bluuebunny/crossref_metadata_2025 huggingface dataset:
Leveraging Targeted Machine Learning for Early Warning and Prevention of Stuck Pipe, Tight Holes, Pack Offs, Hole Cleaning Issues and Other Potential Drilling Hazards
Authors: Payrazyan Vlad Karen , Robinson Timothy S.
Published: April 2023

Stuck pipe and other related drilling hazards are major causes of non-productive time while drilling. Being able to spot early indications of potential drilling risks manually by analyzing drilling parameters in real-time has been a significant challenge for engineers. However, this task can be successfully executed by modern data analytics tools based on machine learning (ML) technologies. The objective of the presented study is to prove and demonstrate the ability of such machine learning algorithms to process and analyze simultaneously a variety of surface drilling data in real-time in order to: a) detect anomalies, that are in most cases invisible to a human eye; and b) provide early warnings of possible upcoming drilling risks with sufficient time in advance, so that the rig crew can execute the appropriate mitigation actions.

The algorithms developed have favorable characteristics, such as adaptiveness to real-time data and agnosticism to well types, BHAs, mud types, lithologies or any other specific well characteristics. This supports out-of-the-box usage, which enables scalability to large numbers of wells. Targeted sub-systems detect the current operation type (tripping, drilling, reaming, etc), and detect symptoms related to differential sticking, hole cleaning issues, mechanical sticking, pack offs, tight holes, obstructions and other risks by analyzing standard surface drilling time logs in real-time, such as hookload, WOB, RPM, bit depth, mud pressure, etc. The ML models and wider risk detection system have been demonstrated to generalize to new wells, and consistently produce high performance across those tested, without any need to pre-train the models on historical data from offset wells.

The system connects to WITSML data stores and outputs warnings with specific information regarding the identified symptom of the potential drilling incident, leaving it up to the rig crew or drilling supervisor to decide how to act on those warnings. The system provides drilling engineers with live warnings on average 1.5-4 hours prior to incidents, giving rig crews enough time to react. This also allows drilling engineers to know in advance a specific source of potential risk, which assists in selecting the right strategy for implementing corrective actions.

The technology's performance was successfully verified in live operations and post-drill studies on historical data on over 300 wells worldwide during the past 2.5 years, with mean recall and precision metrics of 0.986 ± 0.050 and 0.712 ± 0.181 respectively across historical test wells, and significantly reduced occurrence rates of stuck pipe incidents in both onshore and offshore operations. Real case studies for onshore, offshore, conventional and unconventional assets will be presented and discussed.
Mooring Line Failure Detection Using Artificial Neural Networks: An Application to Field Data Including Artificial Failure Cases
Authors: Sidarta Djoni Eka , Auburtin Erwan , Ledoux Alain , Lim Ho-Joon , Leridon Aurelien , Tcherniguin Nicolas
Published: April 2023

Alternative methods to using physical sensors for monitoring the integrity of mooring lines on floating offshore platforms are of great interest in the Offshore O&G industry. These alternative methods can be used in parallel with the physical sensors at the start of the service life of the asset, measurements from the physical sensors can be used to validate these methods, and the validated methods can be vital tools when the physical sensors are no longer working.

Technip Energies has presented ALANN (Anchor Lines monitoring using Artificial Neural Networks) system in a 2021 OTC paper to detect mooring line failure using a dry monitoring system. The system requires only monitoring the positions and headings of the vessel, and it requires information on the draft of the vessel for an FPSO. The system combines status-based detection and event detection to determine mooring line condition, whether they are intact or there is mooring line failure. Artificial Neural Networks (ANN) play a very important role in the status detection with the ability to detect subtle shifts in patterns of vessel motions from intact lines condition to a mooring line failure condition. Numerical algorithms are used for status detection that complements ANN for benign environmental conditions and for event detection.

An ALANN system has been developed, including training ANN models using numerical simulations, for a spread moored FPSO in West Africa. The system has been tested using field data that include time series of easting and northing positions of the vessel, vessel headings and vessel drafts. In addition, field data have been modified to include artificial mooring line failure cases, and these altered field data are used to further test the system. ALANN system performs very well for measured data in good quality independently from the FPSO loading condition, and it is able to detect all the artificial failure cases. The tests confirm and demonstrate how components of the ALANN system contribute to and improve the robustness of the overall solution. Important lessons learned, including challenges that have been encountered due to typical real-life sensor and communication issues (leading to gaps, drift, spikes and/or varying sampling within the data), along with comparison of measured and simulated data are presented in this paper.
Building the Assurance Case for Recovery of Autonomous Underwater Vehicles from Offshore Platforms
Authors: Deeb Amy , Garner Toby , Kuchekar Dipali
Published: April 2023

Digitalization was identified by the International Regulators’ Forum (IRF) as one of three key problems in 2021 due to the petroleum industry becoming increasingly reliant on automated systems. Autonomous underwater vehicles (AUVs) are of particular interest for inspection and maintenance of offshore platform infrastructure; however, the integration of such a complex system requires careful mitigation of safety health and environment risks associated with its operation. Analysis of human factors, including ergonomics, job organization, and cognitive considerations, has been recommended by the IRF to increase confidence that the interaction of the operators and the equipment (manually controlled, automated, or autonomous) permits safe delivery of the system capability in a safe working environment. The established CRitical Intervention and OPerability (CRIOP) analysis methodology is chosen as the basis for constructing an assurance case for an AUV control station on an offshore platform. CRIOP's goal is to show that the control center is able to safely manage all modes of operation.

