bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combining Nanocatalyts with Solvent as a Strategy to Improve Steam-Based Hybrid Technology: Phase Behaviour Modelling and Thermal Simulation Approach
Authors: García-Duarte H. A. , Ruiz-Cañas M. C. , Perez-Romero R. A. 
Published: April 2024

Abstract
As a strategy to optimize the recovery and energy efficiency in cyclic steam stimulation (CSS) processes, the alternative of combining steam - nanosolvents has been under study in Colombian heavy oil reservoirs. The use of oil-based nanocatalysts (nanosolvents) in combination with steam allows extending the effectiveness of the catalyst, transporting it better within the reservoir due to the solubility of naphtha in the crude oil. The interaction phenomena associate with this hybrid technology must be evaluated under a robust phase behavior study which represent oil - solvent interaction analysis and, the effect on the oil density and oil viscosity at different temperatures.
This work shows a methodology to incorporate solvent/oil mixtures phase behavior into the field numerical model. Based on experimental PVT tests (such as compositional analysis and fluids characterization) a fluid model was developed. Using Peng Robinson Modified Equation experimental data were adjusted such as GOR and density. Additionally, the mixture viscosity were fitted with the modified Pedersen equation. Incorporate the effect of nanocatalysts in the numerical modeling required the grouping by pseudo-components of live oil according to the proposed kinetic model, obtaining a good adjustment and a better representation of the live oil. This allowed the inclusion of the component's properties such as asphaltenes and upgrading oil used in the kinetic model of the CSS + solvent enhanced with nanoparticles technology.
The experimental results indicate the high solubility of the solvent in crude oil, due that a linear mixture rules for naphtha - oil was developed. Additionally, a representative fluid model is mandatory to represent aquathermolysis catalytic reaction in the CSS. The modelling results show that the highest incremental recovery of the nanofluid was achieved in early stages of CSS with an increase of 23% concerning the baseline. Likewise, a sensitivity analysis was developed based on a fixed cumulative oil production in the presence of nanofluids, obtaining a 61% reduction in the steam injection rate, indicating that the hybrid technology not only generates positive impacts on recovery but also positively impacts on improving energy efficiency and reducing the carbon footprint.
A novel methodology to represent the fluid interaction in presence of nanocatalysts in the numerical modeling was developed as a strategy to incorporate oil compositional changes in thermal hybrid process.
Enhancing ASP Flood Design: Integrating Pilot Learnings, Lab Re-Optimization and Field Analogues Before Commercial Implementation - A Case Study of India
Authors: Hanotia A. , Biswas M. , Rana V. , Pandey V. , Mavoori R. , Rathi K. , Mitra S. 
Published: April 2024

Abstract
The ASP flooding is a complex technology as experienced from latest field implementations at western onshore basin in ONGC. Although, ASP pilot has been successfully executed in concerned reservoir, few challenges are still present. The present paper proposes to address these challenges before moving for the commercialization.
Encouraging laboratory and simulation results lead to ASP pilot with inverted five spot pattern. The pilot shows directional heterogeneity leading to early breakthrough which necessitated Profile Modification and Water Shut off jobs. Active aquifer and low polymer buffer viscosity lead to increase in water cut. Besides, the chemical quality monitoring, supply chain management were the challenges to be addressed before full field expansion. The re-optimization of chemical formulation is also performed in lab to mitigate the detrimental effect of alkali induced scaling and to reutilize the effluent water. Simulation was also revisited with envisaged incremental oil of 6.6% in thirteen years.
Lessons learnt during pilot implementation and the experience of a commercial ASP project in an analogous field helped in better formulating development strategy for the present project.
To prevent the ground water exploitation and better management of effluent water, the ASP formulation was modified without compromising its performance. The scaling problem as was encountered at surface and subsurface in analogous field lead to reduction in alkali concentration and incorporation of scale inhibitor. For better control of chemical supply chain and quality monitoring, the responsibility matrix was revisited. ASP expansion has been considered in the structurally top part where sand is well developed and well productivity is higher with reduced well spacing. Sensitivity runs showed that incremental oil recovery increases with higher slug size and higher polymer buffer concentration. The ASP injection comprises of 14 inverted 5 spot patterns. The surfactant induced tough emulsion formation is also proactively addressed in the upcoming ASP project.
Although ASP process is a complex technology but it has the potential to significantly enhance the field recovery. The technical and managerial challenges faced in pilot and in the running of commercial project helps to take necessary action beforehand. No matter how well prepared a plan may be it is inevitable that it will face challenges and obstacles along the way. However, being agile and timely midcourse correction is the key for success.
Co-Injection of Surfactant and Gas in Unconventional Reservoirs
Authors: Schechter D. S. , Moore B. , Sarmah A. 
Published: April 2024

