean up procedures of wells with sanding events are changed to slow bean up to preserve well integrity, oil production, and cash revenues. The asset team should consider installing sliding sleeves or inflow control devices for zonal testing and to choke or close sand production zones if needed. The asset team should also consider installing a test pipeline and a test separator to allocate sand production volumes from each well, clean up new wells, sample the wells for water salinity measurements, and other benefits.
Cost-Effective Upgrades of Drilling Risers to 20,000 Psi Applications through Composite-Reinforced Steel Choke and Kill Lines
Authors: Persent Emmanuel , Grosjean Francois , Averbuch Daniel , Roguet Eléonore
Published: August 2021

Oil and Gas companies are considering drilling operations in the challenging high-pressure/high-temperature (HP/HT) environment, which requires new equipment to be qualified to 20,000 psi working pressure and 350°F maximum temperature.

In this study, IFP Energies Nouvelles (IFPEN) has considered the use of composite-reinforced steel Choke and Kill (C&K) lines for retrofitting an existing drilling riser equipped with 15,000 psi steel C&K lines to HP/HT applications. The feasibility of this upgrade solution has been validated through composite material testing and design studies.

The composite provides a 20,000 psi Choke and Kill line that is lighter than a 15,000 psi steel line for (almost) the same outer diameter (OD) while maintaining a nominal inner diameter (ID) of 4.5" for safer operations and ensuring a large safety margin on burst. These major advantages allow the C&K lines to be replaced without increasing the riser mass and with no other modification on the riser design. In particular, the expensive buoyancy modules can be kept in place.

Through combining the best features of steel and composite, this technology offers a cost-effective way to upgrade an existing drilling riser to 20,000 psi/350°F applications.
Digital Transformation and Automation of Flow Assurance Engineering Workflows Using Digital Field Twin
Authors: Patel Harshkumar , Cai Jianlin , Noiray Gautier , Bhowmik Subrata
Published: August 2021

Flow assurance is central to the design of a subsea production system and requires frequent interfacing with engineers from multiple disciplines. The objective of this paper is to demonstrate how cloud based digital field twin can be leveraged to automate subsea flow assurance engineering workflows and consequently, achieve efficient collaborations, faster and reliable designs, and reduced costs.

In this proposed workflow, engineers use a web application built on top of a cloud-based digital twin platform to perform flow assurance calculations and design analysis. The web based platform integrates multiphase flow simulators and other relevant engineering tools through python scripts. A user is only required to input design constraints and necessary basic information. The application acquires inter-disciplinary data (e.g. pipeline, layout, equipment, etc.) and automatically performs pre-processing, model setup, simulation, and results processing in the background and make results available to all the users at the front-end.

The digital flow assurance platform replaces traditional workflows requiring use of different standalone engineering software, and frequent exchange of information with other engineering teams in form of documents and spreadsheets. The proposed cloud-based workflow allows engineers to focus on technical analysis by eliminating several manual and repeating processes such as accessing different software, creating models, results extraction and formatting, etc. The ability to share results in form of auto-generated reports and formatted spreadsheets; minimizes human errors and promotes information exchange and transparency among project team members from different disciplines. The cloud based platform enables engineers to work on a same project from different geophysical locations and devices. Overall, this digital flow assurance workflow significantly improves engineering efficiency, save costs, and allows faster and reliable concept design and FEED (Front End Engineering Design).

The ideas widely discussed for flow assurance digitalization typically include use of data analytics and machine learning, virtual flow metering, real time data monitoring, predictive analytics, etc. This paper, however, presents novel practical idea to bring digital transformation to the way flow assurance engineers work and collaborate.
Legacy Field Upgrades - Production Control System Lessons Learnt
Authors: Moe Sigurd , Pham Dennis
Published: August 2021

