bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advancing Reservoir Understanding: Integrating Deep Learning into Automated Formation Micro-Imaging Log Interpretation for Enhanced Reservoir Characterization and Management
Authors: Gharieb Amr , Gabry Mohamed Adel , Elsawy Mohamed , Algarhy Ahmed , Ibrahim Ahmed Farid , Darraj Nihal , Sarker M. R. , Elshaafie Ahmed 
Published: April 2024

Abstract
The Formation Micro-Imager (FMI) produces high-resolution borehole images, crucial for identifying geological features like bedding and fractures, aiding in reservoir characterization. Its sensitivity to mineralogy and fluid content variations enhances its utility in subsurface analysis for optimizing hydrocarbon extraction strategies. However, interpreting FMI logs requires expertise and experience due to the complexity and nuances of the images, posing challenges in obtaining accurate geological information. This research harnesses the capabilities of automated Formation Micro Imager (FMI) interpretation combined with expert calibration to innovate the analysis of subsurface stress fields, striving to improve the accuracy of geo-mechanical modeling and optimize water-flooding projects, particularly those necessitating hydraulic fracture stimulations. It revolves around the creation of accurate local stress maps using FMI data, specifically drilling-induced fractures, to determine the present-day maximum horizontal stress (SHmax) orientations, thereby informing wellbore stability and drilling strategy optimization. This study utilizes advanced logging techniques to identify borehole breakouts and other enlargements, which are critical for accurate in-situ stress estimation. This process is supplemented by a comprehensive analysis of multiple wells, revealing the variability and predominant orientations of SHmax with the regional tectonic framework.
The study uncovers the significant variability of SHmax orientations, aligning predominantly with major fault trends within the Egyptian Western Desert's complex geological structure. The results from this analysis facilitate an updated regional stress map, indicating the prevalence of normal and strike-slip faulting regimes. Additionally, the research extends to reservoir management, where automated FMI log interpretation aids in optimizing hydraulic fracture directions in Field A, contributing to more efficient hydrocarbon extraction and better reservoir pressure maintenance strategies.
The novel integration of FMI data with deep learning applications presents a groundbreaking approach to subsurface analysis. It offers a new perspective on managing reservoirs by strategically placing water injector wells to support hydrocarbon production while maintaining reservoir integrity. This method enhances the predictive capability of simulation models, ensuring more accurate performance matching and better-informed decision-making in production strategies. The study's approach combines geological insights with advanced technology, offering a substantial advancement in the field of geo-mechanics and reservoir characterization.
Experimental Studies of Sulfonated Polymer Adsorption in Carbonates Under Challenging Conditions
Authors: Mahboob Ahmad , Hassan Anas M. , Khan Sarmad Z. , Sebastian Anoo , Mushtaq Muhammad , Al-Shalabi Emad W. , Zeynalli Mursal 
Published: April 2024

Abstract
This study investigates the dynamic adsorption behavior of an ATBS-rich hydrolyzed polyacrylamide (HPAM) polymer onto two different permeability carbonate rocks under varying salinity and high temperature conditions. The approach followed here is aimed at unraveling the complexities of polymer-rock interactions during enhanced oil recovery (EOR) operations and focuses on evaluating dynamic polymer retention in coreflooding experiments performed at 80°C. The analytical techniques used in this research include Ultraviolet-visible (UV-Vis) spectroscopy, Inductively Coupled Plasma (ICP), and Rheometry, which were employed to analyze the behavior of the polymers under these specific conditions. Notably, the results demonstrate that polymer retention levels are significantly influenced by the salinity of the brine and the permeability of the core. In the case of using diluted brine (5,767 ppm) and high permeability core (419 mD), polymer retention levels were substantially lowered, recorded at 37 µg/g-rock. Conversely, in the higher salinity seawater environment (57,670 ppm) combined with a lower permeability core plug (195 mD), retention levels were higher, reaching 57 µg/g-rock. This variation in polymer retention was further supported by the observed low residual resistance factor in conditions where lower polymer retention was recorded. Additionally, the study identified the occurrence of shear thickening behavior for the AMPS-based polymer during in-situ rheology characterization. These findings are crucial for understanding polymer behavior in different reservoir conditions, providing valuable insights for optimizing enhanced oil recovery processes.
Chemical Reduces Risk of Stuck Pipeline Cleaning Equipment in Deepwater Subsea Flowlines
Authors: Rodriquez R. X. , Bufton S. A. , Blanchard T. J. , Schuttler R. 
Published: April 2024