This paper proposes a CRIOP Assurance Case Template for a control station on an offshore platform. The proposed template uses goal structuring notation (GSN) with arguments, assumptions, and solutions, following the strategy of the CRIOP methodology. This template supports a critique of CRIOP's completeness arguments, goal-based structure, and solution acceptance criteria. Next, an assurance case for an AUV recovery operation is instantiated from the template for three cases with different autonomy levels: manual, automated with a human-in-the-loop, and autonomous. The increasing level of autonomy was shown to result in both technical and methodological variances to the assurance case including: layout changes as the control station moves from the open deck of a boat to a control room; changes in the acceptance criteria for the expertise of analysis team members; and the recommendation for additional scenarios that address situations in which the level of autonomy must be decreased due to safety concerns. Interviews with experienced AUV operators and developers revealed the value in including operators in the CRIOP analysis team to increase operator confidence in being able to maintain meaningful human control in all modes of operation. It is only with this confidence that autonomous systems will be used for the ambitious missions they can perform.
A Novel Subsea Connector for Repairing Clad Pipelines
Authors: Mattarucco Riccardo , Trevisan Alberto , Giudicianni Carlo , Lucchese Francesco , Toso Gianluca
Published: April 2023

Subsea pipeline repair connectors have been used in the oil & gas industry for many years and are considered a valid and safe way of repairing major damages and restoring the original pipeline condition in case of an emergency repair; they can also be used for tie-ins to allow extensions by connection of new pipeline sections to an existing one and they have an extensive track record mainly on carbon steel pipelines but are fit also for stainless steel and duplex pipelines. The increasing number of subsea pipelines with internal CRA cladding which have been deployed in recent years and are foreseen in the future poses new technological challenges since conventional sealing solutions are not suitable for or have limitations in this specific application: in this case the repair connector not only needs to be designed to be compliant with the sour product but it also needs to protect the pipeline carbon steel wall from coming into contact with the internal fluid. This paper presents a new concept of a pipeline repair connector that has been developed from the beginning specifically to target repairs on sour service lines and in particular on clad lines.

This innovative repair connector is based on a metal to metal sealing technology that offers permanent repair without any reduction of the pipeline's internal diameter, provides a versatile diver/diver-less solution, can deal with multiple wall thicknesses and can also be applied to other types of pipelines, such as those for sour service with internal corrosion allowance since it can manage pipe wall thickness reduction over time.

The design of the mechanical connector has been carried out in compliance with DNV pipeline codes after a comprehensive technology qualification testing campaign under DNV certification and focused on medium size pipes. A full-scale 26″ prototype connector has been designed and fabricated for completing the qualification testing program including all required pressure and loading conditions. FEM analyses of the testing configurations have been carried out for comparison with test data so to validate the FEM models and extend results to other sizes within a predefined range. The matching between the experimental data and FEM calculations has allowed setting up a Type Approval process with DNV and, after a design effort covering various pipeline sizes and types, the connector will be certified for a wide range of large bore pipelines and design conditions and be ready for release to the market.
Eliminate Section Milling in Plug & Abandonment Applications with Liquid Thermite
Authors: Levchenko Andre , Clark Billy Ross , Carragher Paul John
Published: April 2023

This paper presents a novel technique for section milling that decreases costs involved in preparing a section of an oil and gas well for permanent P&A. Testing results have shown that this novel technology is capable of melting steel tubulars, control lines and associated clamps in fluid at pressure in both laboratory and well environments. Laboratory work provided data to develop models for window length predictions based on length of thermite column used, and well pressure predictions during the thermite reaction. Melted window lengths of as long as 2m have been achieved in large-scale testing and field trials, along with validation of predictive models. This leap forward in section preparation technology will save millions of dollars of operational expense compared to traditional section milling methods for P&A. Combined with alternative barrier materials such as Bismuth-based alloy plugs this novel technology will be truly rig-less P&A solution for oil and gas well that have reached the end of their lifecycle.
Top of the Line Corrosion Management for Wet Sour Gas Subsea Pipeline
Authors: Abbas Faisal M , Ganugapenta Venkateswara R , Ghurab Abdullah A , Alharbi Abdulwahab B
Published: April 2023

Gas sustainability mandates effective pipeline corrosion management programs, especially for wet sour non-associated gas trunklines. This paper highlights the reengineering of top-of-line corrosion (TLC) management for wet sour gas subsea pipelines. The paper details the strategies adopted for improving the existing V-jet batch inhibition treatment program and summarizes the latest research efforts in sour top-of-line corrosion prediction modeling and effective alternatives to V-jet batch inhibition.