This paper describes examples of functionality and equipment limitations encountered during the subsea field operational phase, and practical solutions to eliminate the limitations. It addresses changes and upgrades required to hydraulic, chemical and electric infrastructure. Modifications and upgrades, such as retrofit sensors, retrofit electric actuators, bypass connections and digital soutions are described. How a holistic obsolescence strategy can modernize the subsea functionality and let different generation systems coexist is further described.
Underwater Photogrammetry as an Environmental Assessment Tool to Monitor Coral Reefs and Artificial Structures
Authors: Vincent Mahamadaly , Isabel Urbina Bareto , Louis Fréchon , Romain Pinel , Rémi Garnier , Kenneth Deslarzes
Published: August 2021

Over the past decade, photogrammetry has grown considerably thanks to technical advances in digital cameras and computing performance. Popular in terrestrial applications with the development of UAV acquisition, photogrammetry provides access to accurate scene reconstruction, high-resolution measurements, and temporal comparisons with a wide range of geolocated and scaled 2D and 3D supports. Nowadays, photogrammetry represents a particular challenge in the underwater field such as environmental monitoring, marine construction, technical inspection, and archaeology. Our study aims to develop underwater acquisition protocols and new tools for marine resources surveys and management to understand the role of 3D characteristics in both coral reefs and artificial structures. Two specific protocols were designed and optimized to reconstruct from coral colonies to coral reefs and artificial structures (up to 500m²) with a mean resolution of 0.05cm/pixel. Here several quantitative descriptors based on 2D and 3D metrics (such as slope, length, surface, volume, rugosity) were calculated for morphological studies and temporal comparisons. The photogrammetric technique now offers higher quality and accuracy tools compared to traditional survey methods. These advantages make possible to access to new scientific surveys of underwater ecosystems and as environmental management tools may prove to be valuable for future.
Subsea Sulfate Removal and Low Salinity Plant Membrane Life Prediction for IOR and EOR
Authors: Haruna Ojonimi Samuel , Hegdal Torbjørn , Huang Xiaofei
Published: August 2021

Subsea water treatment technology for water injection provides a solution for an optimized water injection strategy on both green and brownfield applications. There are no space and weight constraints on the seabed, which enables simple, flexible, and reliable designs.

A full-scale sulfate removal and low salinity plant designed for seabed operation with minimum maintenance intervention has been in operation for ten months without any chemical cleans. This paper reviews the performance results used to predict the life and longevity of a subsea sulfate removal unit (SRU) for a field application in the North Sea.

The ability to reliably predict the potential risks and serving life of a system is crucial for the success of subsea processing equipment. Results from a test conducted over ten months evaluated the key design parameters such as SRU membrane permeate flux, recovery rate, and analyzed membrane fouling behavior during the test period. Lessons learned from the testing are incorporated into the model for more accurate and reliable membrane life prediction.

Field data was analyzed to extrapolate aging factors that are used in the membrane design projection software. The projection software simulated aging performance of the membrane over the membrane lifespan under subsea operation conditions, and the results were applied to determine operating philosophy, maintenance, and intervention interval for the subsea plant. Lessons learned from this field study were discussed and used as guidelines for the next phase full-scale design and practice.

This novelty field practice establishes a break-through step towards full implementation of subsea seawater treatment and injection for increased oil recovery (IOR) and enhanced oil recovery (EOR) purposes. This firsthand data helps the operators to optimize the operation on the seabed, which minimizes the downtime and demonstrates promising advantages of CAPEX and OPEX saving in the long run.
Next Generation High-Definition Geomagnetic Model for Wellbore Positioning, Incorporating New Crustal Magnetic Data
Authors: Nair Manoj , Chulliat Arnaud , Woods Adam , Alken Patrick , Meyer Brian , Poedjono Benny , Zachman Nicholas , Hernandez John
Published: August 2021

