bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unlocking Reservoir Potential: AI-Driven Integrated Well Placement Under Uncertainty in a Giant Onshore Field
Authors: Ismail A. M. , Almusalli Alya Majed , Ramatullayev S. , Su S. , Al Kindi Z. , Mustapha H. , Kloucha C. K. 
Published: November 2024

Abstract
The proposed paper aims to introduce an innovative, automated workflow for identifying and drilling high-performance infill wells in the large onshore reservoir in UAE, a region challenged by its complex geological setting and reservoir dynamics. The focus is on leveraging multi-disciplinary data integration and advanced automation techniques coupled with machine learning to enhance the precision and speed of well placement decisions under complex conditions.
Our methodology employs a multi-disciplinary approach that synthesizes various static and dynamic data to map drilling opportunities and risks. We utilize an automated opportunity index generation procedure to rapidly identify potential infill well locations. By integrating these maps with existing well data and "no-go zones", we develop an optimized well placement target map. The procedure also includes automated design and optimization of well trajectories that account for surface and subsurface constraints both for producers and injectors, resulting in a tailored well design and trajectory that enhances drilling accuracy and efficiency.
Implementing our integrated, automated infill well placement solution in one of the UAE's largest onshore reservoirs with more than 1000 wells produced substantial results. The pilot project successfully extended the production plateau by several years, resulting in significant incremental oil production. Our approach also facilitated notable operational cost savings and improved the efficiency of well placement processes, with the time required for placement decreasing from several weeks to just days—an efficiency gain of up to 80%. These improvements were achieved by optimizing the number and placement of new infill wells at strategic locations, and by removing underperforming wells, which helped streamline operations and reduce unnecessary expenditures. This methodology not only optimizes well placement under complex geological and operational conditions but also significantly contributes in cost-effective reservoir management and enhanced production efficiency.
This paper introduces a novel approach by integrating multi-disciplinary data and automated mapping techniques to optimize infill well placement in complex dynamic reservoir environments. By streamlining the identification of drilling opportunities and risks, our methodology enhances the precision and speed of decision-making processes, offering practical benefits such as reduced new infill well count, optimized oil recovery, and cost-effective reservoir management—an invaluable resource for practicing engineers navigating similar challenges in their field.
Enhancing Survey and Scoping Operation with Digital Twin Approach for the Comprehensive Mapping and Asset Registration in Central Sumatra, Indonesia
Authors: Nainggolan Humisar , Shah Ardian , Wirawan Andi , Shamanta Westya Fiqhi , Hadi Rizky , Widiasri Irma Savitri , _ Hardianto 
Published: November 2024

Abstract
There are more than 150,000 pieces of equipment in scattered locations and 80 on-plot facilities which causes: difficulties in identifying equipment, inefficiency of scoping and surveying, inaccurate planning. Triggered from those circumstances, an internal team has been developing a System for Comprehensive Mapping and Asset Registration with digital twin approach. It will help users to identify equipment accurately, to reduce time for scoping and surveying physically. Ultimately, it would resolve inaccurate planning issues because it could interface among those applications.
The method used was divided into 5 (five) phases: Phase 1 is the development of geospatial data for all equipment using GIS application. Phase 2 is the development of 360View application (a virtual model that replicates a physical object or system). Phase 3 is the development of facility equipment information database using company server. Phase 4 is the integration of those into one web-based application that can be accessed by all authorized users. Phase 5 is the development of standard operating procedures.
This Digital Twin initiative was started in early 2023 and has been implemented in 8 (Eight) gathering Station and 10 (Ten) Transmission Line during the year. It has succeeded in reducing emission about 300 KG CO2 print from fuel consumption used during physical scoping and surveying, feeding data for hydraulic pipeline simulation to support projects, well development, construction, and maintenance teams. This new approach also eliminates the possibility of human errors during scoping and planning phase because all information needed has been provided in one stop shopping application. In total, this application could reduce the cost by about USD 260,000 per year.
With the implementation of this application, it is significantly transforming habits from physical surveying and scoping became virtual mode without decreasing of the objectives of the activities. As stated in the above paragraph, it is improving safety aspects and reducing carbon footprint. Finally, it eliminates the possibility of human errors and become one stop shopping application. This application might be beneficial to be implemented into others Oil & Gas Company with similar operation.
Surfactant Flood in a Tight Carbonate Reservoir in North Oman
Authors: Wang Y. , Al-Naabi A. N. , Al-Hasani M. A. , Al-Naabi A. M. , Al-Sinani I. S. , Al-Jabri S. H. 
Published: November 2024

