bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fenja Digital Twin with Automated Advisory: A Solution for Operational Excellence
Authors: Forooghi Alireza , Trudvang Christian , Gupta Gaurav , Kjoerrefjord Gustav , Karimi Hassan 
Published: October 2022

Abstract
In this paper we describe the Fenja Digital-Twin solution, its automated advisory workflow, and how it enhances operational excellence and further strengthens the operational health, safety, and environment (HSE) vision of Neptune Energy. The Fenja development is a subsea tieback to the Njord-A platform located in the Norwegian Continental Shelf. Fenja wax and hydrate management strategies are based on active heating of the world's longest electrically traced heated pipe-in-pipe (ETH PIP) as the primary layer of protection.
The Fenja development demands a reliable and robust solution to address flow assurance challenges and support operational activities planning (production management, shutdown, startup, virtual metering, hydrate/wax formation preventions, ETH pipeline operation, and chemical tracking). A digital twin solution deployed for the Fenja development uses the integrated power of machine learning and data analytics with multiphase flow simulation, enabling enhanced efficiency and transforming operations.
The Keep-Warm and Warm-Up advisory workflows help reduce carbon dioxide (CO2) emissions to the environment by optimizing the ETH pipeline power consumption and empowering the operational decision-making process for operations.
Leak detection advisory (LDA) uses data analytics, signatures analysis, and pattern recognition to rapidly detect potential leaks of fluids from hydrocarbon pipeline. Combining digital twin with data analytics makes detecting leaks more precise and avoids false alarms. A faster and highly precise LDA advisory can potentially minimize a great deal of hydrocarbon loss to the environment in a real leak event. In the test environment for the factory acceptance test, the LDA was able to produce an alarm within 1 hour after the onset of a small leak (1% of pipe diameter) and within 15 minutes for a moderate (&gt;3% of pipe diameter) to large leaks.
A vast amount of real-time distributed temperature sensing data (at every 3-m distance, a total of 34,000 data points) along the entire length of the ETH pipeline and riser are continuously collected offshore and then fed into the advisory module. A customized automated workflow is developed to process this enormous amount of near real-time data to be used in calibration and to provide useful insights to the end user.
New methods, using machine learning and data clustering techniques, are used to develop specific automated advisories. The digital twin with automated advisory runs automatically and needs minimal to no intervention, providing operational awareness and actionable insights to decision-makers in real time. The integration of a "replay" functionality to rerun historical actions performed in the field and "look-ahead" functionality for future predictions in a collaborative environment makes the Fenja Digital-Twin solution an essential tool for operations.
Generation of Complex Emulsions During the Application of Improved Recovery Methods in Venezuelan Heavy and Extra-Heavy Oil Reservoirs: A Critical Review
Authors: Rodriguez Fernancelys , Belhaj Hadi , Rousseau David , AlDhuhoori Mohammed 
Published: October 2022

Abstract
The formation of emulsions during the production of highly viscous crude oils is one of the biggest issues observed both in cold production and after the application of IOR methods in Venezuelan heavy and extraheavy oil reservoirs, with impact on the lifting of crude oils, separation of phases, fouling, production costs, etc. For the cold production case, the presence of water with strong compositional and salinity variation, coupled with the presence of gas in the case of foamy oil, could generate very stable oil-water and gas-oil emulsions; hence complicating the phenomena after the application of thermal or chemical IOR methods.
This article presents a review of: 1) different types of emulsions found in cold production as well as thermal and chemical IOR methods, 2) factors that affect the stability of the emulsions (compositions of crude oil and formation and injection waters, type of injection fluid, temperature, etc.), 3) fluid characterization methods (gravimetric method, droplet size distribution, centrifugation, rheology, etc.), 4) recommended demulsifiers based on laboratory, and field experiences in Venezuela and internationally. These criteria will be reviewed in detail, establishing the main insights associated with the emulsion formation, providing related conclusions and perspectives for treatment and prevention measures.
Based on the results of this review, it can be highlighted that the presence of resins and asphaltenes in the crude oil has a fundamental role in the stability of the emulsions found during cold production in the Orinoco Oil Belt and that the composition of the formation water might increase the stability of the emulsions (Mg2+ and Ca2+). The application of thermal as well as diluent injection methods generates emulsions that involve precipitation of asphaltenes, which together with sand production in the process, leads to making phase separation processes more complex. Furthermore, the application of chemical methods could cause phase trapping (for the surfactant case) with impact on chemical losses, and water- in-oil emulsion with high viscosity after the addition of alkali in lab experiments. A worldwide review of field and laboratory remediation methods indicates that possible emulsion treatments include the use of silica nanoparticles, polyglycerol fumarate ester, heavy aromatic naphtha, electrical heaters, among others. This article presents the main insights related to the generation of emulsions in Venezuela and for developing strategies for emulsions breakers adapted to each IOR process. It also covers the effect of water chemistry, oil composition and type of IOR/EOR process on the characteristics of emulsion and emulsion stability, and consequently the impact on the technical and economic criteria of the process.
Vitamin C: An Environmentally Friendly Multifunctional Additive for Hydraulic Fracturing Fluids
Authors: Almubarak Tariq , Almubarak Majed , Almoajil Abdullah , Alotaibi Fares 
Published: October 2022

