bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Mature Gas Fields with Hybrid Models – Case Study and Value Analysis
Authors: Sabharwal Varad , Singh Chauhan Prithvi , Guo Zhenyu , Ravuri Meher , Sankaran Sathish , Shrivastava Rahul , Sanchez-Ocana David Marques , Nguyen Thi 
Published: February 2025

Abstract
Production optimization in mature gas fields is a complex and challenging task that requires reservoir knowledge captured over several years of production and long-term data management strategies. Traditional surveillance methods for well and reservoir performance are manual, interpretive and do not scale over several wells with high data volumes to make timely decisions. Hybrid models that blend physics and data-driven methods prove to be useful in automatic performance tracking, early detection of anomalous events, classifying actionable opportunities, and help in continuous system optimization.
An automated solution was designed, consisting of 14 reservoir and production workflows to improve asset operational efficiency for a mature gas basin in Australia. The solution involves workflows that enable continuous optimization through evergreen reservoir, well and network models to maximize reservoir performance, field production capacity, opportunity generation, and exception-based surveillance. Each workflow solves specific problems from bottomhole pressure calculation to network optimization. These workflows are interlinked and together are responsible for production optimization and opportunity generation. In this paper, we discuss the application of our integrated surveillance and optimization system deployed in the Cooper Basin of Australia, and operated by Santos Ltd. The system allowed operators to quickly evaluate and identify several opportunities to improve well productivity within a short span of deployment. The system has captured 5 MM USD generated from automated production opportunity identification and classification. Self-calibrating models, integrated with reservoir and surface networks, provide improved scenario optimization for integrated asset management with a potential 14 MMscf/d uplift in field production. Several improvements in model quality were noted, as well as frequency of model calibration increased from manual updates twice a year to once every week with the automated system. The integrated system has been augmented into existing company processes of capacity determination and business planning.
The solution demonstrates the effectiveness of a hybrid modeling system for automatic fields and wells performance tracking, early anomaly detection, actionable opportunity identification, and promotes continuous system optimization. Our focus is to improve asset operational efficiency, optimize production and enhance surveillance processes. The solution utilizes a new generation of hybrid modeling tools that enable continuous asset optimization. Furthermore, the solution augments the capability of engineers by providing a practical way of combining data-driven methods with our understanding of physics.
Unlocking Potential: Multidisciplinary Integrated Surveillance and Recovery Strategies to Monetize a Thin Oil Rim in Minor Reservoir at G Field
Authors: Bt Kosnon Nur Khairina , Bt Ayub Nur Afiqah , B M Zulkifli Nik M Qusyairi , Harris Lee Hazreen Bt , Kumar Sanjeev , Kumar Suman , Ramli Zuhairi B 
Published: February 2025

Abstract
Oil production from G field is in declining trend where major reservoirs have been monetized through stages of development with good recovery factor. Considering infill development campaign for the field is currently shelved due to commercial challenges, minor reservoirs are being evaluated to sustain the field production. This paper deals with multidisciplinary integrated surveillance efforts carried out in evaluating thin oil reservoir characterized by fluid type uncertainty, flow sustainability and limited connectivity.
A thin oil rim reservoir with approximately 1 meter thickness and 100md permeability has been identified for production as the reservoir has never been tapped before. Promising oil zone characteristic is observed upon evaluating the open hole logs and mud logs from existing wells producing from nearby reservoirs. All candidates have been assessed for reservoir quality alongside well intervention complexity to compare the economics results. The selected well has the most competent commercial value as this well will not require to have cement packer prior to additional perforation operation, on top of good reservoir quality.
An additional perforation job was completed in 2019, targeting to drain oil production from the identified minor reservoir. However, the well was unable to flow as expected due to unforeseen reason in which prompted the team to conduct static gradient survey. The interpreted survey result shows presence of oil from the gradient and the reservoir pressure is still close to original reservoir pressure, which verified that there is no communication between the well to existing wells which are currently producing gas from the gas cap of the same reservoir. On top of that, sand production was observed thus hindering the team from conducting planned pressure build up survey. Eventually, the well was idle for 4 years. With increasing demand in oil, the reservoir was recently reperforated with bigger gun size for deeper penetration. Besides, gas lift valve changeout was done to improve the well lifting efficiency. While the team is striving to bring the well to its expected performance, the well is currently flowing at low THP thus proving the oil presence from the reservoir.
Despite the challenges encountered, the team has taken all the lesson learnt from the well intervention complexity and well performance as baseline to further assess and develop the remaining minor reservoirs at G field.
Study of Cellulose Nanomaterials and Solid Particles Synergistically Stabilising Foam Drilling Fluids
Authors: Dai Liyao , Li Mei-Chun , Sun Jinsheng , Lv Kaihe , Bai Yingrui , Yang Jingbin , Yang Dongqing 
Published: February 2025