Risk-based methodologies are adopted for ascertaining the batching frequency for TLC inhibition in the sour subsea pipelines. Corrosion monitoring data coupled with Inline Inspection data are used for comparing the actual corrosion rate against the model predictions. Laboratory analysis are performed to evaluate the efficacy and persistency of the corrosion inhibitors. Field trials are performed to validate proposed scraping frequency optimizations. Field corrosion data is used for improving the TLC modeling through a joint industry program.

The methodologic approach materialized significant improvements in operations and integrity management of long subsea pipelines. Pipeline scraping frequencies and associated chemicals consumption are reduced, flaring is minimized, and the processing capacity of existing assets is increased. The efforts have also resulted in improving field avails and reduced facility downtime and maintenance efforts. Joint Industry Programs resulted in improved TLC modeling and initiated the development of standardized testing protocols for Vapor Phase Corrosion Inhibitors and Batch Corrosion Inhibitors. Additionally, improvements are made in the aspects of 1. Facilities, and 2. Processes and Practices for improving subsea pipeline integrity management.
High Precision Seabed Deformation Monitoring
Authors: Davis Eric , Krug Ralf , Debastiani Deyvid , Oliveira Camylla , Pereira Leonardo Cabral , Rachid de Araujo Marco Aurelio
Published: April 2023

Deformation monitoring has been conducted on land for many decades to observe fluid movement in reservoirs, determine hydraulic fracture orientation, and confirm cap rock integrity. The three technologies currently in common use for land-based deformation monitoring are: electrolytic tiltmeters, GNSS and InSAR (Interferometric Synthetic Aperture Radar). Each technology has a different set of strengths and weaknesses, which are in many ways complementary. Tiltmeters have a high temporal rate and provide far higher precision than GNSS or InSAR but require careful instrument layout planning to ensure that precision translates from gradient changes to elevation changes. The uncertainty from tiltmeter arrays also increases with time if there is no absolute reference in the array. GNSS is much lower precision and relatively high cost per installation, but its stability over time can mitigate long term drawbacks of a tiltmeter-only installation. InSAR has a limited temporal rate and can suffer from uncertainties due to a variety of causes, but the enormous coverage area that is often available with minimal or no ground instruments makes it a strong asset in many monitoring programs.

GNSS and InSAR both rely on microwave frequency signals, and so are not directly applicable in the subsea environment. Acoustic analogs exist, but only with lower resolution that renders them of very limited use for monitoring small deformations, including those induced by most processes that are well below the seabed. Tiltmeters can be used in the subsea environment, but deployment methods to date, mostly by the scientific community for seamount and tectonic fault monitoring, have placed instruments directly on the seabed and suffered the consequences of low precision. Instruments on land are typically buried 6 to 12m to isolate them from noise sources at the near surface, which are primarily diurnal thermal disturbances. Best precision typically requires maximum thermal excursions on the order of 1e-3 C near the instrument. Since even the deep ocean generally experiences temperature fluctuations of several tenths to several whole degrees C, placing the instruments on the seabed severely limits the usefulness and application range. A new deployment mechanism enables mechanically and thermally stable placement of tiltmeters in seabed sediment at depth, with acoustic transmission for data retrieval. High resolution tilt measurement of the seabed allows the same diagnostics previously only available on land to be obtained in the more challenging and higher consequence offshore environment.

An array of instruments deployed off the coast of Brazil in March 2021 is furnishing key information on reservoir fluid balance, providing insight into the impacts of changes in injection and production and enabling better decisions on reservoir management.
A Machine Learning Approach to Improve the Reliability of Aging Tendon Tension Monitoring Systems
Authors: Ng Jimmy Keong Tark , Maroju Soma Sekhar , Das Suvabrata
Published: April 2023

Tendon Tension Monitoring Systems (TTMS) are commonly installed on Tension Leg platforms (TLPs) to measure the axial tensions in the tendons. These measurements are essential to the weight management of the platform, and in monitoring their fatigue life. The TTMS typically consists of 3 load cells per tendon, with 2 bridge measurements for each load cell. This makes up to 6 tension measurements per tendon allowing for a good number of redundant measurements for tendon tension determination. This system design with redundant measurements allows for long term integrity monitoring of the TLP, and some of these systems have been in operation for over a decade. However, the degradation of the load cells over time due to harsh environments, wear and tear, reduces the reliability of the tension measurement system.