Abstract
Daleel has undertaken an extensive endeavor to establish the technical viability of chemical enhanced oil recovery (EOR) method in the Shuaiba carbonate reservoir, which aims to demonstrate the feasibility of surfactant injection through detailed lab work followed by field applications. The Upper Shuaiba carbonate formation presents challenging conditions, characterized by high formation water salinity (~180,000 ppm), tight matrix (permeability of 1-15md) with fractures, and reservoir temperature of ~85°C.
In light of the continuous gradual increase of the water production from the field and expected ultimate recovery factor from the ongoing water flood, an extensive work program has been conducted since 2010 to identify the most suitable and effective EOR technique for the Shuaiba carbonate reservoirs. This process began with lab tests to analyze fluid behavior and core flooding experiments for the selected surfactant. Subsequently, field trials were conducted including huff-and-puff test in a vertical well and then continuous injection in two horizontal water injectors for three months. Detailed results from both lab experiments and the first field trials were documented in a prior paper (Al-Sinani et al., 2016).
This paper discusses the result of the field trial conducted in March 2018, which yielded 40 kbbl of oil gain and a 5-10% reduction in water cut during two years. The field trial took place in a mature water flood pattern with 100-meter well spacing, involving a horizontal water injector and two adjacent oil producers. Over three months, surfactant was successfully injected at a concentration of 1.3%. A robust monitoring plan, including well-testing, surface wellhead sampling, and time-lapse production logging, was carried out during and after the chemical injection.
The field trial result, along with the previous reported initial lab and field data, paved the way for the expansion of surfactant EOR into a full block including 15 water injectors and 35 oil producers. The full-block surfactant flood was planned in two phases from 2023 to 2026. Phase I surfactant injection took place in a small sector with 3 injectors and 5 producers from Jan to Apr in 2023 to validate oil gain based on the dynamic model results, re-evaluate project economics, and assess any surface and subsurface potential risks for Phase II.
In this paper, an overview of the Phase I execution including challenges will be highlighted. Obvious water cut reduction was seen within 3 months after the surfactant injection, and then the water cut went back to the historical level. A clear oil gain above water-flood base line has been observed from the pattern of Phase I within 15 months but was assessed as below initial forecast. This paper will discuss the possible reason for the lower than the expected oil gain and the future plan of the surfactant flooding in Daleel fields.
Increasing Oil Recovery Efficiency with Lean Principles: A Case Study in Aquifer Pump-Off (apo) Meter Improvement in Oman
Authors: Mahrezi D. , Fazari M. , Naabi N. , Hinai A. 
Published: November 2024

APO (Aquifer pump off) wells are used for water production to maintain the reservoir water that used for steam production. The availability of these wells is affecting directly to the steam production and the reservoir acceptance of the steam injection. All this process cycle is used for enhancing oil recovery (EOR) by steam injection to reduce the oil Viscosity. Moreover, there are different KPIs to ensure that this process more efficient like, Aquifer pump off well production KPI, water treatment plant KPI, steam production KPI and steam injection KPI.
Magnetic flow meter is used to measure the water production for each Aquifer pump off well to produce within the process limit and the daily production target.
The journey started to study the suitable flowmeter type selection, correct verification method, internal inspection to ensure that production operator and filed programmer are getting the correct measurements live and on time.
Integration of Pressure-Derived Permeability with Static Reservoir Modeling: An Adaptive Approach for Improved History matching
Authors: Tripathi Neelesh R. , Saad Ahmed M. , Shalaby Sharif M. 
Published: November 2024

Abstract
Integration of pressure-derived permeability thickness with other geological data plays a crucial role in estimating the apparent reservoir permeability, which is a key reservoir property required for reliable reservoir characterization as it governs fluid flow and greatly impacts decisions related to production, field development, and reservoir management. The geological model provides a representation of the subsurface reservoir, capturing the spatial distribution of lithology, porosity, permeability, and other geological properties. Analysis of pressure data provides valuable information on well condition, reservoir extent, and dynamic reservoir parameters. Integrating such data with the geological model is an enabler to better quantify and manage the uncertainty in the spatial 3D distribution of permeability away from well control.
This work proposes a methodology to build high-resolution geological models based on the available dynamic data, seismic data, and geologic interpretations. The geological model typically provides an estimate of intrinsic permeability, which depends on the pore structure and flow path within the rock matrix. In general, the 3D-modeled permeability honors core and well log data, which are sparse and at a significantly smaller scale compared to the reservoir size. Hence, it may not be representative of permeability farther away from the well locations, especially in carbonate reservoirs, which may have varying complex pore structures and widely varying porosity/permeability relationships. The proposed workflow incorporates pressure-derived permeability into the reservoir model prior to the matching.
The workflow iteratively modifies the permeability in the geological model to minimize the mismatch between the simulated and measured production and pressure data. The proposed workflow has been implemented on a synthetic reservoir model, showing an overall improvement in the history match quality for both deviated and vertical wells. The process enabled a more robust permeability adjustment and improved the integrated asset team's efficiency through guided iterations.
The presented methodology offers a systematic and adaptive approach leveraging pressure-derived permeability and geological information to adjust the intrinsic permeability. By integrating these datasets and enabling multi-disciplinary collaboration, the accuracy of the reservoir model is enhanced, leading to more reliable reservoir characterization, improved decision-making in reservoir management, and optimization of IRS resources and time.
Enhanced Vuggy Zone Recognition Through Merging AI-based Borehole Image Interpretation
Authors: Petrov A. , Egorov D. , Belayouni N. , Tamaazousti Y. 
Published: November 2024

