bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Holistic EOS Model for Characterization of Northern Kuwait Extra-Heavy Oil Mixed with Liquid Solvents
Authors: Al-Murayri M. T. , AlFadhli A. , Baroon B. , Soltani A. , Garifullin R. , Rousseau D. , Bekri S. , Delamaide E. 
Published: April 2024

Abstract
Liquid solvent injection is envisaged for extra-heavy oil extraction from the Lower Burgan Abdali (ADBG) reservoir in North Kuwait. This is a deep reservoir (9000 ft) where steam-assisted EOR methods are associated with a wide array of tehno-ecnomic challenges. This paper presents a methodology for creating a holistic Equation of State (EOS) describing the thermophysical properties of the selected solvents, extra-heavy oil, and their blend at different conditions. Such a model is essential for studying subsurface-to-surface variations in the mixture properties to assess the viability of solvent-assisted production.
Representative extra-heavy downhole oil samples and two multi-component liquid solvents were investigated by performing high-pressure laboratory testing. Fluid density and viscosity were measured under varying conditions. A cubic EOS model was built to reproduce the extra-heavy oil lab-based PVT data. Simultaneously, another EOS model was developed for the two solvents. These EOS models were merged into a unified model to ensure pseudo-component overlap representation and lumping of the components for a correct extra-heavy oil and solvent mixture prediction. The viscosity modelling challenges and solutions for extra heavy-oil (with and without minor dissolved gas) and solvent mixtures were also investigated in detail.
Lab evaluation using representative downhole oil samples (with minor dissolved gas) showed significant differences in the molecular weight of C36+ and the measured viscosity. A single EOS model was created using multi-fluid regression. The heaviest fraction had to be split into two pseudo-components coexisting in both samples but at different molar fractions. The components existing in both extra-heavy oil and solvent were lumped to avoid overlapping. It was demonstrated that the resulting EOS model can accurately reproduce the phase and volumetric behaviour of extra-heavy oil, solvent and their blend at different pressures and the reservoir temperature. Furthermore, it was noticed that the modified Lohrenz-Bray-Clark (LBC Heavy Oil) can predict the viscosities at isothermal conditions. For non-isothermal conditions, the viscosity of each pseudo-component is to be calculated at different temperatures in a tabulated format.
Quantitative Characterization Method for Remaining Oil Distribution in Heavy Oil After Multi-Cycle Steam Huff and Puff Based on CT Scanning
Authors: Zheng Haoyu , Hou Jian , Du Qingjun 
Published: April 2024

AbstractSteam huff and puff is an important development method for heavy oil reservoirs. An accurate description of the remaining oil distribution after steam huff and puff is crucial for reservoir development. In this study, an experimental setup is used to simulate the multi-cycle steam huff and puff process more realistically. The occurrence state and distribution of remaining oil after different cycles of steam huff and puff are investigated. CT scanning is conducted after the first, fourth, and seventh cycles. Based on characterization parameters such as shape factor, contact ratio, and Euler number, the microscopic remaining oil is classified into network remaining oil, cluster remaining oil, film remaining oil, and isolated droplet remaining oil. The volume proportions of different types of remaining oil of different cycles of steam huff and puff are compared. The viscosity of the heavy oil used in the experiment is 560 mPa·s (25°C). The results indicate that as the number of cycles increases, the volume proportion of network remaining oil decreases, while the volume proportions of cluster, film, and isolated droplet remaining oil increase. From the first to the seventh cycle, the volume proportion of network remaining oil decreases by 34.11%, while the volume proportions of cluster, film, and isolated droplet remaining oil increase by 12.87%, 14.48%, and 6.76% respectively. The oil phase transitions from a continuous distribution to a discontinuous distribution. With an increase in the number of cycles, the water saturation increases, and the distribution of remaining oil becomes more dispersed. The results of this research guide the subsequent production of heavy oil.
Evaluation of Production and Injection Profiles by a Combination of Thermal Anemometry Technology, Spectral Noise Logging, and Numerical Temperature Modeling in Horizontal Oil Producers and Water Injectors
Authors: Dolgikh A. , Shubenok D. , Chinchayan G. , Al Bahri B. 
Published: April 2024