Abstract
As a renewable clean energy, geothermal resources have the advantages of large reserves, wide distribution and sustainable development. However, due to the high temperature of geothermal reservoir, high salinity of bottom hole fluid, low pressure coefficient and serious fracture development, the use of traditional drilling fluid drilling is easy to cause complex accidents such as lost circulation and wellbore collapse, which seriously limits the efficient development of geothermal resources. In response to the above problems, this work develops a temperature-resistant and salt-resistant foam drilling fluid suitable for geothermal drilling, which provides a new idea for the safe and efficient development of geothermal resources. The performance of various blowing agents was evaluated, resulting in the identification of a blowing agent with exceptional temperature and salt resistance, along with its corresponding compounding system (0.1 wt% AOS+0.3 wt% BS-12). In order to enhance the stability of foams in high-temperature and high-salt environments, cellulose nanofibrils (CNFs) and Laponite were employed in a synergistic manner as solid particle stabilisers in the foam drilling fluid. The findings of the study indicated that an increase in solid particles concentration resulted in a reduction in foaming ability, while the half-life time was observed to be prolonged. The introduction of solid particles not only diminished the size and surface tension of the foam particles at the gas-liquid interface, but also elevated the viscosity of the system, thereby enhancing the stability of the foam.
Overcoming Challenges of Well Intervention During Simultaneous Production Operations and Hook-Up Commissioning to Restore Production of Big Bore Gas Producers
Authors: Yeow M. L. , Khaidzir K. Mohd , Abu-Jafar F. , Nordin H. , Choo D. , Nor S. M. , Wahab M. B. 
Published: February 2025

Abstract
Challenges of Slickline and Coiled Tubing fishing and milling operations was resolved without HSE incident in Simultaneous Production Operations mode with Hook Up Commissioning and Production Operations to restore production from a big bore gas producer, thus adding 150 MMSCF/D production. The well has 7″ Completion tubing with partially open downhole isolation valve and difficult downhole fish (deep set plug + Toolstring).
Challenges include correct tools, equipment, job design, procedures, weather, limited deck space, personnel movement control and ensuring each well intervention step are carried out with high chances of success. Solutions to resolve the challenges with multiple ongoing works from Well Intervention, HUC and Production were integrated and optimised to ensure all teams meet their work objectives safely within time, cost and without HSE incident. Engineering analysis, risk management and reliable well intervention equipment with good communication and decision making among work teams were implemented in planning, preparations and execution to overcome the challenges.
The well intervention works were successfully completed without HSE incidents demonstrating simultaneous operations involving HUC, Production Operations and Well Intervention can be carried out successfully. Insights include correct equipment design and procedures, working instruction to communicate effectively with personnel, good safety awareness, improving work integration between HUC, Production Operations, Well Intervention and Logistic teams, managing crew with extended shifts and improving equipment reliability. Lessons learnt on the following: running large 0.16″ Slickline wire & 2″ Coiled Tubing including depth calibration, techniques to fish wire and overcoming buckling in big bore completion.milling of ball valve with Coiled Tubing i.e. types of mills, operating downhole milling motors, milling steps, weight on mill, indications of successful milling.hot-work (welding and cutting) with habitat, thus avoiding production shut-downSimultaneous Slickline, Coiled Tubing and Well Testing well intervention with HUC on a producing platform including steps to avoid triggering flame and gas detectors on a producing platform.
The successful campaign increases confidence for multi-disciplinary surface, facilities, HUC, Production Operations and Well Intervention teams to carry out such simultaneous operations in future.
Successfully integrating simultaneous operations between Well Intervention, HUC and Production Operations on an offshore field development is a demonstration of creating real value through technical and operational expertise thus helping reduce development and production cost and time. Insights from this successful work will contribute to realising the aim of the industry to improve efficiency and costs.
A Novel Upscaling Method for the Arrhenius Kinetic Model in Fracture Simulations, with Application to the In-Situ Conversion Process
Authors: Tan Qizhi , Liu Shuyang , Li Hangyu , Wang Yanji , Liu Junrong , Sun Wenyue 
Published: February 2025

