bluuebunny/crossref_metadata_2025 huggingface dataset:
Quantifying Inter-Well Connectivity and Sweet-Spot Identification through Wavelet Analysis and Machine Learning Techniques
Authors: Kalule Ramanzani , Iskandarov Javad , Al-Shalabi Emad Walid , Abderrahmane Hamid Ait , Markovic Strahinja , Farmanov Ravan , Al-Farisi Omar , Gibrata Muhammad A. , Eldali Magdi , Lozano Jose , Huang QingFeng , Rouis Lamia , Ameish Giamal , Rondon Aldrin
Published: November 2024

This study leverages wavelet analysis and machine learning (ML) techniques, including a 1D Convolutional Neural Network (1D CNN), to analyze inter-well connectivity and pinpoint an optimal new drilling location (sweet spot) based on datasets from five wells. The dataset utilized in this work includes well logging data of porosity, permeability, and water saturation at different depths of the wells. A 1D CNN was used to extract important features from the dataset. Wavelet analysis and correlation techniques were applied to the feature space extracted by the 1D CNN, revealing inter-well connectivity. Well-pairs with the highest correlation scores indicated enhanced inter-well communication. For identifying a sweet spot, machine learning regression models, including Gaussian Process (GPR), K-Nearest Neighbours (KNN), Gradient Boosting (GB), and Extreme Randomized Trees (ERT), were trained and tested to predict properties across the field. Locations with high porosity, high permeability, and low water saturation were assessed to identify sweet spots. The Wavelet analysis was then used to detect and analyze inter-well communication between identified locations and existing wells, aiding in identifying a new optimal drilling location relative to the five wells.
Operations Reduce Scope One Emissions Through Rig Electrification and Energy Efficient Lighting
Authors: Landry B. , Stopkoski C. , Norton B.
Published: November 2024

Operators are looking for simple and affordable solutions to significantly reduce the environmental impact of their operations, and many are weighing the benefits of electrification as a substitute for traditional diesel engines. Where a connection to the local utility power grid is available, electrification is an effective way to decrease carbon intensity and operating costs while maintaining operational efficiency. This paper describes the environmental impacts of rig electrification through the utilization of a utility power module and the use of overhead LED lighting, which eliminates the need for diesel portable light towers.

Canrig has developed and manufactured a utility power module that allows local grid power to be used on any drilling rig, regardless of the rig's manufacturer. Where sufficient grid power is available, the utility power module seamlessly integrates grid medium voltage and converts this into usable voltage for the rig in a safe and cost-effective manner. Overhead LED lighting can be used on any rig because this energy efficient solution can be used on any drilling rig, regardless of the rig power source. Together, these technologies deliver significant economic benefits by reducing energy costs and improve environmental stewardship by effectively mitigating Scope 1 emissions, defined by the U.S. Environmental Protection Agency as direct greenhouse gas (GHG) emissions from sources controlled or owned by an organization.

A key benefit of applying these solutions together is that they can reduce onsite CO2e by an average of 20 metric tons per day. In some geographies, applying these solutions, can achieve a 70% reduction in energy costs. The additional savings come from eliminating more than 2,000 gallons (about 7,500 L) in daily diesel fuel consumption from drilling operations and additional cost reductions from less overall truck traffic on location. These together reduce the carbon footprint of operations and at the same time reduces risks associated with transportation for better site safety.

These energy transition solutions not only have economic and environmental benefits but also address operational challenges by lowering drilling pad ambient noise levels. Replacing diesel generators and portable light towers significantly reduces sound levels, maintaining an average of 75 decibels across the drilling location.

These products are engineered to be seamlessly incorporated into drilling rigs across diverse operating environments around the world without impacting performance or efficiency. This paper explores the development and implementation of rig electrification and energy-efficient lighting solutions that can reduce emissions and costs in drilling operations.
From Baseline to Breakthrough: Comprehensively Decoding Rig Power Solutions for Sustainability and Scalability
Authors: Auld S. , Wood A. , Brady J. , Kern S.
Published: November 2024

Assessing drilling rig power solutions in terms of technical and commercial success is vital for the oil and gas industry's sustainability and scalability. An analysis of various rig power methodologies and technologies was performed to understand their impact on Greenhouse Gas (GHG) emissions and rig power costs.

Land drilling rigs typically rely on diesel engines for power, but alternative options like natural gas engines, highline (grid) power, batteries, and blended fuel engines are also available. These alternatives need to be assessed for their effects on GHG emissions and rig power costs.

To conduct the analysis, rig power consumption profiles were compared across various methodologies and technologies to evaluate emissions. The results guide discussions with operators to determine the most suitable rig power options for their specific well programs.

