bluuebunny/crossref_metadata_2025_split huggingface dataset:
Digital Transformation Journey of Field Operations at Abu Dhabi Offshore Field in UAE
Authors: Ahmed Talha Rafi , Januel Bastien , Fuenmayor Morealvin 
Published: December 2021

Abstract
Field operations generate large volumes of data from various equipment and associated Meta data such as inspection due dates, maintenance schedule, people on board, etc. The data is often stored in silos with a data guardian for each entity. The objective of this project was to volarize the data by developing engineered KPI's to drive decision making and make data accessible for everyone in the organization to foster cross collaboration.
Data analytics and visualization solutions were developed to automate low value-added tasks either using robotic process automation scripts or business intelligence reporting tool. Data was residing either in spreadsheet or native applications. With support of IT, centralized database was established. Scrum agile project management techniques were used to develop digital solutions. A high-level digital road map was created consulting all teams including stake holders. Use cases were identified and captured in lean A3 problem solving format. Each use case clearly identified the benefits to organization, and this was used to prioritize the use cases. A sprint was set-up with agile team and products were developed as per end user's expectation. The constant feedback loop via daily stand-up meetings helped the team deliver value added products.
Digital solutions were developed to automate low value-added tasks so employees can focus on improving systems instead of producing reports. By developing engineering KPI's and predictive analytics, technical authority could shift from reactive maintenance to pro-active maintenance. Using linear regression machine learning, early warning digital solution was developed to monitor and notify technical authority to clean strainers. The production team achieved 0.75 full time equivalent (FTE) in time savings by automating reports. By visualizing operations data such as flaring, production profiles; the team minimized flaring leading to 1% OPEX cost saving. Around 10% of chemical budget was saved by monitoring chemical injections at all platforms. Similar cost savings were achieved by visualizing data for other disciplines such as maintenance and HSE teams. By being better informed about wells annuli pressure build-up via email notifications, wells integrity team reduced the associated risk. By forming a multi-disciplinary agile team with business and delivery team, digital team deployed 20+ digital products over a short time frame of 2 years.
Instrument Safety Valves Enhanced Maintenance Strategy
Authors: Al Naumani Yahya Hamood , Al Abri Abdul Aziz Ahmed , Al Ruqaishi Mahmood Ahmed 
Published: December 2021

Abstract
Emergency Shutdown (ESD) and Blowdown (BDV) valves are the final elements part of the Safety Instrumented Functions (SIF) in which are deployed in oil and gas assets. They are classified as safety critical equipment to prevent major accident hazards. The conventional method of proof testing these valves is to close/open them fully, and thus require a process shutdown. In general, planned process shutdown is only viable every two to four years. Such infrequent and limited tests lead to imperfect testing and degrade the reliability of safety instrumented functions. Accordingly, this paper presents the work done to develop a comprehensive maintenance strategy that addresses lifecycle management of safety instrumented function in operate phase which help reduce the potential of process safety incidents. In summary, the innovative approach presented by this paper offers best practice of safety critical system integrity management implementation to achieve the highest standards of operational excellence.
Three-Dimensional Visualization of Oil Displacement by Foam in Porous Media
Authors: Wong Josiah Siew Kai , Suekane Tetsuya 
Published: December 2021

Abstract
Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.
Drilling in the Digital Age: Sensors in Bit and Underreamer Improves Future BHA Design Offshore Mexico
Authors: Batruny Peter , Aburto Zuriel , Slagel Pete , Paimin M Razali , Mahran Mohamad , Cortina Carlos Jose 
Published: December 2021