Magnetic wellbore positioning depends on an accurate representation of the Earth's magnetic field,where the borehole azimuth is inferred by comparing the magnetic field measured-whiledrilling (MWD) with a geomagnetic reference model. Therefore, model accuracy improvements reduce the position uncertainties. An improved high-resolution model describing the core, crustal and external components of the magnetic field is presented, and it is validated with anindependent set of measurements. Additionally, we benchmark it against other high-resolution geomagnetic models. The crustal part of the improved high-definition model is based on NOAA/NCEI's latest magnetic survey compilation "EMAG2v3" which includes over 50 millionnew observations in several parts of the world, including the Gulf of Mexico and Antarctica, and does not rely on any prior information from sea-floor geology, unlike earlier versions. The core field part of the model covers years 1900 through 2020 andis inferred from polar-orbiting satellite data as well as ground magnetic observatory data. The external field part is modelled to degree and order 1 for years 2000 through 2020. The new model has internal coefficients to spherical harmonic degree and order 790, resolving magnetic anomalies to approximately 51 km wavelength at the equator. In order to quantitatively assess its accuracy, the model was compared with independent shipborne, airborne and ground magnetic measurements. We find that the newmodel has comparable or smaller errors than the other models benchmarkedagainst it over the regions of comparisons. Additionally, we compare theimproved model against magnetic datacollected from MWD; the residual error lies well within the accepted industry error model, which may lead tofuture error model improvements.
A Safe and Cost Effective Diverless Method for Hull Wetted Surface Side Shell Repairs Executed On FPSO Fluminense
Authors: Webb Carl Michael , Sarabi Aidin , Constantinis Daniel Alexander , Anthony Travis Harley
Published: August 2021

The Bijupira and Salema oil fields in the Campos Basin, Brazil, are tied-back to the FPSO Fluminense. The design life of FPSO Fluminense was 15 years, first oil was in 2003. In 2017, Shell as operator and partner Petrobras decided to execute a 5 year life extension project to extend production until 2023. Although the life extension project encompassed many vessel, moorings, and production facility renovation projects, this paper will focus on the repairs of cracks in the wetted surfaces of the hull.

Crack repairs were executed during production operations using a novel methodology designed to eliminate the risks of diving operations, while significantly reducing the costs of the offshore hull repairs.

Earlier attempts using traditional methods with divers to deploy cofferdams were unsuccessful due to the high safety risk of diving in the persistent 2-plus knot Brazil current. In early 2019, the operator and a team of engineering consultants concluded that a novel repair approach that eliminates diving operations was feasible.

The concept methodology was developed, one element of which included positioning and securing a cofferdam over a cracked area of the FPSO side shell. The cofferdam was lowered from the FPSO deck while being guided into position and secured in place by guide wires passed through holes in the side shell. Water ingress into the void spaces was eliminated via a hot tap and winching system that penetrates the side shell from inside the tank.

Following the concept development, a step-by-step procedure was written, vetted with the classification society and subsequently used in the tendering process to select an execution contractor.

The selected execution contractor constructed a test tank that replicated the actual hull structure. The prototype was used to test the method at full scale, including procedures, communication protocols, and equipment. The learnings were incorporated into both the procedures and equipment. This process was repeated as a training exercise for the offshore personnel and HSSE leaders prior to offshore execution.

The execution contractor was mobilized offshore in the first quarter of 2020 and successfully performed the hull repairs. The job was completed as planned, including removal and replacement of several independent sections of stiffened hull plating, which included both flat and curved surfaces.

Based upon successful execution, this method has been proven to be a technology that can be used to eliminate the risks of diving and to significantly reduce the costs of future offshore hull repairs.

This paper will address the methodical approach taken to develop and integrate the various elements of this novel technology developed jointly by the operator and consultants, as well as the phases testing, pre-mobilization surveys, project execution, and other activities that drive success.
Improving Offshore Platform Production With Artificial Intelligence
Authors: Herve Philippe
Published: August 2021

The oil and gas sector is facing a changing market with new pressures to which it must learn to adapt. One of the biggest changes in expectations is the increased focus being placed on carbon emissions. Many consumers, investors, and lawmakers see reforms to the oil and gas industry as one of the most important avenues toward reducing carbon emissions and curbing climate change, and accordingly, a large number of companies have already made ambitious pledges towards carbon neutrality.