Diesel engines served as the emissions analyses baseline, with assessments conducted over extended timeframes to normalize the results. Fuel consumption data was shared with engine oilfield equipment manufacturers to validate results. Alterations to the baseline, through technology and aftermarket retrofits, were explored.

Three early modifications included implementation of improved control and active alerts (~4.5% GHG reduction), the addition of a DC connected battery unit energy storage system (~20% GHG reduction), and engine modification to accept natural gas as a blended fuel (fumigated) with diesel (~50% GHG increase). Additional fuel technologies were compared, including lean-burn natural gas engine with battery (~3.3% GHG reduction) and rich-burn natural gas engine (~55% GHG increase). Grid power was analyzed similarly (~67% GHG reduction).

A second blended fuel modification (port injected) option was developed and tested, changing the technical and commercial relationship of blending diesel with natural gas (~17% GHG reduction).

Data is key to addressing the challenges of selecting the best solution for the application. Observations collected over several years reveal that different technologies yield varying GHG impacts during the well construction process that should be considered when evaluating the rig power source for future projects.

The port injected dual fuel option has undergone testing and evaluation in the first half of 2024 and is slated for broader market deployment in the latter half of 2024 and beyond. The results of this new technology will enhance rig power decisions and drive future innovations.
Roadmap to Success: How Deepwater MPD Equipment was Decommissioned, Refurbished and Installed on New Drillship in Record Time
Authors: Ulhaque M. M. , Asif M. , Baouche M.
Published: November 2024

Managed pressure drilling technology (MPD) has been deployed in eastern mediterranean for well over a decade and a half. Initially the technology deployed was designed for use on Jack up rigs and had modifications done to allow the equipment to be deployed on floating rigs. However, as the demand for deepwater applications grew the MPD service providers worked to develop bespoke deepwater submersible systems which could integrate seamlessly with floating rigs’ riser systems. Weatherford introduced it first generation MPD riser system which was installed below the termination joint on the rig in 2014. In 2016 it was deployed for long term contract in eastern Mediterranean Sea on a 5th generation drillship. This was a new build installation on the rig and required a very detailed survey of the moon pool deck where the surface MPD equipment was going to be installed in a stacked arrangement to allow other ancillary completions equipment to be integrated as well. This work was completed in 52 weeks from when the first order for MPD equipment was placed to the stage where the equipment was installed on the rig tested, commissioned and ABS certification finalized to allow the system to commence drilling operations. The system was utilized for 3 years and towards the end of 2019 it was released due to changes in operational requirements.

In 2021 the operator returned to drilling activity in eastern mediterranean and this time the second-generation Deepwater MPD system was deployed in Q4 2021. This was considered an accelerated deployment as the Gen II MPD pkg required some modification of the existing structures which were initially installed on board in 2016. This deployment was completed in ~24 weeks representing a 58% improvement over the contractual term of 56 weeks.

Late 2022 the customer communicated their plans to upgrade from the currently deployed 5th generation floater rig and bring in a 7th generation drillship. Their plan was to perform the rig swap in late Q3 early Q4 of 2023. They intended to continue to use MPD pkg for drilling the first well with this rig. The well was classified as an exploratory well and so the stakes and requirements for MPD readiness were crucial. Their time frame was very challenging as the current rig was drilling a developmental well with MPD system online and due to nature of drilling operations it is very difficult to predict with pinpoint accuracy when the system will be released from the rig. On the other hand, the 7th generation rig was being mobilized from GOM and had an estimated sailing time of 30-40 days followed by 2 weeks of customs clearance process in Egypt and would then commence drilling the exploration well with the MPD section estimated within 4 weeks of spud.
A Novel Data-Driven Approach for Capacitance Resistance Models in Multi-Phase Flow Systems
Authors: Elfeel M. Ahmed , Garcia-Teijeiro X. , Khataniar S. , Biniwale S.
Published: November 2024

Capacitance Resistance Models (CRM) are increasingly recognized for their role in managing waterflooding and offering a streamlined subsurface representation for operational optimization. Since their introduction two decades ago, CRMs have evolved to address multi-phase flow and, with the integration of machine learning algorithms, have been extended to applications in gas, gas-alternating-water injection, and other enhanced oil recovery mechanisms.

In this paper, we introduce a novel data-driven formulation that reduces the number of optimization parameters by 50% compared to traditional CRM approaches. This advancement not only enhances deployment efficiency in fields with numerous wells but also significantly accelerates CRM runtime. We validated our new formulation using several reproducible subsurface numerical simulation models that have been previously employed in CRM studies. Our validation also included tests on more compressible fluid systems (such as gas injection) and scenarios with significant changes in oil-water mobility.