Abstract
Downhole vibration is the primary cause of low Rate of Penetration (ROP), and severe vibration causes Bottom Hole Assembly (BHA) tool failure; it is especially apparent during Hole Enlargement While Drilling (HEWD) due to multiple points of cutter contact with the formation at the bit and the underreamer. Electronic, high data rate sensors, embedded in the 17-1/2 in. bit and the 22 in. underreamer, generated detailed insights on the location, mechanism, and magnitude of downhole vibration.
Time-based downhole vibration logs from the sensors were plotted alongside mudlogging data. Finite Element Analysis (FEA) models were run using actual drilling parameters to simulate downhole conditions and provide a baseline model for further optimization. Sensor data was isolated for each of the bit and underreamer to better understand the individual and combined vibration mechanisms during hole enlargement while drilling operations. The FEA model was then used to optimize BHA configuration and underreamer placement that result in the largest drilling parameter window for future BHAs.
The data from sensors showed that whirl occurred when the bit entered sandstone bodies and the underreamer was still in shale. The data also showed that when the bit was in shale and the underreamer in sandstone, the underreamer experienced stick slip which induced stick slip at the bit. The BHA dynamics model run with actual drilling parameters showed a narrow drilling window with multiple critical vibration points at the same rotation speed (RPM). A new BHA was developed for the next well with a wider drilling window and less critical vibration points for the same RPM. The analysis identified key operational mitigations when stick slip or whirl are encountered.
This work leveraged technology and insights generated from data to shorten the learning curve and improve operations after just one well. In a drilling age where operations are becoming increasingly complex, relying on surface data is no longer enough.
Rationalization of Flares at Terminal Island
Authors: Akhtar Tehsin , Maiti Bablu Kumar 
Published: December 2021

Abstract
This study aims to assess potential opportunities for optimizing the number of flares operated by COMPANY at the Terminal Island with oil and gas processing, storage and export facilities, while considering ongoing and future developments on the island and possible integration with flare network of other downstream Company. The different flare systems cater to flaring requirements of HP, MP and LP systems in oil and gas processing plants at the island. The fundamental drivers for flare systems rationalization study are disadvantages associated with greater number of flares such as:
More plot area usage for flares at expense of industrial expansion Increased HSE risks in terms of thermal radiation and dispersion of toxic gases More fuel gas consumption as purge and pilot gas Higher operational and maintenance costs
In this study, existing flares at Terminal Island were studied and options were developed for each flare system with the aim of rationalizing the number of flares. These options included demolition of flares, diversion and redistribution of respective flare loads to other flares. Relocation of flares to offshore platforms / reclaimed areas in sea and replacement of elevated flare with enclosed ground flare, which has negligible thermal radiation was also considered.
The rationalization options developed for each flare system were evaluated on the basis of factors such as recovered sterile area, reduction in purge gas (Hydrocarbon and Nitrogen) and pilot gas consumption, maintenance cost, operation cost, number of flares and estimated investment as CAPEX (for modification scope). The current and future flare loads were taken into account while developing these options. The flare design capacities, available capacities for accommodating additional flare loads, sterile area freed along with minimization of associated dispersion and thermal radiation effects at ground level after demolition of flares were also considered for generation of suitable rationalization options.
A simplified and optimized flaring network at Terminal Island operated by COMPANY was developed by reducing the number of flares based on techno-economic screening, while safeguarding the operational and safety requirements. As concluded from the study, eight (8) nos. of flares occupying significant sterile radii can be demolished out of total fourteen (14) nos. of existing flares.
The sterile area recovered (approximately 77,000 m2) as result of flares rationalization is of great value and importance for building new facilities. The land recovered can be used for future developmental projects on the island instead of opting for land reclamation. In addition, COMPANY's objectives to reduce environmental impact, associated HSE risks and thermal radiation intensity at surrounding areas / facilities will also be achieved.
Integrated Automation and Data-Driven Workflow for CO2 Project Management – Case Study from a Smart Oil Field in the Middle-East
Authors: Rubio Erismar , Alklih Mohamed Yousef , Reddicharla Nagaraju , Albelazi Abobaker , Dilsiz Melike , Al-Attar Mohamed Ali , Davila Rayner , Khan Karem 
Published: December 2021