This study investigates the use of machine learning (ML) to model tendon tensions using historical TTMS data with reduced number of reliable tension measurements. Building models, training and validation of these models are evaluated and presented to demonstrate how ML can provide reasonable tension estimates and help extend the useful life of the TTMS. Outputs from these models are presented and discussed, with a focus on accuracy in relation to the number of model inputs. Observations from models simulating reduced inputs with no TTMS measurements from at least one tendon are elucidated. This paper demonstrates how ML from TTMS data can estimate tendon tensions reasonably, with a reduced number of reliable measurements. Implementation of these techniques can help to extend the useful life of these TTMS.
Evaluating an Area of Review for CO2 Sequestration and Storage: A Subsurface Modelling Workflow Tied to Regulatory Guidelines
Authors: Umrani Rahul , Jones Ryan , Ware Chuck , Janise David , Ozah Robin , Joshi Nikhil
Published: April 2023

In United States, decarbonization of Carbon Dioxide (CO2) intensive industries is becoming a priority to meet the goals of the ‘Paris agreement’ which is to limit global warming to 1.5 °C. CO2 capture and sequestration (CCS) is an efficient technique to reduce anthropogenic carbon emissions and curtail the impact of climate change. CCS involves capture and permanent underground storage of CO2 which would otherwise be released into the atmosphere into deep saline or depleted hydrocarbon reservoirs. Selected Oil & Gas Exploration and Production companies with upstream expertise are exploring CCS to reduce the broad industrial CO2 footprint. Sequestration of CO2 in the subsurface requires robust techniques to be implemented to monitor the progression of the CO2 plume and the consequent increase in subsurface pressure. The regulatory authorities therefore require evaluation of an Area of Review (AoR) which is a project area that is under the influence of CO2 injection activities. AoR is defined as the project area in which elevated injection zone pressure may cause upward migration of formation fluids into the closest underground source of drinking water (USDW) through a potential geological or mechanical leakage pathway.

Pursuant to the Underground Injection Control (UIC) program, US Environmental Protection Agency (EPA) regulates CO2 sequestration wells by the enforcing Class VI permits. Only five Class VI permit applications have currently been reviewed and approved by EPA and state regulatory authorities (USEPA 2023). In this fast-evolving CCS space, understanding key terminologies of the Class VI permit such as AoR is one of the challenges faced by the industry. The aim of this paper therefore is to explore the AoR concept as stated in the US Code of Federal regulations, provide an interpretation of key terminologies involved and demonstrate how a reservoir modelling workflow can be utilized to delineate an AoR.

The study summarized by this paper employs a conceptual saline reservoir model developed with geocellular property and facies modelling that is representative of a certain US Gulf Coast area. This model is dynamically simulated by incorporating CO2 – rock interaction flow physics. Reservoir simulation provides predictions of subsurface movement of the CO2. These results are coupled with current guidelines provided by the regulatory authorities to evaluate the AoR as the CCS project progresses over time.

Continuous evaluation of AoR provides a robust level of due diligence to prevent the CO2 plume from encountering geologic and mechanical leakage pathways to the surface or overlying sources of drinking water. This technique can also be utilized to prevent the CO2 saturation front from exceeding acreage boundaries that have been prescribed for CCS.
Subsea Tool for Hose Retermination Using ROV
Authors: Corrêa Ygor fernandes Dos santos manhães , Santana Andre luiz Bevilaqua , De souza Douglas oliveira Correa , Junior Ricardo Nascimento deslandes , Schueng Hugo Martins
Published: April 2023

Offshore oil and gas production systems comprise a variety of subsea arrangements dedicated to serving production platforms and export lines. Hydraulic systems are widely used in offshore production systems, particularly for control and operation of Wet Christmas Tree, Manifolds, Valves and others equipaments. Subsea umbilical hydraulic fluid leaks are a problem for the oil industry because they cause environmental damage and involve equipment downtime with financial losses associated with oil and gas production. Leaks, mostly internal, represent one of the most common failures in hydraulic systems.

The Campos Sedimentary Basin occupies a marine area located in the region from the central-northern part of the state of Rio de Janeiro to the southern part of the state of Espírito Santo. This field comprises a geological structure that has provided the accumulation of the remains of marine organisms over millions of years. The region currently accounts for about 30% of the entire national production and there is still a lot of potential to be developed. Within the company, there are approximately 280 producing wells in operation, approximately 7,000 employees working on the most diverse fronts, and 25 offshore platforms in operation.

This paper presents a study of solutions developed to contain leaks in hydraulic umbilicals, using robotic techniques with ROV support. The anomaly that occurred in equipment connected to the PGP-1 in Campos Basin, resulted in significant losses. The area responsible for studies and the company's underwater repair service is responsible for designing and developing solutions for repair services for rigid pipelines in contingency situations and support in the inspection and maintenance of pipelines and underwater equipment.