CRMs provide critical insights into well-to-well correlations in flooded reservoirs and are typically used for production optimization. However, this often requires the separation of production phases into water, gas, and hydrocarbon liquids, which is typically achieved using additional analytical or data-driven models in conjunction with CRM. In response, we present a novel method that integrates CRM with a pattern balancing algorithm, enabling optimization based on multiple objectives such as reservoir fill-up, sweep efficiency, and water injection effectiveness.

Our extended formulation not only improves the accuracy of CRM models—evidenced by increases in R2 values from 0.6 to 0.95 in some cases—but also provides more precise subsurface insights, reducing the risk of misinterpreting reservoir trends as false well correlations. Finally, we explore the complementary role of production data-driven models alongside more detailed numerical reservoir simulation models.
Revolutionizing Drilling Efficiency in Highly Interbedded Formations Using A Sustainable Approach Through A Cutting-Edge Pdc Bit Design
Authors: Alqunais Dawood , Teasdale Paul , Case Matt , Hababi Ali
Published: November 2024

Drilling large diameter boreholes through highly interbedded formations presents significant challenges such as torsional instability that potentially leads to a drill string twist-off or a premature Polycrystalline Diamond Compact (PDC) bit damage. This paper introduces a novel solution to overcome these challenges by utilizing an innovative PDC bit that uses active cutting elements across the bit cutting structure to control the Depth Of Cut (DOC) while improving the performance and reducing the risk of twist-off.

A conceptual development project was established with the objective to replace multiple bits with a single PDC bit. The design engineering team have identified the application challenges and have designed an advanced PDC bit with an alternative cutters configuration to drill through interbedded formations more effectively. The unique PDC bit has a strategic cutters arrangement distributed across the bit face with alternating aggressive and passive back rake angles that enables the bit to shear the formation from various points of contact, control the DOC and improve Rate of Penetration (ROP).

The field test demonstrates the result of deploying the new concept in drilling transitional formations that generate significant torsional vibrations. Historically, several PDC and roller cone bits designs approaches have been unsuccessful to overcome the challenge of drilling interbedded formations in 22-inch section. The bits have been pulled out of hole prematurely due to bit damage or twist-off incidents. The advanced PDC design was tested in an established field with more than 1000 wells, where the operator typically completes the section with at least two bits, either roller cone or conventional PDC bits. The new bit successfully drilled the entire section through interbedded formations and has achieved the best ROP in the field with 49.56 % improvement over the previous ROP record. Subsequent testing in another field shows unprecedented achievement, the bit has drilled the whole section in a single run with 70% ROP improvement. It has been proven that the new approach has reduced harmful torque fluctuations by 25 % while drilling through transitional zones. The innovative PDC bit resulted in a smoother torque response, an improved PDC bit dull condition, and a significant drilling cost savings by eliminating bit trips and new bits cost.

This paper addresses a typical torsional instability issue that many operators encounter in large diameter sections, and it presents a viable solution that can potentially improve performance in variety of transitional applications. The new PDC bit can create more opportunities to enhance drilling performance and reduce drilling costs. In addition, the results of the real-time downhole vibrations analysis can be used to improve future design iterations, optimize drilling parameters and thus improve drilling performance.
Wellhead Desander with Real Time Weight Monitoring System for Enhanced Process Safety and Efficiency
Authors: Piasseski D. , Elhanbouly S. , Al Shehhi H.
Published: November 2024

The presence of solids throughout the lifecycle of oil and gas reservoirs is not a new challenge. Solids in the flow path can originate from multiple sources: they may occur naturally due to reservoir characteristics or as a consequence of the methods, operations, and materials used—such as in unconventional reservoirs, where frac operations often result in solids being produced to the surface. Specifically, in the initial phases—during milling of the frac plugs or the initial flowback period—drawdown must be controlled to prevent frac sands (proppant frac) from being expelled from the reservoir into the wellbore and, consequently, into the flow path. Excessive sand production at this early stage not only poses risks to surface equipment and personnel but also has long-term impacts on well performance. In some cases, excessive sand can severely impact fractures, leading to a weaker connection between the reservoir and the wellbore, resulting in reduced production.

Although sand production is almost unavoidable, the lack of reliable detection and quantification of sand returns in real time hinders continuous process improvement and forces operators to rely on time-based sand flushing. Each flushing operation requires multiple valve operations, exposing the valves to solids and eventually leading to premature failures, which can result in process safety incidents. This paper focuses on the results of a field trial of a new desander model, featuring a novel Real-Time Weight Monitoring System, and how this technology can help improve both process safety and operational efficiency.
Empowering Drilling and Optimization with Generative AI
Authors: Amour Myriam , Rachmat B. Kent , Rementeria Agustin Soriano , Guillot Valerian , Millan Ekaterina
Published: November 2024

Over the last 10 years, no industry has faced more pressure and scrutiny to gain efficiency than the oil and gas (O&G) industry. Drilling engineers are tasked with leveraging data to optimize design and operations. O&G companies have collected and stored large amounts of high-frequency sensor data and reporting data. Efficient data access is fundamental for upstream projects, and data operations skills are critical for drilling engineers. However, data operations have not become a core competency for most of the drilling engineering community.