An oil export pipeline connected to a deepwater production facility in the Gulf of Mexico requires periodic pigging to manage wax deposition on the pipe wall. The facility used in this paper is in the Viosca Knoll Federal lease blocks, located approximately 120 miles SE of New Orleans, LA in a water depth of approximately 3,250 ft. This facility is a Tension Leg Platform (TLP) floating system set on two pontoons which are anchored to the sea floor. Since it was installed in 1999 many modifications have been made to the facility to allow it to serve as a hub to multiple subsea fields, implementing new technologies encompassing enhanced oil recovery techniques and modified process systems to facilitate safe, effective, and environmentally sound exploitation of the asset base.
The production facility separates oil and gas, then exports each to shore via separate oil and gas export pipelines. It is important to manage wax deposition on the inner wall of the oil export pipeline, which consists of 22 miles of uninsulated 10-in diameter pipe (Fig. 1). This facility's base wax management strategy for the oil export system consists of periodically launching pipeline cleaning pigs and continuously injecting paraffin inhibitor (PI). The current pipeline routine cleaning frequency, pig type, and PI injection rate have been optimized over time.
When the pipeline cleaning pig launcher failed in 2021, a new design needed to be engineered, fabricated, tested, and installed. The expected time required to resume routine pigging for wax management raised concerns regarding excessive wax deposition in the export flowline. Being temporarily without pigging capability triggered mitigation measures such as increased chemical injection concentration, additional scrutiny of pipeline pressure and flow data, and design of a conservative progressive pigging campaign to enable eventual resumption of periodic aggressive maintenance pigging.
The Integrity of Idle and Abandoned Wells in California
Authors: Rehak M. , Warburton D. , Daneshvarnejad N. , Ershaghi I. 
Published: April 2024

Abstract
One of the critical challenges of California's 2045 carbon neutrality plans is the sources of greenhouse gas emissions (GHG) and the states' methods to improve emissions. This work provides insight into plugged wells, idle wells, and their potential for emission of methane and emission interferences these wells have with the states' carbon-neutral plans. Alternative solutions exist to abandon certain idle wells. Repurposing wells can generate revenue for oil and gas operators. By repurposing wells, operators can significantly reduce the cost of decommissioning the wells, highlighting the need for risk assessment in wells with the potential to leak methane.
By studying over 330 randomly selected plugged and abandoned wells throughout California, this study demonstrates how the condition of idle well emission needs further investigation. The potential benefit of confirming if plugged and abandoned wells are leaking methane into the atmosphere is assessed while the methods for characterizing wellbores are identified. Based on California's carbon neutrality goals, assessing the potential of a well for leaking methane into the atmosphere is dependent on the well's integrity changes, improper plugging, and geological shifts, including a detailed approach to the evaluation of characterizing wells based on the potential for cracks in the wellbore cement, inadequate cementation, or likelihood of fluid release through tectonically induced pathways based on wellbore diagrams and the cement class. This study can be of benefit to regulatory agencies and operators for improved development towards GHG emission reduction.
Temperature Warmback Test Design and Interpretation in Presence of Long Injection History
Authors: Zeidouni M. , Kohzadi H. , Zamehrian M. 
Published: April 2024

Abstract
Fluids are often injected at different temperature than the target injection zone in the subsurface. Hence, temperature warmback is observed during well shut-in following injection of cooler fluid. Warmback analysis has been previously presented to determine the injected fluid distribution over the injection zone. However, when the warmback is preceded by a long injection history, warmback analysis can be challenging. The temperature/rate information for the long injection history may not be fully known and if known, it is computationally difficult to account for such large volume of data in the warmback analysis. More importantly, the long injection has likely perturbed the background temperature significantly through various thermophysical processes.
Warmback analysis independent of the injection history should be enabled which is the purpose of this work. We introduce design considerations to conduct the warmback test so that the need for the prior injection history is eliminated. In addition, a simple graphical technique is introduced to enable analyzing the warmback data independent of the geothermal temperature which should be treated as unknown especially in presence of long prior injection. Warmback analysis must become independent of the initial temperature. The graphical method presented in this work requires plotting and line-fitting the observed warmback temperature versus its log-derivative with respect to the shut-in time ratio. The slope of the line-fitted data is inversely proportional to injectivity. Therefore, the graph provides the injection profile when plotted for various flow units (layers) of the laminated injection zone. The graphical method rigor is shown through its application to synthetic and field data.
Integrate Carbon Sequestration in Enhanced Geothermal System Through Surface Dissolution
Authors: Zhang G. , Norbeck J. , Smith A. , Dadi S. , Galban G. E. 
Published: April 2024