Abstract
Enhanced oil recovery in unconventional reservoirs has established a track record in the past few years. It is an important technology to investigate and implement to pursue longevity in the thousands of horizontal laterals that are reaching their terminal decline towards abandonment. EOR techniques have been proven to be technically feasible and to a certain degree, economically attractive. The techniques described in this paper are 1) gas injection in the huff n' puff mode 2) surfactant injection in the huff n' puff mode and 3) co- injection of both miscible gas and surfactant. The objectives of this paper are to present laboratory evidence and field resu lts for the three techniques described.
This paper will present laboratory justification behind each of the three methods. Results from core data are presented for each of the three methods that include gas penetration, imbibition, and the use of both mechanisms for co-injection of gas and surfactant. Experiments using time-lapse CT scanning demonstrate the saturation changes as oil is displaced when core samples are exposed to gas, surfactant, or a combination of both.
Miscible gas experiments conducted using time-lapse CT scanning indicate gas penetration induces saturation changes on reasonable time scales. Wettability alteration by surfactants as determined by contact angle measurements will be presented. Ample contact angle and imbibition data demonstrate that wettability alteration is the key to application of surfactants in unconventional reservoirs. Both techniques have been applied in successful field projects.
A novel co-injection method with both miscible gas and surfactant is described. Application of co-injection using both gas and surfactant capitalizing on the synergy between the mechanisms is especially intriguing, both from a laboratory and field perspective. The technique utilizes both the diffusion/swelling mechanism of miscible gas along with the ability of surfactant to alter wettability resulting in gas sweeping the larger pore spaces and aqueous phase surfactants to displace oil in smaller pores via capillary pressure. Experiments are presented that show miscible gas displaces oil from larger pores and surfactant imbibition displaces oil from smaller pores during co- injection. Review of a co-injection project demonstrates key advantages over gas injection alone such as 1) prevention of rapid gas migration via fractures away from injection well 2) reduction of the necessity for high pressure compression to attain the Minimum Miscibility Pressure (MMP) by utilizing co-injection of surfactant and gas and 3) a superior gas utilization factor (GUF) as compared to gas-only projects showing the importance of surfactant during co-injection.
Numerical Studies of Unstable Fingering Flow in a Water-Oil System
Authors: Jia Cunqi , Hu Jinchuan , Sepehrnoori Kamy 
Published: April 2024

Summary
Fingering behavior is a crucial phenomenon in the improved oil recovery process and significantly influences oil recovery, including heterogeneity channeling and viscous fingering. This study modeled the fingering behavior during the water flooding process and enhanced the simulation method to represent these two phenomena simultaneously. In this study, we employ the Corey correlations to preserve laboratory-measured data on the relative permeability and incorporate the impact of capillary pressure. The Leverett J-function is additionally used to integrate formation heterogeneity and saturation influence on capillary pressure. The method is validated through a comparison with lab-based flat-plate displacement experiments, with authentic measured relative permeability data. our improved model can accurately capture the results of the fingering phenomenon, obtaining similar fingering patterns and quantitatively matching the BHP, water cut, and oil recovery factor. Based on it, we explored the influence of injection rate, water and oil viscosities, and viscosity ratio. The results indicate that increasing the injected water viscosity delays the breakthrough, thus improving the oil recovery. It is worth noting that the same value of viscosity ratio does not obtain the same results. For instance, when the water and oil viscosities are 100m and 1000 mPa·s, 1PV water injection results in a final recovery factor of 54.79%, while 38.02% with viscosities of 1mPa·s and 10 mPa·s respectively. Water injection rates also affect the final oil recovery. These two typical findings cannot be captured in most of previous simulations. By considering the impact of capillary pressure heterogeneity, such physical phenomena are well reproduced in this work. Compared to visualization experiments and micro-scale direct simulation, macro-scale fingering simulation has always been challenging. While some studies can obtain fingering images similar to those observed in laboratory experiments, the relative permeability used deviates significantly from actual conventional laboratory measurements. However, our improved model can simultaneously reproduce both heterogeneity channeling and viscous fingering phenomena with authentic laboratory-measured data.
Hot Oil Now a Successful Optimization Acceleration Project, Safer, Faster and Hotter: A Case Study of Optimization Challenges in a Thermal Steam Flood Field, South of Sultanate of Oman
Authors: AL-Shuaibi Hasna A. , AL-Shaqsi Khadija. A. , Al-Mawali Shaikha. N. , AL-Sheibani Hamdan. S. , Bhavsra Chetan. D. , Maabady Islam. A. 
Published: April 2024

