bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Simplified Kinetic Model for Hydrogen Generation During In-Situ Combustion Gasification of Heavy Oil
Authors: Ifticene Mohamed Amine , Li Yunan , Song Ping , Yuan Qingwang 
Published: September 2024

Abstract
In the global push for sustainable energy, in-situ combustion gasification (ISCG) has emerged as a transformative technology to leverage the world's abundant heavy oil reserves for producing carbon-zero hydrogen. Chemical kinetics are crucial for modeling subsurface hydrogen generation and optimizing production schemes to maximize hydrogen yield, which are however currently lacking. This study aims to develop the first experimentally validated kinetic model for hydrogen generation during ISCG of heavy oil. To accurately model ISCG reactions, particularly hydrogen generation, we combined kinetic cell experiments with numerical modeling to history-match the experimental results. The temporal variation of generated gases, such as hydrogen, measured in laboratory experiments, served as the baseline for history matching. A differential evolution optimization algorithm was employed to calibrate the kinetic parameters of the numerical model with experimental results. The kinetic model for combustion reactions was accurately calibrated using combustion experiments. This accuracy is attributed to the well-studied nature of heavy oil oxidation and the comprehensive reaction scheme employed. Conversely, calibrating the kinetic model for gasification reactions with kinetic cell experimental results proved more challenging. Despite significant uncertainties in hydrogen generation and consumption reactions due to limited knowledge of the gasification process, our proposed kinetic model can still predict hydrogen generation with a simplified but powerful reaction scheme, compared to previously proposed ISCG models that involve numerous reactions. This work introduces the first kinetic model to describe the hydrogen generation process during ISCG of heavy oil with rigorous experimental validation. This reliable kinetic model establishes a solid foundation for future multi-scale reservoir simulation and further optimization of the field development for enhanced hydrogen production in a more sustainable manner.
Assessment of Storage Efficiency Factor of Deep Saline Aquifers Using Early 500 Ktonnes of Injected CO2 at the Aquistore CCS Site
Authors: Vahidinia Shima , Shokri Alireza Rangriz , Chalaturnyk Rick 
Published: September 2024

Abstract
Estimation of effective storage capacity of the subsurface formations is currently one of the main technical and financial challenges for the Carbon Capture and Storage (CCS) industry. This factor indicates that not all available pore space will be accessible for CO2 storage. Even within accessible pore spaces, complete saturation with CO2 might not occur. This paper presents the evolution of storage efficiency factor during CO2 injection into a hyper-saline clastic formation.
Values of storage efficiency factor were estimated based on 8 years of CO2 injection at Aquistore. Aquistore, the storage component of the Boundary Dam CCS project in Canada, aims to address the practical aspects of injecting large scale CO2 into a 3.4 km deep aquifer. The process involved analyzing CO2 injection data and employing multiple realizations of reservoir simulations that were calibrated to the time-lapse seismic surveys. We used the USDOE static storage estimation methodology for each geological layer in addition to the whole saline system and compared the results with dynamic CO2 storage efficiency from Aquistore.
Multiple detailed geological and property models were derived from well logs and core analysis at Aquistore. Reservoir simulation cases were constructed for both the storage formations and the overlying caprock to explore the impacts of geology, trapping mechanisms, and injection schemes on storage efficiency. A wide range of time-dependent storage efficiency values were determined for each geological layer through history matching the flow simulation models to the Aquistore injection history in addition to the CO2 plume propagation determined from multiple 4D seismic data. The impacts of assumed degree of uncertainty in geologic and flow properties were considered on the overall storage efficiency factor. The estimation was highly affected by cutoff parameters to delineate the net thickness of the storage formations as well as the averaging technique used for petrophysical properties, especially in the case of multi-perforated zones. Lastly, the evolution of effective storage efficiency was discussed in the context of cold CO2 injection where non-isothermal localized fracturing, salt precipitation, and multiphase conditions could affect the early CO2 injectivity.
Utilizing actual field data of over 500 ktonnes CO2 injection from the Aquistore CCS project is an asset to storage efficiency and capacity estimations. Our results provide a better understanding of evolution of storage efficiency factor in saline aquifers, offering valuable insights into the long-term prospects of geological CO2 storage projects.
Field-Scale Optimization of CO2 Injection Schedule with Critical Pressure and Plume Boundary
Authors: Fu Jia , Alghawi Yaser , Datta-Gupta Akhil , Manche Cameron , Clark Jim 
Published: September 2024