Abstract
Enhanced geothermal system (EGS) provides a pathway for geothermal energy development beyond traditional regional constraints, offering a cost-effective and carbon-free energy solution. The potential to integrate carbon capture and sequestration (CCS) within geothermal operations; however, remains an open question to be investigated. This study examines the feasibility of CO2 geological sequestration within enhanced geothermal frameworks. We investigated CO2 storage incorporating a surface dissolution strategy under normal operational conditions of EGS, utilizing thermodynamic models and reservoir simulation. Our findings demonstrate the viability of storing CO2 in geothermal reservoirs, as indicated by the net mass of CO2 storage and the plume migration distance. Hydraulically fractured geothermal reservoirs can accommodate CO2 plume migration, even in ultra-tight reservoirs with permeabilities as low as 0.01 millidarcies (mD). A comprehensive sensitivity analysis, including parameters such as rock porosity, reservoir permeability, thickness, well arrangement, and fracture design, revealed optimal conditions for CO2 sequestration and identified key mechanisms in CO2 storage. Further exploration into CO2 storage in an actual EGS reservoir highlighted the benefits of a complex fracture network, which enhances interactions between wells, fractures, and the matrix. Additionally, we addressed critical issues in implementing CCS with EGS, including sourcing CO2 from direct air capture (DAC) facilities integrated with geothermal power plantsand problems associated with in-situ sequestration. Leveraging geothermal heat, built facilities, and generated energy to operate DAC facilities is a beneficial approach. The advantages are further accentuated when carbon credits are considered. In geological storage, the buildup of injection pressure is a pivotal factor for storage operations within ultralow permeability reservoirs. Another challenge is the exsolution of CO2 from brine during the production process in geothermal operations. The produced CO2, flowing alongside the production well, necessitates separation and cycling back into the system. This research exemplifies the innovative integration of EGS with CCS. By revealing new avenues for CO2 sequestration, we position EGS as a valuable adjunct to conventional CCS techniques. The synergy of technologies underscores an innovative path toward a more sustainable energy landscape.
Mechanisms of Hydrogen Generation During In-Situ Combustion Gasification of Heavy Oil
Authors: Ifticene Mohamed Amine , Yuan Qingwang 
Published: April 2024

Abstract
Carbon-zero hydrogen (H2) production directly from petroleum reservoirs is of paramount importance as the world strives to combat climate change and seeks sustainable energy solutions. In-situ combustion gasification (ISCG) represents a novel approach for leveraging the abundant heavy oil reserves to generate clean hydrogen in situ. However, the crucial reaction mechanisms for hydrogen generation are lack of understanding. It has not been validated which reactions dominate hydrogen generation experimentally during the ISCG process. This study aims to describe the governing chemical reactions and mechanisms of hydrogen generation during ISCG of heavy oils. Experiments were conducted using a self-designed kinetic cell. Heavy oil and its generated coke were used for combustion and gasification experiments, respectively. Results from combustion experiments showed that the heavy oil generated enough coke, and a peak temperature of 600 °C was achieved during combustion. The clay minerals from reservoir sand had a catalytic effect on the oxidation reactions of heavy oils. Gasification experiments showed that hydrogen generation started at 450 °C and peaked at 900 °C. Hydrogen was generated in three different stages. The main mechanism for hydrogen generation was coke gasification followed by the water-gas shift reaction. It was also observed that methane was released due to hydrogen consumption by methanation reactions. Furthermore, the minerals from reservoir sands inhibited hydrogen generation reaction and accelerated hydrogen consumption at high temperatures. Hydrogen generation can be optimized if the reservoir temperature is maintained between 700-750 °C. This work identifies the governing chemical reactions and paves the way for the development of future kinetic models to simulate hydrogen generation through the ISCG process. It highlights the importance of mechanistic control of the process to enhance hydrogen generation and suppress hydrogen consumption reactions. Importantly, it will lay a fundamental foundation for designing the field pilot and improving the success of the implementation of ISCG technology for clean hydrogen production directly from heavy oil reservoirs.
Classification and Evaluation of Microscopic Pore Structure in Carbonate Rocks by Integrating MICP-Based Dynamic Information
Authors: Wang Muyuan , Wu Keliu , Chen Zhangxin , Li Jing , Feng Dong 
Published: April 2024