Abstract
The limitations of conventional spinner-based methods of production logging in horizontal wells, such as low rate, oil viscosity, wellbore trajectory, and debris, have driven the development of non-mechanical technologies over the past two decades. The paper illustrates an innovative combination of several spinnerless methods as a comprehensive approach for reservoir performance evaluation based on recent field cases. The ability of a simultaneous evaluation of the fluid flow rate inside the wellbore as well as through the formation allows a complete assessment of well-reservoir performance.
For the wellbore fluid flow evaluation, the thermal anemometry method was proposed. The technique allows the detection of the fluid flow zones and the calculation of fluid velocity based on temperature changes of the permanently heated thermal anemometer sensor. The successful field tests and cases of the technique application were published in several technical papers [1, 2], where the consistency of thermal anemometry data with spinner results was proved. The current technical paper provides the fluid flow velocity calculation methodology based on the laboratory and field calibrations of the thermal anemometry tool.
Spectral noise logging (SNL) and numerical temperature modeling were proposed for the reservoir fluid flow evaluation. The mentioned methods were also successfully implemented over the last decade and confirmed by the number of published technical papers [3, 4]. For the spectral noise logging the new-generation split-channels tool was used. For the numerical temperature modeling the high-resolution temperature data acquisition was used to derive the quantitative production/injection profiles related to reservoir flow.
The paper demonstrates the results of several case studies where the combination of the spinnerless methods was applied: one oil producer and two water injectors. For oil producers, the cause of the high water cut was determined by the localization of water inflow zones. For water injectors, the evaluation of the water injection conformance across the reservoir section was resolved by calculating the detailed injection profiles.
The complex results of reviewed case studies emphasizing the wellbore-oriented and reservoir-oriented flow profiles give a broader understanding of the production/injection processes. The paper also discusses the limitations of each technique, as well as the advantages and complementarity of the comprehensive approach in general. One of the advantages discussed in the paper is a lack of mechanical elements in tools, making the combination of spinner-less methods a reliable alternative to conventional spinner-based methods for production logging in horizontal water injectors and oil producers.
The Effect of Different Miscible Degrees on the Migration of Diversified Phase Zones in the Tight Reservoir
Authors: Liu Xiliang , Chen Hao , Cheng Weiming , Xu Chenghao , Zuo Mingsheng , Gao Shuaiqiang , Wu Yi , Liu Haipeng , Qi Xinyu , Brahim Mahaman Sidi 
Published: April 2024

Abstract
Both laboratory tests and pilot wells have demonstrated the significant potential of CO2 as an EOR medium. Due to the weak pressure conduction and mass transfer of the CO2-oil system, multiple zones between the injection well and production well are generated in the ultra-low permeability reservoirs. This work aims to explore the characteristics of multiple zones and mechanisms of CO2-EOR, combining the experimental results, core-scale, and field-scale simulation.
Long core displacement experiments were conducted under different miscibility pressures with production gas assayed using gas chromatography. When the core-scale simulation matched with the experimental results, the four CO2 fronts, which were used to distinguish different zones, were defined based on pressure, interfacial tension, and CO2 concentration along the long core. The distribution of five zones was upscaled to the field-scale model after the history matching of pilot wells. The final step was to evaluate the value of the miscible zone range, utilization factor of CO2 injection, oil recovery, and CO2 storage efficiency during the CO2 injection process.
Results show that the boundary between the original oil zone and the oil transition zone exists at the CO2 component front, where the CO2 concentration is zero. Additionally, the location of the CO2 component front does not overlap with the contact interface of CO2-crude oil, meaning that the dissolution effect of CO2 in the oil transition zone results in the CO2 component front moving farther. Besides, when the formation pressure is higher than the minimum miscibility pressure (MMP), the distance between the CO2-effective phase front and the CO2-effective component front further expands as the pressure increases, enlarging the miscible zone range. The pressure accumulates around the injection well because of slow pressure conduction. When the average formation pressure reaches 1.1 MMP, the miscible zone range is enlarged by 2.7% higher than that of the near miscible flooding (0.92 MMP), leading to a higher rate of oil recovery by 8.6% and a utilization factor of CO2 by 0.14t/t.
It is for the first time that the range of five zones and the characteristics of four CO2 fronts migration is assessed, furnishing an in-depth understanding of the complicated mechanisms and phase behavior in CO2 EOR in the ultra-low permeability oil reservoir. This work contributes to providing significant information for designing an economic and environmental CO2 flooding strategy and is significant in the improvement of oil recovery and the reduction of CO2 emission.
Enhanced Gas Condensate Recovery by CO2 Injection in Low Carbon World
Authors: Nasralla Ramez , Wei Lingli , Al-Bulushi Nabil 
Published: April 2024