Abstract
Recognizing vuggy zones in borehole imaging (BHI) presents significant challenges due to the intricate and heterogeneous nature of these geological features (fig.1). Traditional methods, which often rely heavily on subjective visual interpretation of BHI data, are prone to variability and inconsistencies. These limitations contribute to substantial uncertainties in geological modeling and subsurface characterization, impacting the reliability of reservoir assessments.
The integration of AI-driven interpretation techniques offers a transformative solution to these challenges. By leveraging advanced machine learning algorithms, we can systematically analyze high-resolution borehole imaging data, reducing the dependence on human interpretation and minimizing associated biases. These algorithms are capable of identifying subtle patterns and features indicative of vuggy zones that traditional methods might overlook or misinterpret.
AI enhances the precision and consistency of vuggy zone identification, facilitating a more rigorous quantification of uncertainties inherent in these interpretations. This not only strengthens the robustness of geological models but also leads to more accurate predictions of reservoir properties and behavior. As a result, critical decision-making processes in subsurface characterization—such as reservoir management, well placement, and production forecasting—are significantly improved. This optimization of resource extraction efforts directly translates to reduced operational risks and enhanced economic outcomes.
PDO Pumps Energy Saving Journey
Authors: Al Hashimy Z. , Al Shukaili A. , Al Araimi M. , Willcox P. , Al Zawaidi I. 
Published: November 2024

Abstract
Petroleum Development Oman (PDO) purpose is to "build a sustainable and low-carbon future to maximise value for Oman". In line with this, the Rotating Equipment function has begun an energy efficiency journey by saving electrical power, reducing fuel gas consumption and cutting Greenhouse Gas (GHG) emissions, thereby also reducing Operating expenditure (OPEX) and its Unit Operating Cost (UOC).
A study has been initiated to look for energy efficiency opportunities by checking the running parameters of equipment units compared to their design as some pieces of equipment are running inefficiently due to overdesign or process conditions have changed over the years. The study usually starts by analysing the losses from a machine using main parameters such as suction/ discharge pressure, flow, speed and efficiency. A forecast reaching 20 years ahead is included in this study to understand the required hydraulics in the future and the design required to accommodate the peak condition. After then verifying a technical proposal, a study is then undertaken to explore the best approach to re-rate the equipment by trimming the impellers, change or de-stage them, in the case of multistage machines.
To date, PDO has completed the re-rating of 20 pumps with a total yearly power saving of 7.4 MW, which is the equivalent of US$2.9 million per year and 38,000 Tonnes of CO2 emissions annually, the equivalent of US$2.3 million per year. Currently, we are executing five projects and four feasibility studies to verify the extent of such attractive savings. In this paper we will showcase the journey of PDO's pumps energy savings.
Optimization of Casing Running Operations Using Automated TRS Technology
Authors: Hasler D. , Nguyen D. 
Published: November 2024