Abstract
The in-situ conversion process (ICP) involves complex thermal-reactive-compositional flow processes. To accurately represent the production performance of ICP, computationally intensive small-scale grid-blocks are entailed for numerical simulation. The presence of natural or hydraulic fractures in many oil shale reservoirs further complicates and increases the computational cost of these simulations. Accurate modeling of pyrolysis reactions of solid organics in fractures is critical for production outcomes. To address these challenges, this work introduces a highly accurate upscaling method tailored for ICP simulations involving fractures modeled by the Embedded Discrete Fracture Modeling (EDFM) method. The upscaling method is compatible with both open-source and proprietary reservoir modelling software, highlighting its broad applicability. The method employs simplified models and a temperature adjustment procedure to approximate the temperature evolutions of the grid-blocks in non-simplified models. Based on these approximated temperature evolutions, the Arrhenius kinetic parameters of fine-scale grids are upscaled to coarse-scale grids to enhance computational efficiency. The method's effectiveness is demonstrated through 3D ICP models, where it accurately upscaled the pyrolysis reactions in both matrix and fracture blocks. Additionally, the method accelerates fine-scale ICP simulations by approximately 400 times while maintaining the accuracy of fine-scale production dynamics, making it well-suited for ICP simulations in complex geological settings.
Breakthrough Horizontal Water Shut-Off Using Nano Technology; Field Trial and Optimized Treatment Recipe
Authors: Sulaiman Ahmed A. Al , Jacob Suresh , Almohsin Ayman , Salem Ibrahim 
Published: February 2025

Abstract
This paper discusses a successful rigless chemical water shut-off (WSO) application utilizing Nano-Silica fluid technology in a horizontal oil well completed with passive Inflow Control Devices (ICDs). An extensive downhole monitoring system, consisting of production logging tools (PLT), noise logging, and memory gauges, was implemented pre and post treatment to optimize job performance. A customized coil tubing (CT) bottom hole assembly (BHA) enabled real-time monitoring and precise control over sealant placement into the target zone.
The treatment aimed to use Nano-Silica technology to isolate an ICD compartment experiencing excessive water production caused by fractures in the wellbore. By sealing off this water entry point, the goal was to delay water diversion into adjacent compartments, thereby treating deeper into the formation. Candidate selection relied on PLT to characterize water flow profiles and identify the optimal treatment interval. Diagnostic tools included noise logs, post-job PLTs, and injectivity tests to refine gelation timing.
Treatment design focused on injecting the Nano-Silica fluid through ICD ports, leveraging its low initial viscosity. Once reaching the designated gelation time, controlled by reservoir temperature and concentration of sodium silicate (Na2SiO3)/NaCl (activator), the treatment solution formed an in-situ plug. Real-time monitoring via live CT BHA ensured safe treatment execution within predetermined operational limits, preventing damage to open-hole packers. Enhanced BHA configurations incorporated memory pressure and temperature gauges for comprehensive interference testing between compartments.
Post-treatment analysis showed remarkable improvements. Optimization of gelation time and recipe increased plugging strength from 25% to 100%, yielding a 36% decrease in water cut without impacting oil production rates. Initial post-job rate tests confirmed these gains. Furthermore, PLT oil flow profiling indicated a fourfold enhancement. Insights gained from interference tests validated the efficacy of the WSO procedure.
Integrated Approach to Proactive Sand Management: Subsurface and Surface Control Strategies
Authors: Zainal S. , Shafie N. A. , Salehuddin M. T. M. , Ramli N. A. , Hendraningrat L. , Riyanto L. 
Published: February 2025

Abstract
Sand production is a well-known issue in oil and gas fields. It can lead to other sand-related issues such as well plugging, erosion, production downtime, etc. The issues can be more serious, not only to the loss of wells and production facilities but also to safety and the environment. Therefore, sand management is a critical aspect of oil and gas production, ensuring operational efficiency, equipment integrity, and environmental protection. This paper presents an integrated solution project for proactive sand management, encompassing both subsurface and surface control strategies.
The paper describes strategies for integrating control techniques, empathizing with their role in mitigating sand-related issues. The sand-related issues from the fields were observed and mapped. The active sand control methods were selected: mechanical and chemical agglomeration. The concept of a chemical solution is to provide a larger agglomerate of grains sands and stronger bond strength between particles, resulting in longer agglomerated sand particle longevity.
The chemical agglomeration was comprehensively tested in the laboratory with actual downhole and surface sand samples, and it is agglomerating them into much larger particles that promote the performance and integrity of the sand screen and production separator/desander at downhole and surface facilities, respectively. In the downhole control, the sand screen was installed, and injection was done simply with a bullheading method. This technology has proved to improve production in the field with rapid payback period. Meanwhile, surface control can be applied to separator/desander facilities and shows immediate agglomeration with the chemical and enlarged sand grain agglomerates and settled at the bottom. Both strategies can increase oil and gas production and improve operational efficiency and equipment integrity.
The findings and recommendations from this paper contribute to enhancing sand management practices in the oil and gas industry, promoting cost-effectiveness, asset reliability, and environmental stewardship.
Maximizing Recovery in a Mature Rich Gas Condensate Field: Using Rate Transient Analysis to Identify Infill Opportunities
Authors: Al-Fazari I. , Govinda P. , Kalbani A. 
Published: February 2025