In the past, the repair or replacement of subsea umbilicals was done with the assistance of human divers, more precisely in the saturated mode. This type of assistance is a methodology that presents high risks to the safety of the professionals involved. Another relevant issue is the high costs involved in renting a Diving Support Vessel - DSV and the limitations of using this vessel in adverse environmental conditions (wind, current, wave height, etc.).
ETH-PiP 2.0 Experience from Fenja EPCI
Authors: Marret Antoine , Helland Torgeir , Papore Eddy , Le-Naour Frederic , Pratt Ed , Vivet Romain , Møller Fredrik Andreas , Haugen Knut Edmund
Published: April 2023

This paper presents the foundations as well as the main outcomes of the development, industrialization, fabrication and installation of the TechnipFMC's Electrically Trace Heated Pipe-in-Pipe (ETH-PiP) 2.0 for application on the Fenja field development.

The Fenja Field is located offshore mid-Norway at a water depth of approximately 324m, and consists of two separate hydrocarbon accumulations, the Pil and Bue reservoirs, with fluid properties leading to flow assurance challenges such as hydrates and wax formation. Following successful deployment of a first generation of Electrically Trace Heated Pipe-in-Pipe on the TotalEnergies (then Total) Islay Field in 2011, TechnipFMC have conducted the development and industrialization of a completely new generation of ETH-PiP 2.0.

The new ETH-PiP 2.0 has higher electrical rating of 3.8/6.6kV to overcome the specificities of the Fenja field development including the long tie-back distance of 36.8km which makes Fenja the longest (and largest) ETH-PiP in the world.

Subsequent to successful qualification of the ETH-PiP system, TechnipFMC has completed the manufacturing of 36.8km of ETH-PiP stalks at the Evanton spoolbase. These were then loaded out onto the Deep Energy pipelay vessel for subsea installation by reel lay.

The installation was finalized in summer 2021 with the complete system being connected and tested from the Njord A platform after it returned from refurbishment in spring 2022.

This paper presents the qualification, industrialization, assembly and installation of the new generation ETH-PiP 2.0 which forms part of the Fenja field development.
Electrification Solution for Greenfield and Brownfield Facilities Utilizing Offshore Floating Microgrids, as an Alternative to Power from Shore
Authors: Maisey Joel Alan Brant , Brown Steve
Published: April 2023

The United Kingdom (UK) is driven to reduce offshore emissions by the North Sea Transition Deal (NSTD) agreed between industry and the government in March of 2021. This agreement requires the UK offshore industry to reduce emissions against a 2018 baseline, with interim goals on route to being net zero by 2050. The most pressing target is a 50% reduction by 2030.

To achieve these goals, groups of facility operators and their Joint Venture (JV) partners have begun progressing power from shore solutions exclusively, thus not considering alternative electrification concepts. As a result, the North Sea Transition Authority (UK regulator) launched "The Decarbonization competition for the electrification of offshore oil and gas installations", working with the Department for Business, Energy & Industry Strategy (BEIS), to fund technical and commercial studies on alternative offshore electrification in the UK North Sea. With the benefit of this support, the Orcadian consortium has developed an off-grid, or Microgrid, approach to platform electrification, as an alternative to power from shore.

The Orcadian consortium Microgrid delivers a practical and achievable solution, enabling field operators to meet and likely exceed the North Sea Transition Deal emission reduction commitments The key benefits of the Microgrid are: Emissions reductions – approaching an 80% reduction for offshore facilitiesLower costs – saving almost $2 billion and more than 25% cheaper than the power from the UK grid option, when capital and ten years of operating costs are included, for a subset of platformsA practical way for operators to meet their North Sea Transition Deal commitments in terms of both the emission reduction targets and timeframeDeliverable quickly, and in phases, which allows a staged deployment with a steadily improving reduction in emissionsOpportunities for re-use or redeployment – provides legacy infrastructure for the grid and/or other usersApplications beyond oil & gas to provide reliable, low carbon power to industry or national power grids.
Efficient Welded Joint Sealing System for Pipe with Thermoplastic Liners
Authors: Sears Ryan M. , de Oliveira e Silva Jose Anisio
Published: April 2023

Thermoplastic pull-through liners are an effective method or preventing corrosion of carbon steel pipe. Offshore pipelines using thermoplastic liners require a means of welding pipe joints without damaging the heat-sensitive liner. Methods used to date include the use of corrosion- resistant alloy (CRA) connectors that place the plastic liner far enough away from the weld zone to prevent heat from damaging the liner, and thermoplastic connectors that utilize insulation and/or an annular air gap to prevent heat from damaging the plastic liner at the weld zone. In the case of the latter the thermoplastic connectors require electrofusion welding of the connector to the liner in the pipe, which is time consuming.

This paper reviews the design and shop tests of a welded joint sealing system that permits the use of insulating thermoplastic connectors that seal to the liner in the steel pipe by means of a mechanical seal. This welded joint sealing system permits far faster joint assembly in the field than other methods, by avoiding the time-consuming processes of CRA welding or electrofusion of the thermoplastic connector to the thermoplastic liner in the steel pipe. The joint assembly process on a lay barge takes seconds per joint and is orders of magnitude faster than other methods, making it economically feasible for use in J-Lay and S-Lay vessels.