Abstract
In integrated casing running operations, the common contributors to flat time have been identified in the processes of aligning the casing running tool (CRT) tool into the joint, making up the connection, and intermittently filling up the casing string with drilling fluid. The connection time from slips to slips can vary as a result of factors that include the driller's level of expertise, visibility of the CRT position, and the effectiveness of crew communication, but overall improvements have been achieved over the years through the use of mechanized tools that reduce makeup time. Over the years, the use of tools such as power tongs for expediting casing connections has evolved into a more advanced process that involves tying in a CRT to the top drive in parallel to the rig's operating system to automate casing string makeup.
Recognizing the areas where improvements were attainable through automation, Nabors Drilling Solutions developed integrated tubular running services (TRS) to seamlessly handle and install tubulars and execute the process efficiently and reliability. The mechanized casing running system uses a top drive to rotate and reciprocate casing strings to total depth and leverages cutting-edge technology to streamline and automate the casing installation process for optimal wellbore integrity.
Implementing an engineered solution that includes both mechanical and software enhancements to automate casing running helps bridge the gap between inexperienced and experienced drillers by executing steps of the casing running sequence without human involvement. This innovative approach delivers consistent casing connection times while eliminating the possibility of human error that can lead to misapplied torque, introduce the risk of joint damage to the casing or result in cross-threading incidents.
A field test conducted in West Texas demonstrated a 67% reduction in the time required for CRT alignment compared to the conventional method for running casing, proving that automation is both feasible and practical. This paper highlights the advancements achieved through automation and optimized processes in integrated casing running for improved performance and increased safety.
Optimizing Tubing Size for Effective Sand Transportation and Extended Life of ESP-Assisted Wells
Authors: Agarwal J. R. , Lenka M. , Ebrahim A. S. , Bourisli R. I. , Santhanagopalan S. , AI-Majdli A. , Sumarto B. A. , Mohammad R. , AlAmer R. , Vedapuri D. 
Published: November 2024

Abstract
The study examines the minimum sand transport velocities needed for different tube sizes to prevent ESP (Electric Submersible Pump) tripping and extend the lifespan of inclined wells. The methodology involves observing sand bed conditions at varying superficial liquid velocities (VSL) across different tube sizes, utilizing both OLGA modeling and experimental analysis. The studies were carried out using pure water, and the OLGA models were created based on completion schematics and fluid composition data. Sand transport phenomena were simulated with OLGA's sophisticated particle flow module, while Multiflash was used for thermodynamic fluid modeling. According to our findings, the minimum sand transport velocity is consistent across different tube diameters, specifically 2″, 2.5″, and 3″ tubes. Based on these findings, we suggest an optimal tube size of 2″ or smaller, considering a maximum flow rate of 1000 stbpd. Experimental measurements indicated a minimum sand transport velocity of 0.48 m/s, while steady-state models pointed to a requirement of around 0.4 m/s to prevent sand accumulation. Interestingly, our experiments revealed that OLGA underestimated the minimum sand transport velocity required to prevent sand accumulation. The study provides new insights into the dynamics of sand transport, emphasizing in particular the limitations of OLGA for coarser particles and inclined wells. The findings give engineers practical guidance for maximizing production and maintaining well integrity.
Leveraging Synergies from Oil and Gas Project Knowledge to Advance Hydrogen Project for South-East Asia's 1st Multifuel Refueling Station
Authors: Rashyid Mohd Amin Nor 
Published: November 2024

Abstract
This paper is written to share the best practice of capitalizing synergies from O&G project knowledge to foster and advance hydrogen projects through Darul Hana Hydrogen Refueling Station (HRS) Project. To keep pace with demand of energy transition towards sustainable sources, hydrogen has emerged as a versatile and clean alternative with vast potential across multiple sectors. This paper intends to demonstrate how knowledge and technologies captured within O&G sector by PETRONAS Project Team were leveraged, repurposed, and retrofitted to support smooth execution of hydrogen projects.
Upon its completion, Darul Hana HRS Project by PETRONAS will become the first Multi-Fuel Refueling Station in South-East Asia. The success of this project is clear evidence that collective synergies of knowledge and experience of the O&G industry and hydrogen are crucial factors in realizing the full potential of hydrogen as a key enabler of a sustainable energy transition.
By embracing the convergence of expertise from both sectors, stakeholders can unlock new opportunities and address complex challenges in advancing hydrogen technologies at much bigger capacity on a global scale.
A Biodegradable Anti-Agglomerant Leads to a Low-Viscosity, Transportable Hydrate Slurry in a Multiphase Flow
Authors: Hu S. , Nelson A. , Fan C. 
Published: November 2024

Abstract
This work presents a biodegradable anti-agglomerant (AA) that is not only environmentally acceptable (Yellow) but also able to deliver a low-viscosity, transportable hydrate slurry with dispersible hydrate particles. A high-pressure rocking cell was used to test the performance of the developed AA candidates. Compared to the nonbiodegradable AA candidates, the selected AA performed better in various scenarios. All tests included a gas mixture that forms Structure II hydrates, a clean oil sample from the field, a subcooling of approximately 15 °C, and steady-state and shut-in and restart scenarios. The AA demonstrated the ability to treat hydrate problems under water cuts of up to 50 vol% and salinities of up to 6 wt%. In addition, the product passed a series of stability and flowability tests under various temperatures and pressures. These tests aimed to qualify a chemical product for injection via a subsea umbilical line without causing any blockages or damage.