Abstract
Automation and data-driven models have been proven to yield commercial success in several oil fields worldwide with reported technical advantages related to improved reservoir management. This paper demonstrates the implementation of an integrated workflow to enhance CO2 injection project performance in a giant onshore smart oil field in Abu Dhabi. Since commissioning, proactive evaluation of the reservoir management strategy is enabled via smart-exception-based surveillance routines that facilitate reservoir/pattern/well performance review and supporting the decision making process. Prolonging the production sustainability of each well is a key pillar of this work, which has been made more quantifiable using live-tracking of the produced CO2 content and corrosion indicators.
The intensive computing technical tasks and data aggregation from different sources; such as well testing and real time production/injection measurements; are integrated in an automatic workflow in a single platform. Accordingly, real-time visualizations and dashboards are also generated automatically; to orchestrate information, models and multidisciplinary knowledge in a systematic and efficient manner; allowing engineers to focus on problematic wells and giving attention to opportunity generation in a timely manner. Complemented with numerical techniques and other decision support tools, the intelligent system data-driven model assist to obtain a reliable short-term forecast in a shorter time and help making quick decisions on day-to-day operational optimization aspects.
These dashboards have allowed measuring the true well/pattern performance towards operational objectives and production targets. A complete set of KPI's has helped to identify well health-status, potential risks and thus mitigate them for short/long term recovery to obtain an optimum reservoir energy balance in daily bases. In case of unexpected well performance behaviors, the dashboards have provided data insights on the root causes of different well issues and thus remedial actions were proposed accordingly.
Maintaining CO2 miscibility is also ensured by having the right pressure support around producers, taking proactive actions from continues evaluation of producer-injector connectivity/interdependency, improving injection/production schedule, validating/tuning streamline model based on surveillance insights, avoiding CO2 recycling, optimizing data acquisition plan with potential cost saving while taking preventive measures to minimize well/facility corrosion impact.
In this work, best reservoir management practices have been implemented to create a value of 12% incremental oil recovery from the field. The applied methodology uses an integrated automation and data-driven modeling approach to tackle CO2 injection project management challenges in real-time.
Hybrid Physics-Constrained and Data-Driven Approach for Interwell Saturation Estimation from Well Logs
Authors: Kovalev Dmitry , Safonov Sergey , Katterbauer Klemens , Marsala Alberto 
Published: December 2021

Abstract
Combining physics-based models for well log analysis with artificial intelligence (AI) advanced algorithms is crucial for wellbore studies. Data-driven methods do not generalize well and lack theoretical knowledge accumulated in the field. Estimating well saturation significantly improves if predictions from physical models are used to constrain data-driven algorithms in outlined primary fluid channels and other important points of interest. Saturation propagations in the reservoirs interwell region also generalize better under using combination of models. This work addresses combined usage of theoretical and data-driven models by aggregating them into single hybrid model. Multiple physical and data-driven models are under study, their parameters are optimized using observations. Weighted sum is used to predict water saturation at every point with weights being recomputed at each step. Model outputs are compared in terms accuracy and cumulative loss. A synthesized reservoir box model encompassing volumetric interwell porosity, resistivity and saturation data is used for the validation of the algorithms. Aggregated model for estimating interwell saturation shows improved prediction accuracy compared both to physics-based or data-driven approaches separately.
Very High Temperatures Steam Foam Additives
Authors: Odier Céleste , Kerdraon Margaux , Lacombe Emie , Delamaide Eric 
Published: December 2021

Abstract
In heavy oil reservoirs operated by steam injection, foam has a double benefit. By improving the steam sweep efficiency within the reservoir, foam increases oil recovery while reducing the amount of injected steam. However, in the field, this technology is not always very effective due to the fact that it is difficult to find foaming agents that can withstand temperatures above 200°C. Moreover, the agents that form stable foams at such temperatures are often insoluble at ambient temperature, and therefore difficult to solubilize in the field. Thus, a compromise between good solubility in surface conditions and high temperature foaming performances in the reservoir has to be found.
In this study, we show that it is possible to boost chemicals that form foam at very high temperature with an additive to greatly improve their solubility at ambient temperature while maintaining their high foaming performance at high temperature.
Two foaming agents of increasing degree of hydrophobicity (H and HH) were initially selected for this study. The first one shows high foaming performances in porous media and in a high-pressure cell at temperatures comprised in between 150 and 220°C. The second one, more hydrophobic, is particularly performant at temperatures comprised in between 220°C and at least 280°C.
Using a robotic platform, the temperature at which the foaming solution for agents H and HH needs to be heated to be solubilized, was evaluated with an accuracy of 5°C in four brines (varying salinity and hardness). We found that the temperature at which both agents become soluble is above 60°C, still too high for a field application.
In the second part of the study, these hydrophobic molecules were coupled to a pre-selected additive. The resulting mixtures were again qualified in terms of solubility and foaming performances. We show that by coupling these hydrophobic agents with an additive, we are able to maintain their excellent foaming performances while decreasing their solubilisation temperature down to room temperature.
To the best of our knowledge, this is the first time that very high temperature foam stability assessment up to 280°C is combined to solubility measurements to design performant foaming solutions that will be easy to handle in the field for steam foam applications. Interestingly, we show that the hydrophobicity of agents that is required for high temperature foam generation can be balanced by a more hydrophilic agent without reducing their foaming performances.
Associative Microgels, New Self Adaptive Systems to Control Fluid Loss in Well Cementing
Authors: Cadix Arnaud , Meeker Steven , Kaushik Swati , Haumesser Elodie , Ovarlez Guillaume 
Published: December 2021