New technologies may offer the best avenue for oil and gas companies to reduce their carbon emissions and meet those neutrality goals. Digital technologies—and in particular, artificial intelligence—can aid in decarbonization even with relatively small investments, primarily by enabling large increases in efficiency and reducing unscheduled downtime and the need for flaring. This paper discusses how artificial intelligence-powered predictive maintenance can be applied to reduce carbon emissions, and a case study illustrating a real-world deployment of this technology.
Lost Circulation Risk Mitigation in Deepwater Cementing Operations with a New Tailored Spacer System
Authors: Gorman Angela , Patil Sandip , Agapiou Kyriacos
Published: August 2021

Lost circulation (LC), commonly encountered in drilling and cementing operations, can be a costly problem that increases non-productive time, especially in highly permeable formations. When LC occurs during cementing, zonal isolation can be compromised. Risks associated with LC affect most applications, including offshore operations. This paper presents the evaluation of a new tailored spacer system (TSS) designed to effectively mitigate LC and its use in deepwater cementing operations to meet zonal isolation objectives.
Development and Deployment of the Surface Current Imaging Nowcast System
Authors: Anderson P Steven , Zuckerman Seth , Stear James , Fan Shejun
Published: August 2021

This paper describes the development and installation of an ocean surface current monitoring device called SCINS: Surface Current Imaging Nowcast System. We describe the process of designing and building the prototype system, installation on an offshore platform, implementation of real-time reporting, and results from one year of operations.

SCINS utilizes passive long-wave infrared imaging of the ocean to derive surface currents. This is done using a time-series of images to observe the phase-speed of the ocean waves. Then, the Doppler shift of the observed waves due to the surface current is determined using a non-linear least squares fit. The primary components of SCINS are a long-wave infrared camera and a data acquisition computer. The camera is mounted several 10s of m above the water surface. The system collects imagery at 2 Hz for 5 minutes every 15 minutes, day and night, and calculates surface currents in real-time.

In this paper, we describe the results from deploying SCINS on an offshore platform, Chevron's Big Foot TLP, in the Gulf of Mexico for one year of continuous data collections, including several tropical storm and hurricane events. Results are compared to environmental data to describe system performance as a function of wind, wave, and sea conditions. We describe the engineering challenges and lessons learned from designing and installing this new type of passive imaging system for offshore use. We conclude that SCINS is an effective method for measuring surface currents in the vicinity of offshore platforms, requiring very little maintenance and without the need to put any instrumentation in the water.
Qualification of Barrier Fluidless, Sealless Seawater Canned Motor Pumps
Authors: Stover David L. , Pagani Christian
Published: August 2021

The oil and gas industry continues to push toward subsea pumping technologies that minimize required support systems and increase system reliability. Canned motor technology has been applied successfully in other applications to achieve similar objectives including driving a subsea twin-screw pump. Applied subsea, canned motors eliminate the need for any barrier fluids within the motor, the myriad of systems and complexities necessary to store and replenish these fluids, and the mechanical shaft seals required to prevent the leaking and/or contamination of these fluids within the motors.

As a direct adaptation of proven applications, see Figure 1, subsea water treatment is ideal for canned motor technology. Therefore, a development has been initiated and environment qualification testing of the first truly barrier fluidless, sealless subsea pump solution is complete.

This purpose of the paper is to highlight the novel elements of this technology, review the system configuration, and document the system performance in accordance with the TRL 4 qualification initiative.
Feasibility of the Potential for Wave and Wind Energy Hybrid Farm to Supply Offshore Oil Platform in Gulf of Mexico
Authors: Gu Chengcheng , Li Hua , Haces-Fernandez Francisco
Published: August 2021