A novel solution to this problem is proposed—a framework that, to the best of our knowledge, represents the first application of Text-to-SQL using LLMs within the Oil & Gas (O&G) domain, specifically designed to handle complex database structures. This paper presents a novel solution that bridges the gap between drilling engineers’ need for efficient data access and their lack of specialized data skills. Our Natural Language (NL) to SQL GenAI workflow transforms complex data transformation operations into a seamless process requiring no special expertise and delivering results within seconds. By converting natural language queries into SQL queries, this framework dynamically enriches users’ questions with relevant contextual information before processing them through a Large Language Model (LLM). This ensures that drilling engineers can quickly analyze multi-well data, address critical issues, and capture knowledge for future wells, all while overcoming the challenges of accessing and interpreting large SQL databases.
Hydrogen Gas Accumulation in Subsea Umbilical Cable Splitter Boxes: Evaluating HSE Risk, Overcoming Challenges & Deploying Mitigation Measures
Authors: Khatua Anup Kumar , Alhashmi Abubaker Alaidarous
Published: November 2024

This paper presents a comprehensive analysis of potential sources of hydrogen (H2) gas, its propagation, and accumulation within subsea umbilical cable splitter boxes, leading to deformation of the splitter box. With a focus on addressing challenges and proposing effective mitigation strategies, this paper provides actionable insights for practicing engineers. The meticulous exploration of health, safety, and environmental (HSE) risks enhances the understanding of subsea cables & umbilical, making this paper a valuable resource for managing risks and safety protocols in the upstream oil and gas industry.

An integrated approach has been developed through discussions with key stakeholders, including the original equipment manufacturers (OEMs) of the umbilical cable, topside umbilical termination unit (TUTU) & splitter box teams, and consultants. This collaborative effort led to root cause analyses and the identification of the most efficient and cost-effective methods for mitigating hydrogen accumulation in splitter boxes.

The insights gained from this study can be applied to similar installations, helping to enhance the safety and reliability of subsea electrical systems in the oil and gas industry. Future work will focus on monitoring the effectiveness of the implemented measures and exploring additional strategies for further risk reduction.
Enhancing Asset Reliability Through Comprehensive Implementation of Systematic Approach for Conducting Pre-Commissioning Material Adequacy Assessments in offshore Fields
Authors: Aoudi H. K. , Al Mukhmari H. K. , Alhammadi M. S. , Almarzooqi S. M.
Published: November 2024

This paper addresses the comprehensive integration of material adequacy assessments aimed at enhancing asset reliability and service life within offshore fields. In offshore oil and gas projects, ensuring the reliability and longevity of assets is very critical. The primary focus is on the seamless integration of new packages and modifications into existing facilities while safeguarding asset integrity through detailed corrosion monitoring. By assessing the reliability of existing equipment and piping mechanisms, the paper aims to mitigate risks associated with changes in process conditions and fluid compositions. The proposed methodology combines existing manuals and expert knowledge to enhance processes, harmonize best practices, and update information, ensuring effective corrosion control measures amid evolving project requirements. The study emphasizes downstream tie-in points for existing facilities, considering the dynamic nature of process conditions and fluid compositions. The results suggest that standardizing corrosion control practices and aligning with industry standards improve operational reliability, reduce costs, and enhance risk management. Proactive corrosion management, updated material selection, and rigorous evaluation processes are highlighted as key to ensuring long-term sustainability and asset integrity.
De-Risking the Steam Injection Project with Comprehensive Geomechanical & Geochemical Assessment, Sultanate of Oman
Authors: Maranu R. , Al Amri B. A. H. , Mirza M. , Sudono H. , Ezzat G. , Shinde A. L. , Singh H. , Harper C. , Rao D. Govind , Kidambi T. , Perumalla S.
Published: November 2024

The subject field has a cretaceous clastic sandstone reservoir which has been producing heavy oil (16-17° API). The reservoir is overlain by thick shale cap rock with an unconformity. The study area is bounded by two faults on the eastern and western sides of the field. Enhanced oil recovery methods are deployed to improve the productivity, including cyclic steam stimulation (CSS). A steam flood pilot was performed on a few wells with the aim to implement the full-field steam injection in the near future. As part of this full-field deployment, comprehensive Geomechanical & Geochemical risk assessment was carried out with multi-disciplinary reservoir data integration. This paper discusses the relevant workflow for risk assessment in detail.