Abstract
There exists a need for high temperature fracturing fluids as we expand exploration into deeper, lower permeability, and hotter formations. Fracturing fluid stability depends on two main bonds: the crosslinker to polymer bond and the monomer to monomer bond. To preserve the crosslinker to polymer bond, a proper crosslinker with a suitable delay additive is typically utilized. On the other hand, the monomer to monomer bond is challenging to protect since it’s susceptible to a variety of factors with the main culprit being oxygen radical attacks. Consequently, the most common high temperature stabilizers used are oxygen scavengers such as sodium thiosulfate or sodium sulfite. Unfortunately, both additives create their own issues. Sodium thiosulfate is known to degrade at high temperature to generate H2S, while sulfites generate sulfates that end up causing inorganic scale precipitation or feeding sulfate reducing bacteria creating another source of H2S in the reservoir. Additionally, Sodium thiosulfate is a high pH additive which can cause formation damage through fines migration and precipitation of hydroxides.
Vitamin C is renowned for its antioxidative and oxygen scavenging properties throughout many industries. It is commonly used as an extremely cheap supplement to boost the immune system and as a food preservative to increase shelf life. Moreover, it has an acidic pH and offers a chemical structure capable of delaying crosslinking reactions. For that reason, this work aims to study the influence of Vitamin C as a multifunctional additive in fracturing fluids.
The tests mainly utilized the high-pressure/high-temperature (HPHT) rheometer. The performance of Vitamin C was assessed with a guar derivative at temperatures between 250-300°F for 1.5 hours. Moreover, zeta potential and coreflood were used to evaluate the formation damage tendencies of using this additive.
The results showed that the use of Vitamin C was able to provide a pH reduction, crosslinking delay, and enhance the high temperature stability of fracturing fluids. Zeta potential and coreflood experiments showed that clays were more stable at lower pH conditions minimizing fines migration.
Vitamin C is a cheap and readily manufactured environmentally friendly additive that offers solutions to the use of fracturing fluids at high temperatures. Utilizing it not only offers oxygen scavenging ability, but also replaces additives that lower pH and provides crosslinking delaying properties.
Squeeze Deployed Sulfide Inhibitor Successfully Averts Challenging Sulfide Scale Deposition in Permian and Williston Unconventional Basins
Authors: Okocha Cyril , Thornton Alex , Wylde Jonathan 
Published: October 2022

Abstract
Sulfide scales (zinc, lead and iron sulfide) are currently causing considerable production challenges as mature fields are kept operational, and as deeper-hotter reservoirs are being developed. An effective way to combat conventional scaling is to inject "squeeze" scale inhibitors into the formation which are then lowly released as production resumes, providing scale protection. This option has not been the case for sulfide scales due to formation kinetics and lack of suitable products.
In this study we present two field cases where new generation squeezable sulfide inhibitors were deployed with clear success in inhibiting sulfide deposition and establishing stable production. Also presented are the development methods and chemical synthesis details for the development of a squeezable product. A novel fast screening technique is detailed as well as a new type of residual monitoring method for the polymeric species that inhibit the sulfide scales.
In the Permian Basin, newly completed long horizontal wells in the Sprayberry Formation were on a constant rotation of work overs (every 3 to 5 days) due to severe zinc and iron sulfide deposition. Early squeezes performed with known phosphonate/ester scale inhibitors, and end-capped polymer were unsuccessful. A new generation of squeezable sulfide inhibitor was deployed and stabilized production as well as the scaling ion data. A unique and fast residual analysis methodology (using a specialized HPLC column) was developed as part of the squeezable sulfide inhibitor development project capable of providing a unique selectivity in a high TDS brine without interferences increasing residual monitoring and squeeze confidence. In the Williston basin many fields are known for their troubled history with iron sulfide. To date, the preferred option has been continuous well cleanout that impacts production, next generation squeezable sulfide inhibitor was deployed and it successfully increased productivity and eliminated well clean outs for the trialed wells. This technology summarized in the paper offers a substantial step change in the ability to protect against sulfide scale via squeeze application.
These field treatments show that next generation squeezable inhibitors were successful in inhibiting sulfide scales with no observed formation damage, upset to process facilities during flow back, or decline in productivity.
Which Technology is Right for Your Field? – Quantifying Technology Significance
Authors: Mohammed Noureldien Darhim 
Published: October 2022