Offshore oil and gas platforms use gas turbine with natural gas or fuel diesel for their high demand of power. Due to the declining amount of gas available, high carbon footprint, increasing cost of fuel and inefficient operating, alternative energy options are necessary and imminent. Most offshore oil and gas platforms locate in deep water surrounded by huge amount of energetic wave resources, hence, the feasibility of supplying offshore oil facilities electricity by hybrid wave and wind energy farms based on daily energy power production instead of annual average was conducted in this project. The hybrid energy farm was modeled and validated by applying meteorological data in Gulf of Mexico area from WaveWatch III system. With the hindcast wave and wind condition data from 1979 to 2019, daily energy generation of the hybrid energy farm was estimated. Meantime, the feasibility of suppling offshore oil and gas facilities by the proposed combined hybrid farm was assessed. The project optimized the configuration of the hybrid wave and wind energy farm to satisfy offshore oil and gas platform demands and reduce the variation of power generation, so that it may be feasibility to gradually substitute the gas turbines. Through matching the local wave and wind conditions, the project was able to maximize the power output while minimize the variation within limited ocean surface area. The project addressed the advantages of hybrid wave and wind devices, as well as theoretical prospection of wave harvesting device and wind turbine combination. To validate the proposed optimization model, a case study was explored by using Vesta V90 3MW wind turbines and Pelamis 750kW wave energy converters to supply five offshore platforms in more than 45 m deep water areas. The results indicated the possibility of bringing wave energy into large commercial operation and utilization with minor investment and environmental impact.
Design of Large-Size Suction Embedded Plate Anchors for Permanent Mooring Systems in the Gulf of Mexico
Authors: Chen Jinbo , Heyl Caspar N. , Newlin Jason A. , Karayaka Metin
Published: August 2021

Suction embedded plate anchors (SEPLAs) are an economic solution for the mooring system of a floating production platform and have been deployed both in the Gulf of Mexico (GoM) and around the globe with excellent field performance records. The design of SEPLAs has gradually matured over the past two decades for conventional SEPLAs, but debates continue both in the industry and academia, e.g., on the function of the flap and the required keying. These design aspects become more critical for permanent mooring systems in the GoM where the anchors have to resist large mooring tensions from hurricanes, and balancing safety and economy is a challenge. Thus, the objective of this paper is to present design considerations for large-size SEPLAs for permanent mooring systems in the GoM. The design considerations in this paper include the embedment loss, the functions of the flap and keying, cyclic loading, sustained loading, keying disturbance, and out-of-plane loading. Recommendations are provided to advance the design of large-size SEPLAs, and more specific guidance is offered relative to the ambiguous requirements currently in the industry guidelines.
Umbilical-Less Tubing Hanger Installation Controls System
Authors: Lovland Thor , Lokka Trond
Published: August 2021

The umbilical-less tubing hanger running installation tool, ROCS ("Remote Operated Control System") was first introduced as an R&D project to the market in early 2020. By February 2021, it is in operation for Aker BP in the North Sea on Deepsea Nordkapp.

ROCS is specifically designed to increase the robustness and efficiency of running the production tubing in the well. In a traditional operation, the Tubing Hanger Running Tool ("THRT") normally communicates topside through an umbilical. The ROCS eliminate the controls umbilical by having two methods of communication to the THRT, either acoustic or through wired pipe, preference is acoustic. This also eliminates the topside WorkOver Completion System ("WOCS"). The approximately 16meter long ROCS is also designed with a Ready To Run ("R2R") principle, where the ROCS, THRT and Tubing Hanger ("TH") is made ready on land for offshore operations, already connected and tested.

The system is redundant and based on a closed loop hydraulics, powered by a subsea HPU, electrically supplied from subsea batteries. The SHPU is small in size and power consumption, capable of providing the required flow at 690bar. The control functions occur through electrically held DCV's ("Directional Control Valve") for controlling all of the required TH functions. The ROCS is capable of performing 3 operations of each TH function within the allocated deployed period. The energy required is provided between the hydraulic accumulators and batteries. Pressure balanced accumulators are included to optimize all deepwater operations. A properly sized clean reservoir is installed, interfacing the pre charged accumulators. ROCS is controlled through a modular and user-friendly topside HMI ("Human Interface Machine"), communicating acoustically or through wired pipe over any type communication protocol.

The benefits include removing personnel from red zone, as well as eliminating time to clamp umbilical to the drillpipe. This significantly reduces mobilization of the system to a few hours, which also eliminates the topside deck space considerably. The running time is reduced and allows to increase speed of the drill pipe. This also reduces the risk of damaging production tubing or downhole equipment. There is no risk of downtime due to damaged conduit and the operating weather window is increased.
Case Study: The Impact of VR & AR Simulation Project to Decrease Human Exposure in Critical Environments
Authors: Reis Juan Ribeiro , de Oliveira Thiago Sousa , de Oliveira Wesley Lopes , Barboza Diego Cordeiro , De Melo Leonildes Soares , Oberziner André Luiz Bertoldi , da Silva Paulo Andrade
Published: August 2021

Human exposure is a relevant factor when operating in critical environments and depends on a thorough analysis and consideration towards driving the teams to a safer and more productive environment. Reducing such exposure through digital technologies benefits the whole workforce in their decisions and maneuvers, like simulations, training, and other critical activities that can be executed remotely and prior to the actual activity.