Abstract
This study aims to develop a field-scale CO2 injection optimization workflow to refine the injection strategy and enhance storage capacity while managing the extent of the Area of Review (AoR). We utilize the concepts of critical pressure and plume boundary to evaluate the AoR delineation during injection optimization. The optimization workflow is enhanced by an advanced upgridding technology to accelerate simulations. We evaluate the feasibility of CO2 storage with AoR delineations using varied injection schedules.
We employ an advanced upgridding technique to accelerate the optimization workflow. Our approach involves an ‘optimal’ layer design through sequential coarsening using a distance-based error metric while minimizing the loss of heterogeneity between fine-scale and coarsened models. A recursive analysis is applied to develop the optimal layering while preserving geological heterogeneity and reducing the number of layers for computational efficiency. After optimal layer design, a novel pressure transient upscaling is introduced to upscale transmissibility based on local flow solutions, which preserves reservoir quality and reservoir flow barrier and is particularly well-suited for high-contrast systems.
Our proposed workflow is tested to optimize the injection schedule for field-scale application of CO2 storage in saline sands along the Texas Gulf Coast. Field-scale evaluation and optimization of CO2 storage using a high-resolution compositional model can be computationally demanding. This is compounded by the fact that optimization of the injection schedule requires a large number of flow simulations to examine a multitude of scenarios. First, the performance of the upgridding scheme was evaluated based on computational speed up and comparison of the well responses and dynamic reservoir properties from the fine-scale model. We examined three different approaches for distance-based errors to quantify the loss of heterogeneity: velocity-based distance, slowness-based distance, and hyper-volume weighted distance. The optimal layer design scheme resulted in approximately an order of magnitude speed up in computation time, which greatly facilitated the field-scale CO2 injection optimization. The injection schedule was optimized to maximize storage capacity while minimizing the AoR extent to avoid potential contamination of USDW. The injection zone selection involved the evaluations of flow unit geometry, reservoir properties, zone interference, and their influence on the AoR extent. The optimization of the injection schedule was carried out iteratively and heuristically, applying learnings from previous simulation scenarios.
The proposed workflow provides an efficient way to evaluate AoR extent and optimize the injection schedule while providing valuable guidelines for future carbon storage projects.
Downhole Pressure Wireless Monitoring via Electromagnetic Waves Transmission in Oil Well Production
Authors: Yang Haitao , Lu Hongjun , Li Dajian , Wang Yahui , Zheng Gang , Gan Qingming , Rong Guanghui , Hu Zijian 
Published: September 2024

Abstract
Pressure monitoring is one of the crucial dynamic parameters in the production process of oil wells. Due to the large number and wide distribution of oil wells, the use of wired monitoring technology aims to reveal downhole production dynamics in some high-production-rate or key wells, there are difficulties such as high production costs, large analysis workload, high risks, and maintenance of monitoring tools, which are not suitable for large-scale promotion. The lack of intuitiveness and timeliness in conventional storage pressure monitoring has brought enormous difficulties to the normal management of oil wells. However, the wireless data transmission method of Electromagnetic Waves Measurement While Drilling (EM-MWD) cannot be directly implemented into oil production wells.
On the basis of technical research and drawing on the wireless monitoring experience of EM-MWD, the 3 different electromagnetic wave excitation methods were compared, and an asymmetric oil tube antenna electromagnetic wave excitation method suitable for matching the characteristics of the pumping well was identified. Mathematical models of the wellbore formation were established. Based on finite element analysis, a simulation model of electromagnetic wireless monitoring under the pumping well was constructed, and the influencing factors of electromagnetic wave transmission were analyzed, including the influence of formation wellbore, casing, and well fluid media on electromagnetic waves. After conducting research on the structural principles and weak signal processing methods, a wireless monitoring system for ultra-low frequency electromagnetic wave downhole monitoring data, combined with downhole electromagnetic wave transmitter and surface receiver for pumping wells, is formed.
By installing a transformer on the output end and adjusting the voltage, the simulated test ground can achieve electromagnetic wave signal acquisition at a depth of 1500 meters and meet the analysis requirements. Through on-site testing at X well, when the well depth reaches 1517m, the signal can be transmitted normally; The signal acquisition frequency band of the wireless transmission system for underground pressure is once per 5-1440 minutes, and the pressure measurement range is 0-100MPa; The accuracy of downhole measured pressure data by sensors reaches 80%.
The development of a wireless monitoring system for downhole pressure in pumping wells is of great significance for dynamic monitoring of reservoir pressure and intelligent reservoir construction. Downhole dynamic monitoring achieves intuitive and timely monitoring, providing a new tool for real-time understanding and mastery of reservoir dynamic changes; Compared to conventional cable control monitoring methods, it is expected to significantly reduce costs and help promote on-site application.
East Nesson Bakken Huff ‘n’ Puff Enhanced Oil Recovery Second Pilot: Water-Alternating-Gas Injection using Produced Gas and Water
Authors: Pospisil G. , Griffin L. , Pearson C. M. , Dalkhaa C. , Sorensen J. , Kurz B. , Bosshart N. , Assady A. , Zhao J. , Warmack M. , Ren G. , Giesbrecht R. , Herman G. C. 
Published: September 2024