Abstract
Exploration and Production Professionals are always concerned with setting and optimizing field development plans (FDP). Setting field development plan is not an easy task; it usually requires full knowledge and integration between almost all technical disciplines to build a robust plan with optimum alternatives. Technology is a key, and it has a significant impact of reservoir development. Its impact was proved and identified in previous researches already but has never been quantified before. In this paper, a new methodology to quantify significance of technology is introduced using artificial neural network.
Significance of applied technology is well-proved on field development. Using reservoir-related technology (e.g. 4D seismic, Enhanced Oil Recovery (EOR), Conformance techniques… etc.) or well-related technology (e.g. smart wells, stimulations, artificial lifting… etc.) are believed to have significant impact on recovered hydrocarbon volumes and consequently the overall field development. However these factors cannot be evaluated directly for their impact on field development – there is a pattern but not recognized yet and that's why significance of technology on field development is not quantified till now.
In this research, more than 300 fields’ data have been used from many regions (US, Europe, Middle East and Africa) to give wide applicability of the model. Artificial Neural Network (ANN) has been used to recognize the pattern relating different "technology" to "field development". After the research, many key observations have been concluded; there were many fields’ types that were found very sensitive for specific technology more than others, other fields were found to have preferable technologies than others (i.e. well stimulation was more beneficial than other well technologies, in certain cases), and eventually statistical reviews, comparisons and conclusions for technologies had been deployed and its significance on field development for different regions.
This research introduces a new concept of quantifying technology and its impact on field development using a new application of ANN in petroleum industry. This paper is not only giving technical recommendations based on significance of each technology but also giving strategic insights for decision makers. E&P companies that are concerned with benchmarking technology should learn more about such approach, and follow guidelines provided so they can select the right technology for the right field.
FRP Materials in Oil and Gas Industry: New Challenge Highlighted
Authors: Herzallah Osama , Alsulaimani Mariam , Al Omari Ammar , Almarzouqi Abdulaziz , Braik Nouf 
Published: October 2022

Abstract
Lately, the oil and gas industry has been always exploring and examining new materials that has superior properties that work efficiently under severe conditions. Fiberglass Reinforced Plastic (FRP) is one of those materials that exhibit good corrosion resistance and possess powerful properties. However, FRP may encounter some substantial challenges through certain applications. This paper will highlight the failure of a unique FRP-made internal component in a condensate tank as part of a steam generation process. Some oil traces were reported in certain equipment downstream of a condensate return tank in a steam generation plant. The tank was taken out of service and inspected internally. The Corrugated Plates Interceptor (CPI) pack, one of the tank's essential internals that is made of an FRP material, was found to be covered with a dark sludge layer, partially distorted and becoming very crunchy. A root cause analysis was conducted to list all the possible sources of the CPI pack failure. All the equipment documents were reviewed and the properties of the FRP material of the CPI pack was studied.
The CPI pack in the condensate return tank was made from a cast Laminate Isophthalic Resin, which is an FRP material that is selected due to its chemical and mechanical properties. This CPI pack was found to be covered with dark sludge deposits. Some of the corrugated plates were either compressed or crumbled and the pack was distorted with a considerable angle from its original position. The review of the tank operating conditions showed that the temperature of the influent entering the tank was ranging from 70 – 95 °C. Simultaneously, after studying the FRP properties, it was noted that the maximum allowed heat distortion temperature of the CPI pack material is 100 °C, which is only 5 °C higher than the highest temperature of the inlet fluid. This marginal difference was found to be not enough for the FRP to withstand such service. Hence, the FRP material of the CPI pack was found to be inadequate for very high temperatures and shall be replaced with a more heat-resistant material. Moreover, the sludge layer on the CPI pack was attributed to the insufficient cleaning of the sludge inside the tank. This research sheds light on one of the challenges of using FRP materials in high temperature applications. This may grab the attention on a weakness of FRP materials that may need to be furtherly considered and improved in the future. In the case analyzed in this paper, it was recommended to use a CRA material with high heat resistance rather than an FRP material.
A New Fault Sealing Analysis Method Based on PSDM Seismic, Well Logging and Reservoir Performance and its Application in K Mature Oilfield
Authors: Xin Chen , Jianlin Li , Min Zhao , Qunli Qi , Xiaoliang Li , Dongyang Li , Wenwen Yu , Xiaohuan Yan , Junxian Chai , Dengyi Xiao , Shuangting Chen , Fuli An , Chen Yang , Bo Peng , Bo Wang , Weixiang Zhong 
Published: October 2022