This paper presents a case study to demonstrate how augmented and virtual reality can be used to create a high fidelity virtual environment emulating the real industrial facility. This approach enriches the Digital Twin with the association of data and the virtual environment. It leverages on display and interaction capabilities of hardware devices, and intelligence and data querying capabilities of industrial software, empowering the workers with enhanced training capabilities and access to information increasing safety and efficiency.

A real application of this technology is presented in this paper through the case study of the PredictMain4.0 project of Repsol Sinopec Brazil (RSB), which aimed at the integration of digital technologies, including augmented reality (AR) and virtual reality (VR). The PredictMain4.0 project was executed using data and data models of PETROBRAS’ P-50, a FPSO (Floating Production Storage and Offloading) operating in Brazil, and illustrates how different AR/VR applications can be developed and used in combination with engineering, operation, and maintenance databases. This includes 3D models, digitalized critical procedures, and the ability to integrate field teams into a single virtual environment, allowing real interaction in a digital setting that is linked to the real world. Considering the digitalized procedures, this paper aims to establish how virtual simulation and training can make teams more confident and prepared to execute the same physical asset procedures.

After consulting with stakeholders from many different teams, the PredictMain4.0 project team selected three critical operating modules in the FPSO (Power Generation, Water Injection, and Gas Compression). For each one, considered which situations were relevant, should they occur. These situations led to developing a training and simulation framework, allowing instructors to create different scenarios and use advanced features such as digital measurement, real-time data collection, and collaborative sessions.

The case study indicates that the development of such applications can save more than $1 million per year in maintenance costs considering the decrease in downtime and avoiding risks of accident.
Normalized Modulus Reduction and Damping Ratio Curves for Bay of Campeche Calcareous Clay to Carbonate Mud
Authors: Taboada Victor Manuel , Cao Shuang Cindy , Flores Lopez Francisco Alonso , Cruz Roque Diego , Barrera Nabor Procoro
Published: August 2021

Equations to calculate the modulus reduction curve (G/Gmax-γ) and material damping ratio curve (D-γ) of calcareous clay and clayey carbonate mud of the Bay of Campeche and Tabasco Coastline are developed. This was achieved using a database of 156 resonant column tests and 468 strain-controlled cyclic direct simple shear tests performed in clays with 10 % ≤ CaCO3 ≤90 %. The effects of carbonate content (CaCO3), mean effective confining pressure (σ′m), plasticity index (PI), and overconsolidation ratio (OCR) on the shape of the modulus reduction and material damping ratio curves are shown based on the available laboratory data and the equations developed to calculate these curves. It is shown that as CaCO3 increases, the normalized shear modulus (G/Gmax) curve tends to shift downward and the damping ratio (D) curve tends to shift upward; as σ′m and PI increase, the G/Gmax curve tends to shift upward and the damping ratio curve tends to shift downward; and the value of OCR has practically no effect on the position of the curves. The validation of the calculated values of G/Gmax and D shows the best predictions are found at low shear strains for G/Gmax and at large shear strains for D, falling within ± 25 % of the measured values, and shows that due to limitations in the model at large strains (γ > 1 %) for G/Gmax and at low strains (γ < 0.05 %) for D, the calculated values fall within ± 50 % of the measured values. The equations developed to calculate the curves of G/Gmax-γ and D-γ of calcareous clay and clayey carbonate mud are recommended for preliminary or perhaps even final seismic site response evaluations. However, considering the scatter of the data points around the curves, the equations should be used with caution, and parametric and sensitivity studies are strongly recommended to assess the importance of this scatter. In large critical projects, direct experimental determinations of G/Gmax and D for the soils of interest are suggested to be more appropriate.