Abstract
This paper covers the optimization challenges in a thermal Steam Flood field located south of Oman. Focusing on the A Field, which is a deep reservoir characterized by high-temperature and high-pressure conditions, making it one of the most challenging fields in Oman. The research methodology encompasses a comprehensive analysis of optimization challenges in A Field, classifying them into three primary categories: subsurface challenges, surface challenges, and process challenges. This classification sets the stage for a detailed examination of mitigation plans and strategies tailored to each challenge. To maximizing oil recovery, ensuring reservoir balance, preventing loss of containment, and ensuring Health, Safety, and Environment (HSE) practices. Implementation of Practical Problem-Solving sessions (PPS) and Continuous Improvement (CI) initiatives, specifically tailored to improve process challenges, has resulted in significant improvements. This includes a notable 70% reduction in the total surface optimization cycle time, liberating resources for approximately 51 days to address other workovers and enhance resource deployment efficiency. Furthermore, the paper showcases substantial cost savings equivalent to a full-time Petroleum Engineer position, coupled with an accelerated enhanced oil recovery in 2023 of around 35 % net oil gain of the average field production compared to 4 % net oil production gain of the average field production in 2021. The establishment of a standardized process flow as a Standard Operating Procedure (SOP) and the creation of a visual management system, coupled with tracked Key Performance Indicators (KPIs), ensure the sustainability of these improvements. This paper presents novel insights into the optimization challenges faced in a thermal steam flood field and provides a case paper of the A Field in Oman. The research emphasizes the significance of aligning optimization criteria, introducing visual tracking tools, and following agreed-upon surface and subsurface optimization processes. The paper also highlights the potential benefits of automation, standardization, and visualization in planning and executing optimization activities. By leveraging automation and lean methodologies, the field can overcome challenges more efficiently, leading to increased operational efficiency and higher oil recovery rates. The findings contribute to the understanding of optimizing thermal fields and offer valuable lessons for similar projects worldwide.
Self-Granulated Thermoplastic Elastic Particles for Fracture Conformance Control of Harsh Reservoirs
Authors: Xue Yan , Yin Qiulu , Zhang Chunquan , Wei Bing , Lu Jun , Wang Yiwen 
Published: April 2024

Summary
To address the challenges associated with the complex preparation process of polymer particles for conformance control and the difficulties in combining injection and conformance control performance, a study was conducted on a thermoplastic elastic particle conformance control agent using polyvinyl alcohol (PVA) as the particle skeleton. The millimeter-scale elastic particles can be prepared in-situ by incorporating a hydrophobic modifier (HM) and a cross-linking agent glutaraldehyde into the aqueous phase. By adjusting the content of HM and stirring speed, the particle size can be regulated. The texture profile analysis indicated that the self-granulated thermoplastic elastic particles exhibit excellent elasticity and high resilience. Furthermore, they can undergo thermoplasticization in highly mineralized water (21×104 mg/L, Ca2+ + Mg2+ = 1.2×104 mg/L) and crude oil at 130 °C, while maintaining exceptional mechanical properties. Physical model experiments demonstrated that the particle system exhibits good migration ability and plugging performance. The particles’ breakthrough pressure significantly increased after high-temperature treatment, reaching 1860 kPa, highlighting the practical potential of these particles for oil reservoir applications. With a simple dropwise stirring "one-pot" synthesis method, the thermoplastic elastic particles offer advantages including straightforward synthesis, environmental friendliness, excellent mechanical performance, thermal stability and salt resistance. These thermoplastic elastic particles show great potential for future industrial production and have promising prospects as a fracture conformance control agent.
The Effect of Small Molecule Gas-Soluble Polymers on Minimum Miscibility Pressure During CO2 Injection
Authors: Torabi Farshid , Gandomkar Asghar 
Published: April 2024