Abstract
Accurate modelling of fault seal is crucial in understanding fluid flow and connectivity in mature fields. Numerous methods of modelling the sealing capacity of faults have been developed, such as lithological juxtapositions, SGR and PSSF. However, due to the uncertainty of structure, throw and lithology prediction, conventional methods are difficult to meet the needs of reservoir development. In order to improve the accuracy of fault seal analysis, a new method was proposed in this abstract. Integrated PSDM seismic data, well logging, and reservoir dynamic data, this new fault seal analysis method include 4 steps: 1) Horizons and faults update based on PSDM seismic data. In this step, more accurate structure model would be generated; 2) Integrated well logging and seismic motion inversion (SMI) for reservoir lithology modelling. In this step, the accuracy of lithology prediction results on both sides of the fault will be improved; 3) Fault seal analysis was ran efficiently in 3D geological model by lithology juxtaposition and SGR. 4) Fault seal analysis QC and optimization by using reservoir dynamic data.
This method has been successfully applied to the K mature oilfield in Central Asia. The detailed faults interpretation was done based on new PSDM seismic data. The number of faults increased from 18 to 44, and the new structural model was improved obviously. The reservoir model based on the combination of well logging interpretation and seismic motion inversion (SMI) is not only consistent with drilled well, but also consistent with seismic inversion trend, which improves the accuracy of lithology prediction. Automatic fault seal analysis algorithm based on 3D geological model can efficiently generate the fault seal analysis results, and find potential areas. Fault seal analysis results can be validated and optimized by dynamic data from drilled wells. 6 potential faulted seal traps below conventional oil-water contract (OWC) were found in the slope area of oilfield. 3 wells have been drilled and confirmed 3 fault seal reservoirs with high oil production and much lower water-cut (6%) than conventional water-cut (96%) in the slope of K mature oilfield. It is proved that the method is beneficial for development in mature oil field.
This new fault seal analysis method integrated the information from PSDM seismic data, well logging, and reservoir performance data to improve the accuracy of faults model and lithology model, and generated a more reasonable fault seal analysis result. This allows more confidence in estimating the sealing or leaking capacity of faults and reduces risk of re-exploration and development in mature oil field.
Block-61 Rigless Method for Efficient Permanent Abandonment
Authors: Al Abri Sultan , Abbas Aala , Jaboob Musallam , Al Abri Muna , Najwani Mohamed , Al Harrasi Sultan , Al Fadhli Khalid , Al Shidhani Taimur , Al Darai Asma 
Published: October 2022

Abstract
Well Abandonment is an important stage in the life of any well and in the field development plan in general. Tight regulatory requirements along with high cost made it apparent to search for more innovative methods to design and execute well abandonments more efficiently.
Conventionally, well abandonment operations are performed by cementing the wellbore utilizing a drilling rig and its facilities, which is the main driver for the relatively high P&A cost. Here is where the method/initiative of "Rigless abandonment" came into play. This technique replaces the use of drilling rig with other intervention conveyance packages, resulting in a more efficient and cheaper plug and abandonment while satisfying all the regulatory isolation requirements.
For a non-standard abandonment operation, the rigless abandonment initiative was a great success. All the abandonment objectives have been met and required barriers have been established while spending 73% of the planned cost only. Despite the challenges faced during the operation, the well abandonment only took 1 day longer than planned. In addition, many lessons learned have been captured to avoid recurrence in the upcoming similar jobs.
In the year of 2019, a well in the northern part of bp's block 61 concession was deemed for abandonment due to poor reservoir performance. An opportunity was fore sought by the intervention team to design and execute the required abandonment in a "rigless" style. The planned process considered the use of coiled tubing unit to kill the well and place cement across the targeted Amin formation. Subsequently, utilizing the wireline service to place a plug across the packer before perforating above it. This step was to create a pathway for the cement to communicate between the A-Annulus and the tubing in the wellbore. Then, using the cement unit, the cement was reverse circulate down the annulus and up the tubing. To ensure the placement of the cement, a slickline drift run was conducted after the cement has cured, which indicated TOC at 480 m. Finally, the X-tree was removed, and the tubing and wellhead was cut at surface before performing a top-fill job to cement the remaining void up to surface.
The implementation of this abandonment operation also adhered to strict safety standards. The rigid bp safety process guidelines ensured that all challenges and optimization opportunities were fulfilled in a safe manner.
The purpose of this paper is to detail how the team pushed the technical envelope to introduce this methodology and share the journey of implementing a cheaper and safer well abandonment alternative.