Understanding and evaluating the state of in-situ stress is essential before and during steam injection operations. This requires building calibrated Geomechanical models for key wells based on the best available data. A normal stress setting prevails in the reservoir at initial pressure and temperature conditions. In order to simulate the complex geological structure of the reservoir, 3D finite element (FE) modeling is deployed with the aim to compute stress and strain changes in the reservoir and cap rock due to changes in reservoir pressure and temperature. A watertight structural framework for the 3D Geomechanical model is built covering overburden, reservoir and underburden formations along with faults capturing the complexity. The full field 3D Geomechanical model is populated with rock mechanical properties with guidance from a static geological model. Then, the 3D Geomechanical model is coupled with a reservoir dynamic model that has forecasted pressure and temperature at different time intervals as per the planned steam injection. This model computes the stress/strain changes in and around the reservoir with forecasted changes of pressure and temperature with time. Furthermore, geochemical assessment was conducted considering the reservoir mineralogy and estimated the fines production risk as well as the risk to the integrity of the formations as a result of the introduction of steam into the formations.

Results of the finite-element modeling are evaluated to quantify the geomechanical-related risks, which includes compaction/heave in the reservoir, cap rock integrity, and fault reactivation. Additionally, an estimated safe operating envelope for injection was defined to avoid risking reservoir integrity. A customized multi-technology monitoring strategy is developed for further field development planning. This integrated study has systematically de-risked the development plan with safe operating envelopes and further recommendations to develop the reservoir.
Case Study: Practical Solutions for Managing Small-Volume Flares in Community Areas: the Installation of an Incinerator
Authors: Matsuo R. , Takada Y. , Jeanes T.
Published: November 2024

Flaring, the combustion of excess gas from oil and gas operations, remains a contentious practice, particularly when it comes to routine flaring, which contributes substantially to both energy loss and greenhouse gas (GHG) emissions. In 2023, satellite data estimate that annual flaring amount will reach 148 billion cubic meters (BCM) globally, with small-scale operations flaring less than 5 million standard cubic meters per day (MMSCFD) responsible for 59 BCM [1]. Notably, upstream flaring accounts for over 90% of total flaring [2]. The World Bank's Zero Routine Flaring by 2030 initiative underscores the critical need for enhanced gas management practices.

Elevated flare stacks have long been the standard method for managing excess gas; however, incomplete combustion remains a frequently cited issue. While combustion efficiency is generally assumed to range between 97% and 98%, lower rates have been observed in certain cases [3,4], raising concerns that publicly reported figures may underestimate actual GHG emissions. These discrepancies stem from various uncertainties, including inconsistencies in measurement techniques [5]. Additionally, decreased efficiency has been confirmed under specific conditions, such as strong crosswinds [6,7] and suboptimal flare gas properties (e.g., lower heat value, reduced flow) [8]. Incomplete combustion also produces black carbon [9] and unburned methane, both of which have a higher global warming potential than fully combusted CO2. Furthermore, these emissions can potentially degrade local air quality, posing significant risks to public health [10]. Volatile organic compounds (VOCs), polycyclic aromatic hydrocarbons (PAHs) [11], and particulate matter (PM) [12] are significant sources of pollution associated with flaring activities.
Moving from Composite to Dissolvable Plugs, A Journey Towards the Elimination of Post Frac Intervention
Authors: Alfaify Alhaitham , Baki Sohrat , Alabdrabalameer Musab , Alzamil Abdullah
Published: November 2024

Hydraulic fracturing is a fundamental technique used to extract hydrocarbons from reservoirs with low permeability. A pivotal aspect of the process of hydraulic fracturing often require the temporary isolation of specific wellbore sections to ensure effective zonal isolation. Traditionally, composite plugs have been used for their strength and durability, however, they do still require post-fracturing cleanup. Dissolvable plugs on the other hand, are now revolutionizing the industry by having the distinct advantage of disintegrating under downhole conditions. This paper evaluates the performance of both traditional composite and dissolvable frac plugs through a detailed assessment of various plug milling (plug removal) parameters. The study compares two composite plugs and four dissolvable plugs separately to ensure a fair evaluation, addressing key metrics such as milling time, debris weight, exposure period, and dissolution rate for dissolvable plugs. The goal is to streamline the process to reduce and potentially eliminate post-fracturing intervention required to for plug removal. The results show that while composite plug A offers consistent performance, dissolvable plug two stands out with the highest dissolution rate, cutting post-fracturing intervention time by half and generating the least debris. These findings provide insights into the evolving practices in the industry and highlight the advantages of adopting dissolvable plugs. Ongoing research and advancements may lead to plugs with a 100% dissolution rate, potentially eliminating post-fracturing intervention altogether.
Application of PLT and Tracer Testing Data on Deposition Study and Reservoir Geological Modeling-A Case From the Mishrif Formation in H Oil Field in Southeast Iraq
Authors: Han Rubing , Song Benbiao , Zhao Hang , Sun Liang , Xiong Lihui , Lou Yuankeli , Li Shunming , Mao Xianyu
Published: November 2024