Hydrostatic pressure tests have proven the welded joint sealing system to consistently prevent liquids from reaching the weld zone at pressures exceeding 500 bar. The key to achieving the mechanical seal is the novel means of locking the thermoplastic liner to the steel pipe wall. By preventing the liner from moving inside the steel pipe, it is possible to provide a fixed seat for the thermoplastic connector to seal against.

Weld tests have proven that weld quality is unaffected by the connector and that heat exposure to the connector is below the degradation threshold of its thermoplastic material.

The welded joint sealing system provides a cost-efficient, highly repeatable means for protecting the weld zone of thermoplastic lined steel pipe from corrosion. It makes it economically feasible to use thermoplastic liners for the transport of corrosive and hazardous liquids, including the use of specialty thermoplastic liners in case of high temperature sour oil and gas.
An Innovative ROV Tool for Inconel Strap Installation and Life Extension of VIV Strakes Secured to Deep Water Production Jumpers
Authors: Ziero Loris , Lazzarin Diego , De-Amicis Luca
Published: April 2023

The paper presents a unique innovative ROV Tool that is used to install Inconel straps on pipes, spools and jumpers. The tool was developed and built by Saipem Sonsub, in 2020; The tool has been operated (in ultra-deep water), during the past two years, in some offshore campaigns to install Inconel straps on jumpers, to further secure VIV strakes, ensuring the jumper service life, thus avoiding the possible need to recover them on board for strake reinstatement.

This innovative ROV Tool was designed and built starting from the proven packaging industry process and technology for metal strap installation without sealing clip. The installation process was replicated, reviewing and radically modifying the original technology to cope with the operative and environmental constraints related to subsea ROV operations and the specific need to allow the straps to be installed in any possible orientation. The paper provides an overview of the installation process and main features of the Tool including details and results of the performed operations, also focusing on possible further subsea applications that this new tool now allows, with some minor adjustments.

This Tool is conceived as a special end effector to be handled through a WROV manipulator and requires a dedicated skid to be connected beneath a WROV of convenience for Power & Control. The tool is currently configured for pipes with an OD of approx. 450 mm but can also be applied to different sizes, with minor adjustments. The subsea operational sequence is:

Tool positioning using the WROV and/or its manipulator, pipe grabbing where the strap has to be installed, closing the two shaped jaws of the tool with strap channels/guides Strap feeding all around the pipe, with final strap tip locking Strap tensioning to wrap the pipe Strap crimping and cutting with subsequent jaw opening and disengagement of the pipe

A reel houses the Inconel strap; the current capacity is approx. 130 m of strap, allowing the installation of multiple straps without the need to recover and replace it. The skid houses a movable trolley with a cradle and a set of latches to secure the Tool itself. In the water, the Tool is neutral, and once undocked from trolley, it is handled by the ROV manipulator/s; a pair of movable buoys manage its in-water righting moment, helping for its rotation.

This type of subsea intervention had never been performed in deep water. The ROV Strapping Tool, beyond its achievements for VIV strake securing in deep water, can now open the way to further different applications. Diverless repair operations, securing of piggyback cables or other items to pipes (e.g.: repair patches or monitoring devices), in deep and ultra-deep water, can be now achievable by means of single or multiple strap installation, using only ROV/s.
Achieving Safe and Expedited Facility Start-Up and Production Under Abnormal Situation
Authors: Chong Ching Lih , Goh Janet Anne Siaw Ling , Adnan Imran bin , A Manan Nur Syafiqah binti
Published: April 2023

This paper describes the implementation of phased start-up and operating strategies to achieve safe and expedited production resumption from Field B after an incident that caused damaged production facilities due to the collision of a marine vessel with an interconnecting bridge between platforms.

Phased facility modification plans were implemented to gradually remove constraints and bring production facilities back online. The start-up and operating strategy were tailored to constraints and available production facilities at each phase. Phase 1, achieved through minimal facilities modification, leveraged on the availability of natural-flowing high-pressure gas wells as gaslift source to gas-lifted wells. Phase 2, with further facilities modification, resumed normal gaslift supply from gaslift compressor. Installation of flexible pipes in place of damaged piping brought about the flexibility of gas tapping from vicinity field for start-up purpose. The same flexible pipes were used to enable gas and additional liquid export. Utilization of pipeline line-pack volume as gaslift compressor start-up feed and fuel gas source was available as alternative Phase 2 start-up strategy.

Phase 1 start-up was achieved within 45 days and operational for 120 days, recovering on average 1.3KBD of oil production. The introduction of a warm-up sequence effectively mitigated hydrate formation risk. Formulation of a robust crude oil transfer pump control strategy allowed the pump to operate in stable region despite low flow. Subsequent implementation of Phase 2 concept, which was operational for 490days, brought online 3MMSCFD of gas sales and 8.9KBD (a further 54% of Field B nominal oil production rate). Implementation of enhanced process monitoring, control, and safeguarding measures mitigated risk with high flowrate of HP gas through flexible pipe. Flexible pipes were also successfully deployed to evacuate crude production and process drain liquid to export lines. Through comprehensive hazard analysis and Management-of-Change (MOC) program, execution of facilities modification work, start-up, and operating the facilities under abnormal condition were safely accomplished, alleviating production deferment impact due to the incident.