Abstract
Fluid loss control additives are critical constituents in a cement slurry formulation to ensure even cement placement and ultimately satisfactory zonal isolation. Many technological options have been developed over the past decades to design fluid loss control additives for cementing. The most popular technologies as of today are either based on water soluble polymers or colloidal particles like latexes. As an alternative approach, in this paper we introduce a new technology based on associative or "sticky" microgels. These microgels are able to associate with one another at elevated concentration but, more surprisingly, are also able to associate under shear in the dilute regime during a filtration process. As a consequence these additives demonstrate outstanding performance as fluid loss control agents.
This study focuses first on standard API filtration tests using sticky microgels, and on how their behavior in application differs from traditional systems, in particular water-based soluble polymers such as cellulosic derivatives or synthetic polymers. Our investigations then focus on the working mechanism of the microgel system by analyzing adsorption on the cement surface, rheology, and filter cake structure using Mercury Intrusion Porosimetry (MIP). Finally the behavior of sticky microgels in model filtration tests is explored with either filtration against porous ceramic discs or using microfluidic chips allowing a direct visualization of microgels during filtration.
This study demonstrates that associative microgels are not controlling fluid loss through a simple size match between particles and pores within the filter cake but rather through shear-induced aggregation. Microfluidic observations reveal that aggregation occurs irreversibly as microgels are forced through the pores as the filtration process occurs. The shear-induced associated gels are particularly effective at reducing dramatically the filter cake permeability and allowing gas migration control. Interestingly the shear-induced aggregation of associative μgels seems to confer self-adaptive properties of the fluid loss additives with respect to the pore network to be clogged. Indeed, formation of shear aggregated gels larger than the individual microgels can be used to limit fluid loss even if the pore sizes are much larger than the individual microgels.
Systematic Modelling of Unstable Displacement
Authors: Skauge Arne , Sorbie Kenneth Stuart , Salmo Iselin Cecilie , Skauge Tormod 
Published: December 2021

Abstract
Modelling unstable displacement is a challenge which may lead to large errors in reservoir simulations. Field scale coarse grid simulations therefore need to be anchored to more reliable fine grid models which capture fluid displacement instabilities in a physically correct manner. In this paper, a recently developed approach for accurately modelling viscous fingering has been applied to various types of unstable displacement.
The method involves estimation of dispersivity of the porous medium and length scale of the model to determine the required size of the simulation grid cell. Fractional flow theory is then applied to obtain the correct saturation of the injected phase in the unstable fingers formed due to the adverse mobility ratio. Unstable displacement experiments have been history matched using 2D-imaging of in-situ saturation as a calibration of our method, before carrying out sensitivity calculations on the effect of fluid viscosity, and rock heterogeneity. Our modelling approach allows us to carry out simulations using a conventional numerical simulator using elementary numerical methods (e.g. single-point upstreaming).
The methods used to model instability (Sorbie et al, 2020) was originally developed for immiscible water/oil systems. The current paper now presents new results applying this approach to unstable gas displacements, where adverse viscosity ratios may be even higher than in water/oil systems. The displacement with injected gas is shown to be influenced by mass exchanges between the gas and oil as the alternating fluids (water and gas) are injected in WAG processes. Swelling of fingers delay the gas front and WAG processes divert the injected gas and improve sweep efficiency. We have also modelled water-oil displacement at adverse mobility and shown the benefit which is obtained by reducing the instability by adding polymers to viscosify the injected water. The impact of rock heterogeneity has different effect depending on buoyancy forces and the degree of crossflow into the high permeable zones.
This paper extends our novel approach to modelling the fine scale distribution of the injected fluids in adverse mobility ratio displacements. This approach has now been applied to both, gas/oil and water/oil systems where viscous fingering is present, either at extremely adverse mobility ratios and/or for reservoirs where the permeability field is very heterogeneous.