Abstract
In 2023, Liberty Resources LLC (Liberty) deployed an enhanced oil recovery (EOR) pilot via a single huff ‘n’ puff (HnP) well in a 2560-acre spacing unit at the East Nesson site in Mountrail County, North Dakota. This was the second EOR pilot at this site and the third by this operator in the Bakken. The prior pilot at the East Nesson site was deemed effective, resulting in incremental oil production by using a novel technology for coinjecting pulses of produced gas and freshwater with surfactant. The objective of this second pilot was to improve economics and simplify injection operations by using readily available equipment and sources of water and gas in a water alternating-gas (WAG) scheme. Oil recovery mechanisms include raising reservoir pressure above the minimum miscibility pressure and improving gas conformance to displace incremental oil in a scalable process.
Numerical models were developed and calibrated using historical production data and learnings from the prior EOR pilots. Various injection scenarios were simulated including the use of surfactants and alternative WAG ratios. Studies included evaluation of surfactant mixtures in lab tests determined to be suitable for Bakken reservoir conditions, showing good stability, interfacial tension behavior, and contact angles with improved rock wettability. While surfactants were evaluated via simulations, ultimately the field pilot was simplified to use only produced gas and water with no additives. After completing the injection scheme, a reservoir surveillance program, including continuous monitoring of the HnP well, was implemented to evaluate oil production performance and reservoir response.
The WAG injection scheme was completed with no injectivity issues with approximately 70 million standard cubic feet of produced gas and 23 Mbbls of produced water injected. Production in the offset wells showed no indication of a major gas breakthrough compared to earlier pilots. The use of WAG injection appeared to improve gas conformance and containment, delaying and reducing gas breakthrough. Additionally, no gas or water breakthrough was detected outside the pilot area of the 2560-acre drilling spacing unit. Initial production results show increased oil production in the HnP well with predicted trends in gas and water rates during flowback. Results include analysis and assessment of oil recovery and efficiency compared to simulation and the prior Bakken EOR pilots.
Results of a Project for the Electrification of Well Testing and Production Equipment in the Ecuadorian Amazon
Authors: Clerque B. , Gómez A. , Fernandez L. , Soria J. 
Published: September 2024

Abstract
The article presents the results and lessons learned from a project for the electrification of equipment used for well testing and production in Ecuador. We quantified the reduction of CO2 emissions and noise in upstream operations in some of the most active oil fields in South America, located in one of the most biologically rich places in the world. In Ecuador, jet pumping is used for well testing and to a lesser extent for mature field production. The power equipment for the jet pump includes a 350 hp diesel engine. To improve the energy efficiency of its services, a project was executed to replace these engines with electric motors in 30% of the production units of one of the largest service companies in Ecuador. CO2 emissions were quantified and noise generated by a sample of diesel engines were measured. From this data, the reduction of emissions achieved by this electrification project was estimated. The construction and operation of hydroelectric power plants have facilitated the integration of numerous oil fields in the Ecuadorian Amazon into the National Interconnected System. This has made it possible for operating and service companies to invest in projects to improve the energy efficiency of production processes. In this project, the replacement of diesel engines with electric motors has resulted in the avoidance of 11,200 tons of CO2 emissions since 2017. Costs associated with fuel supply were reduced. The electric equipment was more stable, and non-productive times were minimized. Additionally, noise levels in the external environment of the wells were lowered from 54 dBA to 41 dBA, this holds significant importance in environmentally sensitive regions, such as the Amazon. Among the lessons learned is the need for specialized personnel to operate and maintain electrical equipment. Internal certification processes were implemented for the technicians in charge of these tasks. It is not possible to change 100% of the production units because not all wells have access to electricity generated through renewable means. However, switching to electric motors has proven to be a cost-effective investment to improve the energy efficiency of operations and reduce CO2 emissions. It is known that to achieve climate change mitigation goals by 2050, the oil industry must reduce its emissions by 90%. The present work is an example of how current technologies, that leverage local government investments in renewables, make it possible to achieve substantial reductions in emissions, controlling the environmental impact in one of the most sensitive areas of the planet.
Are There Opportunities for Upstream Sector in Peru? A Comprehensive Study of Peruvian Peak Oil Production with Hubbert Model
Authors: Huerta V. A. , Morán A. , Adriano L. , Quintero E 
Published: September 2024