The approach as described in this paper would provide a good case study for other facilities constrained by similar issues and how the associated risk can be effectively mitigated.
Geohazards in Riserless Drilling for an Exploration Well in Deepwater GoM: Identification and Mitigations
Authors: Bui Huyen , Hasanov Azar , Mendoza Legna , Rowe Shawn , Ontiveros Paul , Mennie James
Published: April 2023

A Geohazards assessment for the riserless section is critical in offshore drilling operations, especially in deepwater environments, such as Brazil or Gulf of Mexico as there is no blowout preventer (BOP) being utilized in this section of a well. If there is any occurrence of geohazards issue without control, then it can have negative impact on human safety and the environment. Geohazards prediction and mitigation in the riserless section requires a multidisciplinary approach with specific types of data from seismic (high resolution recommended), site survey data (multibeam, sub bottom profiler, high backscatter, offset well information (mud weight, drilling trouble events) and most importantly, the geological understanding from regional to local scale.

This paper presents critical input data and an integrated workflow of how to identify potential geohazards and respective mitigations for planning a deepwater exploration well in Gulf of Mexico. Not only does it provide a perspective view about the geohazards prediction process, but it also shows the actual outcomes from drilling results. We will use a case study well as an example to illustrate the assessment procedure. This well was identified as a challenging well with complex shallow geology in the riserless section. Drilling trouble events were observed in most of the offset wells in the same geological setting with gumbo, tightspots, shallow water flow and shallow gas. High-definition seismic data was recommended and incorporated into shallow subsurface interpretation and geohazards prediction. We derisked the uncertainty of riserless drilling through the shallow section of the prospect area for upcoming wells, and successfully drilled the riserless section despite the challenging shallow geology.
Business Case for WEC Networks Enabling the Ocean Internet of Things
Authors: Davidson Ryan
Published: April 2023

The blue economy has an estimated value of $1.5 trillion annually, which is predicted to double by 2030 (NOAA, 2021). As R&D funding for wave energy converters (WECs) continues to rise globally, wave power costs are anticipated to fall; this, in tandem with unstable oil prices and unfavorable conditions for deploying small-scale offshore renewables like solar and wind, is likely to lead to the widespread adoption of networks of small-scale WECs. Using a comprehensive market-sizing approach, this paper analyzes the business case for these WEC networks, which have the potential to enable offshore industries to benefit from an "Ocean Internet of Things," or O-IoT. This market analysis reveals not only the blue economy industries most ripe for adoption, but it establishes the idea of "increasing marginal returns" for the wave energy industry stemming from widespread network effects, contrary to the "diminishing marginal returns" dominating most industries. Networks of small-scale WECs, with average power outputs around one kilowatt, will likely unlock immense value in mature, growing, and embryonic offshore industries. In a mature industry like oil and gas, WECs may enable operations like remote sensing and pipeline inspection. In a growing industry like aquaculture, WECs may enable operations like feeding and fish stock monitoring. In an embryonic industry like coral reef restoration, WECs may even enable operations like seawater electrolysis for mineral accretion. While the blue economy is expected to continue outpacing the global economy through 2030, this paper concludes that robust networks of small-scale WECs may enable this growth even further. As oil and gas and other offshore industries set sustainability targets for 2030, 2050, and beyond, WEC networks present a novel approach to decarbonize operations while unlocking new value.
Experience with Deploying HIPPS in Subsea Production and Processing Systems
Authors: Sen Raj , Kent Ian , Ali Mohammad Hasan , Free Nathan
Published: April 2023

Challenges associated with High-integrity Pressure Protection System (HIPPS) design, assembly testing and commissioning are presented in this session. It is based on the experience of completing 10 projects successfully over last decade. The method involves reviewing various logs at different stages of a project lifecycle and determining the root cause of the challenges faced. Implementation of the process control methods around design and assembly demonstrates the benefits of continuous improvement. The trend of issues experienced over time also demonstrates the effectiveness of close loop feedback process existing in the infrastructure. The paper details how functional safety management principles can be applied to the supply of HIPPS systems, from the development of Safety Requirements Specification, through development of the Safety Instrumented System (SIS), Verification & Validation of the (SIS), Commissioning the SIS, Operation and Maintenance of the SIS, and finally decommissioning the SIS. The paper also discusses the impact of functional safety on the subsea control system, and the requirements of the functional safety standards IEC 61508 and IEC 61511 (and ISA 84.00.01), and how these standards impact both the supplier and the operator of the HIPPS. The paper highlights the maturity of the High Integrity Pressure Protection System solution, and the track record of these systems once deployed. Lessons learned spans over 20 years and across 10 projects involving 25 systems. They are distributed in the areas of design, functional safety assessment, interface management, supply chain, testing and commissioning. Given the low volume of product solutions and safety considerations, it is necessary to determine cause of "every" anomaly beginning from design analysis through life of field. Lessons learned and experience in managing challenges form critical part in deploying technically sound HIPPS units in a timely manner in future.
SCC-CO2 Failure Mode: Literature Review and Available Technologies Used to Inspect and Access the Integrity of the Flexible Pipes
Authors: Vasconcelos Ferreira Lobo Cicero , Ribeiro Mario Luis
Published: April 2023