Abstract
CO2 injection in gas condensate reservoirs has the potential to enhance gas recovery while reducing CO2 emissions, aligning with Petroleum Development Oman’s (PDO) goal of decreasing greenhouse gas intensity and producing low-carbon oil. PDO has a rich portfolio of gas condensate reservoirs, which could be good candidates for the injection of captured CO2. However, finding the best candidate for CO2 injection may be a challenge given the diversity of the portfolio. The focus of this paper is to explore key mechanisms of CO2 injection in gas condensate reservoirs to enable the selection of the most economically attractive candidates and understand the key factors that can impact the economics of an enhanced gas condensate recovery (EGCR) project.
Conceptual and full-field simulation models were developed to estimate the potential incremental recovery and the amount of retained CO2 during the production phase of the project, allowing for the estimation of the net gas utilization factor. One-dimensional conceptual models were employed to reveal the predominant mechanisms and net gas utilization (NGU) for different scenarios, varying the depletion state of the reservoir, condensate-to-gas ratio (CGR), and injection rate. Additionally, two field examples are presented to demonstrate the expected NGU and suggest strategies for improving CO2 utilization.
The results of this study demonstrate the high potential of CO2 injection to maximize the recovery of gas condensate. In addition, this study demonstrates the importance of the miscible displacement of condensate by CO2 for depleted reservoirs over revaporization, which requires higher pressure than miscible displacement and hence higher amount of CO2. The results suggest that CO2 injection in less depleted gas condensate reservoirs at the start of CO2 injection can be more economically attractive than in depleted reservoirs due to the better net gas utilization (NGU) of CO2. For highly depleted reservoirs, higher injection rates are required to increase pressure, resulting in poor NGU compared to less depleted reservoirs. The study also highlights the importance of optimizing injection rates and/or injection durations to maximize oil production per ton of injected CO2.
In conclusion, while CO2 injection presents significant opportunities for enhancing gas condensate recovery and CO2 storage, the economics of such projects are contingent upon improving NGU and ensuring the cost-effectiveness of CO2 capture, transport, and injection compared to oil revenue.
Applications of Intelligent Formation Breakdown Automation Algorithms in Tight Formation for Creating Conductive Propped Fractures, Improving Pumping Efficiency and Maximizing Hydrocarbon Productivity
Authors: El-Sayed M. , Abdelhalim M. , Seada M. , Mahmoud B. , Farouk E. , Bapetco A. Maher 
Published: April 2024

Abstract
Hydraulic Fracturing is one of the most widely used reservoir stimulation techniques for enhancing production of hydrocarbons from various subsurface formations. Although the nature of hydrocarbon-bearing formations can vary being conventional and unconventional formations, high perm and tight formations, hydraulic fracturing will be the primary stimulation technique to be considered with all challenges that can be faced. One of these challenges arose in this method of stimulation is the formation breakdown and fracture initiation processes that can be accompanied with high pumping pressures in the beginning of the treatment. Uncontrolled formation breakdown can affect hydraulic fracturing treatment impeding creating a dominant fracture geometry due to initiation of multiple fractures increasing leakoff during pumping accordingly increasing treatment placement risk and dampening fracture efficiency in tight formations with near-wellbore complexity.
This paper discusses the applications of how smart algorithms can optimize pumping parameters using an intelligent automation to achieve maximum fracture conductivity and stimulated reservoir volume in tight formations. The proposed approach involves the use of automated engineered breakdown technique to reduce pumping pressures thus giving more room for increasing proppant concentration hence improving overall surface efficiency even in tight gas formations where formation breakdown and rate establishment become more formidable to achieve.
This paper will review some treatments where the intelligent engineered breakdown automation technique was applied in formations that are tight and have near-wellbore complexities in different fields of Egypt’s western desert. This study will include reservoir quality, well geographic data, OHL interpretation, diagnostic pumping analyses, formation responses and placement challenges and productivity results. In addition, will highlight and compare the results with some case histories of offset wells where the intelligent engineered breakdown automation technique was not used.
Combining digitalization, artificial intelligence and reservoir stimulation techniques will allow maximizing the value of assets and natural resources which is vital in the current marketing conditions.
A Unique Solution Designed to Deploy 15k Multi-Stage Fracturing Systems Successfully in Horizontal Wells With Complex Profiles, Resulting in 100% Success Rates with 6 Days of Savings Per Well
Authors: Agarwal Rohit , Bansal Sarvodaya , Levario Jesus , Corona Mauricio , Alismail Ahmed , Paz Daniel 
Published: April 2024