Abstract
Oil and gas industry in Peru has a long history with more than 100 years oil production with almost all coming from Talara and Marañón Basins. Peruvian oil production has decreased significantly up to 41 MBOPD in the latest 10 years1, with a cumulative oil production exceeding 1.6 and 1.1 billion barrels in Talara and Marañón fields2 respectively. Despite, primary recovery factors represent just 9% and 20% respectively. which may be an indicator of proved hydrocarbon potential that can be recovered with new development strategies and better technology.
This study explores the opportunities to increase the oil supply for the Upstream Sector in Peru by using the Hubbert Model to determine the peak oil and maturity degree of each production region, and for the whole country; a sound estimation of hydrocarbon potential would be crucial to trade off the negative impact in Peru's balance of payments and exchanges due to decreasing oil production and increasing oil imports.
A multicycle Hubbert approach was used to model production history, determine the peak oil and maturity degree, and forecast oil supply for each production region in Peru. Based on analysis of production trends, reserves and contingent resources can be identified in each area, as well as the more suitable technologies and development plans can be proposed.
Typically, primary recovery factors for main fields in Peru are in between 5 to 50% with 14% average. The multicycle Hubbert approach indicates that heavy oil recovery can be increased by at least 20% in Marañón Basin, with new technology (horizontal drilling with autonomous inflow control devices and/or selective completion and/or chemical EOR).
On the other hand, mature Talara fields have shown in recent years low decline rates which also indicates that additional development plans, with more suitable technologies for tight reservoirs, along with new waterflooding or gas flooding projects may also raise recovery factors up to 15%.
Heat Extraction Through an Advanced Closed-Loop Geothermal System
Authors: Liu S. , Taleghani A. Dahi 
Published: September 2024

Abstract
Heat production through conventional closed-loop geothermal systems (CLGSs) is constrained by the limited contact area available for heat exchange between rock formations and the wellbore containing circulating fluid. To address this challenge, an advanced closed-loop geothermal system (ACGS) has been proposed to enhance heat production in this research. The ACGS incorporates a hydraulic fracture, partitioned by a horizontal insulator for vertical zonal isolation of fluid flow in the fracture, into the closed-loop system's fluid circulation. Since working fluid flows through the partitioned fracture, convective heat transfer from rock to fluid in the fracture having a large surface area is introduced to the closed-loop system, which will significantly enhance the temperature of fluid produced from the system. To accurately assess the heat production performance of the ACGS, a comprehensive numerical study is performed. Initially, a three-dimensional hydrothermal model of the ACGS is developed and numerically validated. This numerical model is utilized to simulate heat production through the ACGS incorporating a double-wing fracture for different key parameters, including fracture dimensions and tubing thermal conductivity. Then, heat production performances of two main ACGS configurations respectively incorporating a branched fracture and a multiple-wing fracture are analyzed. Lastly, simulation results of the ACGS under different conditions were compared to determine the design parameters for ACGS yielding the highest heat production performance. Compared with the scenario without a fracture, the near-wellbore temperature of the ACGS has decreased significantly, indicating that the geothermal reservoir is cooled much more efficiently. Due to incorporation of a double-wing fracture, the cumulative extracted heat of a closed-loop system over 20 years is enhanced by up to 162.94%. Increasing the fracture half-length and fracture height can both enhance heat production efficiency of the ACGS considerably. Vacuum-insulated tubing with extremely low thermal conductivity performs better than polymeric insulation tubing in avoiding heat loss through tubing. Compared with a multiple-wing fracture, a branched fracture results in better heat production through the ACGS, with a larger number of fracture branches leading to more efficient heat production. A branched fracture can improve the cumulative extracted heat of a closed-loop system over 20 years by up to 321.77%. Therefore, the proposed ACGS emerges as a promising solution to overcome the limitations faced by closed-loop systems in heat production.
Economic Analysis of Lithium and Salts Recoveries from Bakken Formation
Authors: Jakaria Md , Ling Kegang , Wang Dongmei , Crowell Josh , Zheng Danzhu 
Published: September 2024

Abstract
Oilfield-produced water, a byproduct of extracting petroleum, often contains salts and other significant critical elements like lithium. Utilizing these elements provides a chance to enhance revenue streams in the petroleum industry while also tackling sustainability challenges. This research provides a thorough economic analysis of the extraction of critical elements, specifically lithium, from produced water in the Bakken Formation using the NanoLiSal recovery model. The research aims to evaluate the expenses of project design, anticipate revenue, outline implementation processes, and analyze the environmental impacts. Research utilizes economic analysis strategies to assess the NanoLiSal approach while offering future strategies for applying it. Essential elements comprise financial modeling, investigation of industry trends, and assessments of environmental impact. Economic analysis results provide valuable information on the viability of the recovery process, emphasizing patterns, obstacles, and potential advantages. This article presents a detailed and subtle comprehension of the economic environment, offering direction for future research and real-world implementations. It offers a well-defined project framework that includes the overall expenditure and income generated by the NanoLiSal recovery process. Results emphasize the possibility for the petroleum industry to increase revenue from disposable wastewater while also contributing to sustainability goals. This paper makes a substantial contribution by clarifying economic factors and offering practical insights for individuals and organizations involved in the sector.