For many oil fields, due to the limitation of economic benefits or short development history, there are many difficulties, such as fewer cores, larger spacing of cored wells and poor seismic data quality, etc. This paper takes a giant carbonate reservoir in H oilfield as an example, utilized common reservoir monitoring data, namely PLT and tracer detection data, to assist sedimentary facies research and get more convincing results in both deposition understanding and facies model. The new procedure of deposition study and facies modelling were introduced as follows: Firstly, with comprehensive geological data, the sedimentary facies study was conducted and the initial sedimentary facies maps were made; Secondly, the PLT data and tracer detection data were collected and analyzed; Thirdly, reservoir monitoring data were utilized to improve the initial sedimentary facies understanding. Finally, the sedimentary facies maps were redrawn and used to constrain facies modelling and a few realizations of facies models that complied with the geological knowledge were got. They are for the geologists and the reservoir engineers to choose the right realization together. Then the sedimentary facies maps were redrawn and used as trend to constrain facies modelling, which show better coincident rate between static and dynamic data. With the continuous reservoir development, the amount of reservoir monitoring data is gradually increasing, and the corresponding geological research is increasingly deepening. The new facies model was more in line with the actual underground conditions of the reservoir and laid a solid foundation for other workflows in the static and dynamic process of reservoir study. Without changing other parameters, the history match results improve significantly, which lays solid foundation for reservoir management.
An In-Situ Mobility-Controllable Nanofluid for Enhanced Oil Recovery in High Temperature and High Salinity Reservoirs: Experimental Study
Authors: Zhao X. , Wang H. , Liu R. , Li C. , Sun Z
Published: November 2024

In order to improve the EOR efficiency of water flooding in reservoirs which are high temperature and high salinity (HT/HS), a polymer-free nanofluid based on the synthesized amphiphilic nanocarbon with In-situ mobility-controllability has been developed and evaluated. Thickening water-in-oil Pickering emulsion was produced from this amphiphilic nanocarbon. The viscosity of the emulsion was exponentially increased as the water content increased up to 90%.

The dispersibility, intrinsic wettability and oil/water interfacial tension (IFT) of the amphiphilic nanocarbon were investigated. The prepared amphiphilic nanocarbon was a nanoscale emulsifier, which had an excellent colloidal dispersibility in harsh brine for 90 days at 120 °C. Low IFTs facilitated the oil external phase emulsions within a wide range of water/oil proportions. The study of morphologies and droplet size distributions of the corresponding emulsion type within various water cut region was conducted. A distinctive Maltese cross pattern around the emulsion droplet edge indicated that a protective layer was produced in a spontaneous emulsification process.

Then the shear-dependency of viscosities for emulsions were tested. The apparent viscosity of the emulsions regularly increased higher than that of crude as increasing of water proportion when the water/oil proportion was below 80%. Based on the static experiments, the core displacement behaviors of the emulsifier were evaluated by flooding test to identify the in-situ intelligent mobility-controllability of this amphiphilic nanocarbon. Owing to the tunable viscosity of the in-situ emulsions together with low magnitude of IFT, and the wettability modification of rock surface produced by this unique amphiphilic nanocarbon, the oil recovery factor could be enhanced about 20% to 35% by injection of the nanoscale emulsifier when the WCT of earlier water flooding exceeded 90%.
Industrial-Scale Application of Amine-Based Tail Gas Oxidation-Absorption Technology Combined with Claus Process for Lowering Sulfur Dioxide Emission from Natural Gas Purification
Authors: Tang Quanwu , Li Jing , Fu Jingqiang , Fan Rui , Chen Shiming , Sun Feng , Wang Xingrui , Hu Chao , Lai Bing , Zhao Liang , Jiang Guobin
Published: November 2024