In 2017, after a failure of a flexible riser operating in an environment with high level of CO2, a new failure mode of the flexible pipes was reported: Stress Corrosion Cracking induced by CO2(SCC-CO2). This issue was not considered in the design and manufacturing standards of these equipment. In this context, this paper covers a literature of SCC-CO2 phenomenon. Moreover, the impacts on the flexible pipes due to this failure mode are discussed. Lastly, this research focuses on the current technologies and tools used to inspect and access the integrity of the pipes used on gas injection and production lines. The paper is written based on detailed review of the literature. A set of relevant keywords were used on peer-reviewed journal articles and conference papers mainly available in the OnePetro database. Some recognized books, technical specifications and PhD thesis were also consulted. The papers included in this literature review were selected based on four steps: identification, screening, eligibility and inclusion (Moher et al., 2009). This methodology allowed to find out what is the current state of the art about the topics covered in this study. This detailed review of literature revealed that after the issue reported in 2017, the industry invested in the research of the SCC-CO2 phenomenon. Many studies were conducted in order to investigate what are the main factors that triggers this failure mode on the flexible pipes used for the production and gas injection in the deep-water and ultra-deep-water fields with high levels of contaminants and harsh metaocean conditions. Then, different technologies and tools were developed to inspect the flexible pipes. Operators can use this data to estimate the remaining service life of the lines. There are proven tools that can inspect the gas injection pipes using different non-destructive techniques. However, there is still a gap on the inspections of the annular region of the production flexible pipes. This happens due to the limitation of reading through the thermal insulation layer contained on them. This is very critical because the inspection of the pipe annulus detects if it is dry or flooded. This information is vital to assess the integrity of the structural armors of the flexible pipes.
Controlling Undesirable Water by Applying a Composite of Nanosheet and Viscoelastic-Surfactant Based Foamed Gel
Authors: Alarawi Abeer A. , Almohsin Ayman M , Busaleh Ahmad S
Published: April 2023

Excessive water production is one of the significant phenomena of reservoirs worldwide that influence oil production and costs. At the same time, a comprehensive collection of treatments is available to solve this issue, such as mechanical water shutoff, polymer-based gel, and crosslinkers-based gel. However, they all possess drawbacks, including but not necessarily limited to surface mixing and handling problems. Foamed gel systems can enhance oil production by plugging the high water permeability zones due to their physical plugging, adsorption, dynamic trapping, and in-depth injectivity. In this study, a novel foamed gel system containing a composite of nanosheet material (NS), and viscoelastic surfactant (VES-SURF) was developed for inhibiting undesirable water in different watercourses of high permeable zones (zones far away from well, transient zones, and near-wellbore zones). The NS/VES-SURF-based foamed gel is prepared at the surface facility and then injected to control gelation time and gelling certainty.

The foamed gel stability, foamability, and rheology were examined at 77-200 °F. Foam loop rheometer experiments were conducted at 1500 psi, and 70% N2 quality to assess foamed gel rheological properties and stability at dynamic conditions. High-resolution optical microscope was utilized to detect the foam morphology and stability altering with time stability. The gelation time of foamed gel was calculated at 77-200 °F. A viscometer was also used to measure the viscosity and thermal stability of VES-SURF and NS/VES-SURF-based foamed gel systems at 100-200 °F.

The experimental results demonstrate that the VES-based foamed gel system converted to gel within two days, while NS/VES-SURF foamed gel requires only ninety minutes. In this foamed gel system, the gelling time can be easily controlled by altering the concentrations of NS and VES-SURF. Moreover, the VES-SURF-based foamed gel system was stable for ten days at room temperate. In contrast, NS/VES-SURF foamed gel system was stable without any phase separation for 35 days. VES and NS/VES-SURF-based foamed gel systems’ viscosity was 1000 and 1500 cP at 100 °F. Increasing the temperature to 200 °F enhanced the viscosity of foamed gel systems to reach 3500 cP for NS/VES-SURF and 2000 cP for VES-based foamed gel systems.

The NS/VES-SURF-based foamed gel characterizes by high mechanical strength, low volume, less damage, and lower cost than the traditional gel systems. In addition, the NS/VES-SURF foamed gel system is stable in harsh environments, including high temperatures, salinity, and pH. Once gelation occurs, gels do not flow and distribute along the rocks due to the high viscosity of the invented system.