Abstract
Rate Transient Analysis (RTA) is a powerful technique in petroleum engineering that can be used to diagnose reservoir behavior, leading to better reservoir understanding and production optimization. In this study, RTA was used as a simple and agile analytical technique for the Field A reservoir. Field A is a rich tight gas condensate reservoir in a complex structure composed of six sub-units with varying geological characteristics located in Oman's north Field. The main purpose of this study was to understand the connected volume seen by existing wells and thereby identify sweet spots for future infills that would help maximize field recovery.
A clear and structured approach was followed in this study. First, the gap to top quartile was defined with an understanding of reservoir challenges and reservoir data uncertainties. Second, data were gathered to apply basic analytical techniques. Third, the analytical technique Blasingame was used to history match the connected pore volume. Fourth, a numerical technique was used to match the analytical approach, where the condensate banking effect was considered. Finally, the connected volume was estimated per well, and drainage areas were marked on a map to identify potentially undrained areas and infill opportunities.
Individual well RTA was performed for two blocks of the Field A reservoir, the East and West blocks, consisting of 31 wells in total. The effect of condensate dropout on the effective permeability-thickness (kh) of the reservoir was inferred from RTA. Well-level numerical models were generally able to match condensate-gas ratio decline trends and the effective kh reduction due to condensate banking. Changing skin was observed in many of the RTAs (initial negative skin gradually going towards 0), indicating gradual closure of hydraulic fractures. The study results indicate nine potential infill opportunities in both blocks of the Field A reservoir. The identified infill opportunities were ranked through economic evaluation, considering factors such as the cost of drilling and completing new wells, the expected increase in production rates, and the projected increase in reserves.
This study provides valuable insights for enhancing field performance and consequently improving field recovery. The study represents an agile approach in how field understanding, opportunities identification, and maturation can be developed quickly yet effectively using existing data and limited manpower in a limited time frame. RTA offers efficient analysis of changing reservoir and well conditions, surpassing limitations of traditional methods and dynamic simulation, providing a practical alternative for identifying infill opportunities and optimizing production strategies. The approach used can be replicated for other similar reservoirs, and the results have significant implications for the petroleum industry.
Enhancing Oil & Gas Recovery Using a Novel Nano Particle Technology
Authors: Ojukwu K. I. 
Published: February 2025

Abstract
Nanoparticle technology is increasingly prominent in the oil and gas industry, offering significant enhancements in both waterflood projects and hydraulic fracturing operations. The efficacy of nanoparticles hinges on various factors such as molecular composition, particle size, solvent base, and concentration. Typically, nanofluids consist of aqueous suspensions containing nonferrous metal nanoparticles, typically sized between 70-150 nanometers, dispersed in an anionic surfactant solution like sulfanole-akyl aryl sodium sulfonate. Anything smaller than this is rare to find in nanofluid applications.
In a recent application, smaller hydrophobic silicon dioxide particles (12-25nm) suspended in aqueous solution were deployed as part of stimulation fluid in multi-stage fracturing operations in multilateral oil producers within the Alberta Cadium and tight Montney formations. Initial Production (IP) results showed a remarkable improvement—up to 50% to 200% higher than nearby wells treated with different nanoproducts or traditional surfactants, with a significant reduction in water cut. Cumulative production comparisons revealed these wells recovered 25% more oil from the Montney formation within the first 10-12 months compared to offset parent wells treated conventionally, translating to a 3% increase in recovery factor.
Laboratory experiments corroborate that these very tiny silicon dioxide nanoparticles effectively fragment oil droplets in reservoir pores, mobilizing previously unrecoverable hydrocarbons. These nanoparticles also improve rock wettability and disperse effectively within formations to accelerate oil production. Overall, the operator realized a 400% return on investment with a mere 14-day payback period, underscoring the economic viability and transformative potential of nanoparticle technology in the oilfield.