Natural gas emits less air pollutants and carbon emissions than other fossil fuels, thereby natural gas consumption is growing rapidly and natural gas purification becomes more important around the world. Claus process and extended Claus process (e.g., superClaus, cold bed adsorption and clinsulf-SDP) are industrialized sulfur recovery systems to convert hydrogen sulfide to sulfur and have been widely used in natural gas purification plants, but there would be a large number of sulfur dioxide emissions. To reduce sulfur dioxide emissions, an innovative tail gas oxidation-absorption technology combined with Claus process has been developed and applied in a natural gas purification plant of PetroChina. In this paper, the tail gas oxidation-absorption technology combined with Claus process was elucidated in detail, an amine-based sulfur dioxide absorbent was employed and evaluated, and key operation parameters such as oxygen volume fraction, burner temperatures, amine-based sulfur dioxide absorbent concentrations, pH of lean amine solution and molar rate of heat stable salts versus the amine-based sulfur dioxide absorbent were investigated and analyzed in an industrial-scale. The key operation parameters were determined as follow. Tail gases of the sulfur recovery system was burned at 810±5°C in a burner, and the oxygen volume fraction was maintained between 3.3v% and 3.7v%. The concentration of amine-based sulfur dioxide absorbents was controlled between 21w% and 25w%. The pH of lean amine solution was optimized among 5.0 to 5.7. In addition, the molar rate of heat stable salts versus the amine-based sulfur dioxide absorbent was controlled between 11:10 and 14:10. As a result, with above operation strategies, super low sulfur dioxide emissions can be gotten below 100mg/m3, which is better than the sulfur dioxide discharge standard of natural gas purification plants (GB39728-2020) in china. Wastewater produced from the amine-based tail gas oxidation-absorption technology was reused. This work would be helpful for exploiting high-sulfur natural gases and decreasing sulfur dioxide emissions from natural gas purification plants in the world.
Enhancing Drilling Equipment Reliability: Deep Learning for Predicting Failure Time and Real-Time Anomaly Detection
Authors: Tharayil Sarafudheen M. , Alrammah Marah M. , Alghamdi Maria A. , Aljohar Fatimah E. , Otalvora William B. Contreras
Published: November 2024

Predict drilling equipment's failure time and real-time anomaly detection play crucial roles in ensuring the seamless Oil and Gas wells drilling operations. In this study, we delve into the application of neural network-based machine learning techniques specifically tailored for these tasks in drilling. Our primary objectives encompass diagnosing equipment health states, detecting anomalies in real-time, and predicting remaining useful life (RUL). To address these challenges, we implement a novel combination of neural network architectures, including convolutional layers, Long Short-Term Memory (LSTM) cells, and attention layers. By meticulously training our model on historical data using carefully selected deep-learning hyperparameters, we tackle the unique characteristics of drilling equipment data. The resulting neural network predicts total lifetime and RUL based on historical input. Our LSTM model achieved an accuracy of 74.03%, given the complexity and novelty of the dataset, these results establish a strong benchmark for future research. This improvement results from hyperparameter tuning and optimized network architectures. Additionally, accurate anomaly detection and minimized unscheduled downtime of 14% demonstrate potential cost savings for oilfield operators. By identifying potential failures in advance, our approach allows efficient scheduling of maintenance activities. Field engineers express satisfaction with our approach, validating its effectiveness. Our research introduces novel aspects to drilling equipment maintenance. Through empirical validation, we rigorously test our approach using real-world drilling sensor data, ensuring robustness and reliability. This instills confidence in industry practitioners. Furthermore, our intuitive real-time anomaly detection system enhances drilling safety, efficiency, and cost savings.
For CFR - Account for Greenhouse Gases Emissions in Upstream Activities Through Sustainable Integrated Asset Modeling
Authors: Marmier R. , Chehade P. , Akchiche M. , Pellegrino J. , Shmeis M. , Matusse A. , Dauba C. , Higelin M.
Published: November 2024

The objective of this paper is to present the benefits of an integrated greenhouse gases (GHG) emission and hydrocarbon production forecasting approach and proprietary tool, called For CFR, currently being deployed within the Company on real cases. The presented approach consists in organically integrating material, heat and power balance modeling of an asset within reference hydrocarbon production forecasting softwares. At every simulation timestep, equipment power needs (e.g. compressors or pumps) are evaluated according to hydrocarbon production and injection potential. Power needs are then transmitted as a load to equipment power sources (e.g. gas turbines) for fuel gas rate evaluation. Flare gas rate is evaluated from flaring policy, combining planned and unplanned contributions. Fuel and flare gas rates are finally converted into GHG emissions. Constraints such as asset GHG intensity or condition-driven equipment startups and shutdowns have also been implemented. In the context of brownfield assets, For CFR approach allows integrated asset GHG emissions and hydrocarbon production evaluations for short-term optimization and planification, as well as long-term projects evaluations. In the context of greenfield assets, For CFR approach allows screening of various design assumptions from reservoir to surface parameters and promotes sanctioning the most valuable and energy efficient development. This paper illustrates clear examples of GHG emissions reductions opportunities with associated production profiles, varying subsurface and surface parameters. As an example, reservoir management can have a significant impact on GHG emissions and shows complex interactions. Indeed, water injection voidage replacement optimization was screened on an oil field operated by the Company: when water injection is reduced, short term GHG intensity decreases as less water is produced, treated and pumped for injection. Long term GHG intensity then increases to a higher than initial value, as the reservoir depletes and more energy is required to sustain production (e.g. riser gas-lift) and to treat associated produced gas. Other examples involving surface equipment optimization are detailed in this paper. The novelty of For CFR approach consists in integrating fuel gas and flare gas GHG emissions evaluation directly within reference hydrocarbon production forecasting softwares. It allows to better and faster capture subsurface - surface interactions and to evaluate more GHG intensity reduction opportunities with associated hydrocarbon production, leading to more valuable asset evaluation all along field life.
Water Management Strategy in UAE's Unconventional Fields: A Case Study of Closed Loop Operations and Novel Treatment Technologies
Authors: Alhassani A. A. , Baig M. Z. , Elazab S. A. , Burgess C. , Caillon D. P. , Alvarado O. A. , Bannay A. Al
Published: November 2024