Abstract
Deployment of Open Hole Multistage Fracturing (OH MSF) completion system in long horizontal wells has always been a daunting task, and often presents high risk of getting stuck in open hole due to complex completion design with very stiff assemblies that include multiple large OD packers. This paper introduces a novel technology called Cemented MSF, which addresses the deployment risks associated with OH MSF. Notably, this technology eliminates the need for time-consuming coil tubing operations for plug-and-perf, thereby avoiding production delays.
The paper examines the major bottleneck in deployment of OH MSF, a very stiff completion string, which is particularly influenced by the number of stages, elevating the risk of equipment getting stuck in the open hole due to ledges and washout created while drilling the reservoir. Consequently, there is a constant trade-off between maximizing deployment chances and minimizing the risk of getting stuck by reducing the number of stages. However, this trade-off comes at the expense of production efficiency.
Cemented MSF is a hybrid integrated system that provides all the production benefits of OH MSF without the deployment risk. In this novel solution, OH packers are eliminated, and the completion is run like a cemented liner. The cemented MSF lower completions was successfully implemented in a long horizontal well with &gt; 6,000 ft of reservoir contact. While drilling the lateral section, this system enables greater degree of directional flexibility and navigation control as compared to conventional OH MSFs, which have very strict limitations for dogleg and inclination citing risk of deployment complexities with the stiff completions string. Having no OH packers eliminates the need to record open hole logs for packers placement and further eliminates the need for a simulation run (Dummy Run) to simulate actual completion string stiffness, resulting in a direct savings of minimum six-days. Furthermore, to ensure that the frac ports are not activated prematurely, a fit for purpose cementing program was developed using precise volume and hydraulic displacement calculations and optimum shoe track length. Among the unique features of this system is its ability to run maximum possible stages, ensuring that productions will not be compromised. At the end of completion phase, the frac. Ports can be activated by dropping balls just like a conventional OH MSF system and prepare the well for production.
The paper outlines essential design considerations, checkpoints, an execution phase roadmap, and potential contingencies related to the deployment of the Cemented MSF technology.
Functional Neural Networks Model for Prediction of the Formation Tops in Real-Time While Drilling
Authors: Mahmoud Ahmed Abdulhamid , Elkatatny Salaheldin , Abdulraheem Abdulazeez , Gowida Ahmed 
Published: April 2024

Abstract
The determination of formation tops while drilling plays a pivotal role in the efficiency and cost-effectiveness of the drilling operations. Identifying lithology changes in real-time is crucial for adapting drilling programs, optimizing well designs, and ensuring the overall success of the drilling process. Real-time detection of lithology changes provides a valuable tool for mitigating uncertainties associated with geological data limitations, especially during the exploration phase. As formations vary in composition and characteristics, the ability to predict these changes enhances the overall management of drilling operations, minimizing risks and contributing to the economic viability of oil well projects. Current methods for detection of the formation tops rely on geological data, introducing uncertainties, especially in exploration due to data limitations. This study explores the real-time predictive capabilities of the functional neural networks (FNNs) for the prediction of the formation tops. Trained on 3162 datasets of six drilling parameters, the FNNs model aims to predict lithology changes and formation tops across the sandstone, anhydrite, carbonate with shale streaks, and carbonate formations. Testing on 1356 datasets from a different well validated the FNNs model. Results affirm the FNNs accurately predicted the carbonate/shale formation top in training data, while it struggled to accurately predict tops for all formations in testing data compared to the reported high accuracy for the artificial neural networks model.
Unlocking Reservoir Potential with Logging-While-Drilling Technologies in Mature Fields
Authors: Taher A. , Fouda M. 
Published: April 2024

Abstract
Wireline logging has been the preferred primary formation evaluation tool commonly used for decades for assessing reservoir quality. However, where the complexity of the well plan and uncertainty in formation pore pressure may necessitate decision making in real time, logging while drilling (LWD) has become more commonplace.
Assessing the reservoir properties of previously drilled laterals presents a challenge due to hole condition deterioration over time. Even if the borehole is stable and competent while drilling, it might be subject to time-dependent deterioration that could be due to reservoir pressure depletion. LWD tools can be used to re-evaluate previously drilled wells as well as log new wells while drilling. In some wells it is required to measure the formation pressure to be able to log, deepen, and consequently drill several laterals from existing wellbores. The uncertainty in formation pressure depletion can result in operational delays due to difficulties in optimizing the mud weight window based on available data. LWD tools, including formation testers, can be utilized in real time to acquire formation pressure and mobility information, which are key measurements for mud-weight optimization and confirming the feasibility of drilling deeper.
LWD tool strings, including formation testers, have been used to acquire real time formation evaluation and reservoir pressure measurements in formations which had previously limited success due to the relatively low mobility, decreasing the likelihood of obtaining a reliable measurement. Lessons learned have been developed to implement best operational practices in successfully testing in these low mobility environments.
Gamma Ray, Resistivity, density, neutron, and NMR LWD sensors were also used in the bottom hole assembly (BHA) to replace wireline logging due to the risks associated with wireline deployment under these unfavorable hole conditions. Measurement integrity and data quality provided by LWD sensors have been evaluated and used for the design of multilateral wells.
This paper presents the effective utilization of LWD technologies to address operational risks of logging highly deviated well while facilitating robust formation evaluation for this development re-entry drilling program.