Abstract
In carbonate reservoirs, the establishment of a coherent correlation between petrophysical static rock type (PSRT) and petrophysical dynamic rock type (PDRT) schemes poses a formidable challenge due to its petrophysical complexity. Additionally, the interpretation of the dynamic properties of microscopic pore structure (MPS) based on mercury injection capillary pressure (MICP) data has been an issue. The objective of this study is to alleviate the divergence in flow properties in MPS classification and evaluate the oil recovery potential of different MPS quantitatively based on MICP.
A total of 76 core plugs without fractures were studied from the Middle East region. The data set available included helium porosity, gas permeability and high-pressure mercury injection. MPSs were qualitatively classified according to the morphological characteristics of the MICP data correlated oil recovery potential. Unsteady-state oil-water relative permeability tests were subsequently conducted to ensure the effectiveness of the classification. Sensitivity parameters were correlated with the efficiency of mercury withdrawal and condensed with the factor analysis (FA) method. After dimensionality reduction, interpretable general factors were obtained to quantitatively characterize the oil recovery potential of MPS and to establish a core quality evaluation model from a dynamic view.
Results showed that the proposed classification can maintain the consistency of dynamic attributes in five qualitative categories and significant differences were observed among the different MPSs. A total of five sensitivity parameters were screened to quantitatively characterize the oil recovery potential of MPS. Moreover, FA defines three aspects that affect the ability to oil recovery: sweep, displacement, and storage. The relative relationship between the MPS and oil recovery potential predicted by the evaluation model and the laboratory-measured oil recovery are in general agreement, and this relative relationship can evaluate the oil recovery potential based on the MPS without the laboratory-measured oil recovery.
This work presents a qualitative classification method for reducing the discrepancy between PSRT and PDRT. The proposed quantitative evaluation model provides new insights into the effects of MPS on fluid flow. Both of them can improve the screening of representative samples for special core analysis and accurate numerical simulation of carbonate reservoirs.
Parametric Study of CO2 Sequestration in Deep Saline Aquifers Using Data-Driven Models
Authors: Khan M. I. , Khanal A. 
Published: April 2024

Abstract
Large-scale geo-sequestration of anthropogenic carbon dioxide (CO2) is one of the most promising methods to mitigate the effects of climate change without significant stress on the current energy infrastructure. However, the successful implementation of CO2 sequestration projects in suitable geological formations, such as deep saline aquifers and depleted hydrocarbon reservoirs, is contingent upon the optimal selection of decision parameters constrained by several key uncertainty parameters. This study performs an in-depth parametric analysis of different CO2 injection scenarios (water-alternating gas, continuous, intermittent) for aquifers with varying petrophysical properties. The petrophysical properties evaluated in this study include aquifer permeability, porosity, relative permeability, critical gas saturation, and others. Based on the extensive data collected from the literature, we generated a large set of simulated data for different operating conditions and geological settings, which is used to formulate a proxy model using different machine learning methods. The injection is run for 25 years with 275 years of post-injection monitoring. The results demonstrated the effectiveness of the machine learning models in predicting the CO2 trapping mechanism with a negligible prediction error while ensuring a low computational time. Each model demonstrated acceptable accuracy (R2 &gt;0.93), with the XGBoost model showing the best accuracy with an R2 value of 0.999, 0.995, and 0.985 for predicting the dissolved, trapped, and mobile phase CO2. Finally, a feature importance analysis is conducted to understand the effect of different petrophysical properties on CO2 trapping mechanisms. The WAG process exhibited a higher CO2 dissolution than the continuous or intermittent CO2 injection process. The porosity and permeability are the most influential features for predicting the fate of the injected CO2. The results from this study show that the data-driven proxy models can be used as a computationally efficient alternative to optimize CO2 sequestration operations in deep saline aquifers effectively.
Numerical Simulation of CO2 Storage in the Soft Sediments of Depleted Reservoirs in the Gulf of Mexico
Authors: Hashemi Sam S , Kovscek Anthony 
Published: April 2024

Abstract
Depleted oil and gas reservoirs are among the most popular formations for large-scale geologic CO2 storage. While extensive research and characterization have been conducted on the geological structure and physical properties of many of these fields, the lack of field and core sample data related to reservoir flow and mechanical properties has hindered the assessment and modeling of CO2 storage, especially in offshore areas. In this study, we developed a coupled flow-geomechanical numerical model to evaluate the potential for storing CO2 in the soft sediments of the West Delta field of the Gulf of Mexico. The poroelastic parameters of the reservoir rocks were measured in the laboratory and the geological model of the reservoir was constructed based on the available seismic and well logs. The process of reservoir depletion was simulated to consider the effect of porosity reduction and permeability change. Pore volume multipliers were employed at the boundary to reach realistic pressure in the reservoir after depletion. A modified Cam-Clay model was used as the mechanical failure criterion to trace the porosity and formation subsidence. The results showed that the porosity reduced somewhat during the depletion and then increased during the CO2 injection. The porosity, however, did not fully recover after the injection process was completed. The maximum subsidence of the storage formation top reached almost 24 cm at the well location once the depletion completed. The pressure buildup at fault zones varied based on the vicinity of faults to the injection well, fault dip, dip direction, and CO2 injection rate. Sensitivity analysis using Fault Slip Potential (FSP) showed that various geomechanical parameters such as SHmax orientation, friction coefficient and dip of the fault influenced the probability of fault slip markedly. Assuming that faults are sealed, the pressure perturbation required to slip one of the major faults in the reservoir volume studied was lower than the calculated pressure buildup after the CO2 injection. The other two major faults are not predicted to have the potential for activation in any scenario. Therefore, it is advisable to conduct additional mechanical characterization particularly focusing on in-situ stress orientation and the transmissibility of faults as further work. This precautionary measure aims to mitigate the risk of fault activation during or after the injection phase.