As part of the UAE's commitment to Environmental Social Governance (ESG), unconventional exploration operations adhere to a strict zero-tolerance policy regarding spills. Consequently, closed-loop operations were instituted across all rigs and sites, ensuring no water is discharged into pits. This approach is supported by a thoroughly planned treatment and discharge strategy established before operations begin.

This paper will delineate the water management strategy, focusing on the closed-loop system and innovative treatment technologies that facilitate H2S removal without infusing chemicals into the produced fluid. By preventing both over- and under-treatment, this method not only enhances operational efficiency but also reduces costs. A major challenge encountered was managing and treating high-temperature flowback water exceeding 200 degrees Fahrenheit.

Additionally, the paper will explore the technical and operational experiences in establishing the water management process for Zipper frac operations, where over 800,000 barrels of water were pumped. It includes the sourcing, storage, and treatment protocols, alongside modifications to testing and treatment equipment designed to handle high-temperature, high-pressure flowback water. The use of real-time, non-chemical H2S treatment methods reduced testing time by 50%.

Initiatives aiming for efficient and cost-effective water management solutions are being explored to facilitate the profitable development of unconventional gas and oil in the UAE. These initiatives strive to merge optimal performance and low-cost strategies with current regulations and environmental requirements to ensure sustainable operational security. The scope of the paper extends these closed-loop operations to metal extraction, applying circular economy principles to unconventional completion operations.

While the development of unconventional oil and gas resources has transformative impacts on the UAE and global energy markets, concerns about water availability in desert regions remain. The UAE, however, benefits from significant oil and gas reserves as well as abundant water resources—both surface and subterranean—and advanced local water treatment technologies and services. Moreover, the basin's proximity to the sea and the stratigraphic setting of target unconventional reservoirs below known aquifers like Simsima and Um Radhuma provide notable advantages.
Improving Well Control Response Ability via Virtual Reality Technology
Authors: Luo Yuan , Zhu Jun , Pang Ping , Xu Xianjue , Qing Yu
Published: November 2024

The objective of this study is to address the challenges faced in well control emergency response training due to the impracticability of simulating actual crisis scenarios and the rarity of personnel who have experienced real well control emergencies. Traditional training methods are limited and often result in ambiguous outcomes, highlighting the need for an improved approach to preparing teams for well control incidents. Our method involves the utilization of Virtual Reality (VR) technology to simulate and recreate various well control emergency situations. This immersive technology allows for the construction of diverse operational scenarios and facilitates multi-person collaborative drills. By employing VR simulations, trainees can experience realistic well control challenges in a safe and controlled environment, enabling them to practice response strategies and teamwork without the associated risks of real-life emergencies. Also receiving multi-person collaborative training via VR technology results in a lower cost and high efficient way to simulate different scenarios where the teammate rarely to meet in real world which help them get used to their role and familiar with the procedure or environment under such conditions.

The implementation of Virtual Reality (VR) technology in well control emergency training has led to a multitude of positive outcomes. A significant enhancement in the trainees’ decision-making speed and accuracy was observed, as VR simulations provide instant feedback and allow for rapid iteration of scenarios. Trainees have also reported increased confidence in handling high-pressure situations due to the realistic, immersive experience offered by VR. Furthermore, the technology has enabled the creation of a comprehensive database of performance metrics, allowing for detailed analysis of actions taken during each simulation. This data-driven approach facilitates targeted improvements in both individual skillsets and team dynamics. Moreover, the scalability of VR solutions allows for larger numbers of employees to be trained simultaneously, further amplifying the return on investment. In essence, the adoption of VR for well control emergency training has not only transformed the effectiveness of such programs but also provided a sustainable, scalable, and economically viable pathway to building a safer and more competent workforce within the oil and gas industry. The innovative aspect of this approach is the ability of VR to provide an interactive and engaging platform for well control emergency training. Through realistic simulations, VR allows for an unprecedented level of immersion and interactivity that traditional training methods cannot offer. As a result, personnel are better equipped with the necessary skills and confidence to effectively manage well control emergencies, ultimately enhancing safety and operational efficiency in the field.