Abstract
The minimum miscibility pressure is the main technical challenges during CO2 flooding. Therefore, the purpose of this work is to explore the effect of small molecule CO2-soluble polymers including PDMS, PFA, P-1-D, and PVEE on minimum miscibility pressure during gas flooding. The dilute concentrations of polymers (1000 to 50000 ppm) were considered to dissolve in CO2 at 60 and 80 °C. According to the cloud point pressure results, the small molecule CO2-soluble polymers dissolved in carbon dioxide at pressures consistent with gas-based EOR methods (less than 2500 psi) at both 60 and 80 °C. Also, (CO2/polymers)-oil interfacial tensions were decreased extremely via the dissolution of dilute concentrations of polymers in CO2. Moreover, the small molecule CO2-soluble polymers decreased significantly the MMPs by 19.4% for CO2/PFA, 17% for CO2/PDMs, 13.6% for CO2/PVEE, and 10% for CO2/P-1-D scenarios in comparison with pure carbon dioxide injection. Moreover, the 26.5% additional oil was recovered during miscible CO2/PDMS injection in comparison with miscible pure CO2 scenario. Therefore, the small molecule CO2-soluble polymers containing functional groups with oxygen can be one of the best candidates for miscible CO2 displacement in the field-scale.
Enhancing Condensate Production by 29%, Through Thermal Gas Injection from a Retrograde Gas Condensate Reservoir - With an Operational Case Study in the Western Desert of Egypt
Authors: Taha Maged Alaa , Shokier Eissa , Attia Attia , Yahia Aamer , Mansour Khaled , Abdelkhalek Dina Medhat 
Published: April 2024

AbstractIn retrograde gas condensate reservoirs, the accumulation of liquid from natural gas below the dew-point pressure leads to condensate blockage, a significant issue in reservoir damage. Although most of this liquid doesn't reach the level required for production, it hinders the flow of natural gas, affecting its production.This study focuses on the impact of gas injection methods (like methane, carbon dioxide, and nitrogen) and high-temperature steam on an Egyptian retrograde gas condensate reservoir. Various scenarios were tested, involving different temperatures, enthalpy levels, types of injection gases (CO2, N2, CH4), and injection rates.The findings revealed that neither conventional nor thermal gas injection methods significantly increased cumulative gas production compared to simply depleting the reservoir. However, non-thermal gas injection methods boosted cumulative condensate production by 8.6%. Notably, thermal CO2 injection showed a substantial increase, enhancing condensate production by 28.9%. The study found that thermal gas injection does not vaporize condensate more effectively than conventional injection methods under similar reservoir pressure trends. Instead, the primary benefit of thermal injection is in enhancing condensate mobility. Therefore, thermal injection is most suitable for depleted retrograde reservoirs, where a significant amount of non-producible liquid has already accumulated. The research also explored the operational aspects of implementing thermal gas injection in retrograde gas condensate reservoirs. This includes considerations for carbon dioxide recovery units, compressors, storage tanks, corrosion-resistant pipelines and tubing strings, as well as corrosion inhibitors and downhole gas heaters.
Synergistic Effects Between Supercritical CO2 and Diluted Microemulsion on Enhanced Oil Recovery in Shale Oil Reservoirs
Authors: Yuan Shuai , Wang Bin , Yang Maoqin , Zheng Leyi , Liu Hao , Li Yuan , Zhou Fujian , Liang Tianbo 
Published: April 2024

Summary
The development of unconventional liquid-rich reservoirs, supercritical carbon dioxide (scCO2) considers a promising fluid to further improve oil recovery of shale oil reservoirs in and after hydraulic fracturing. However, the scCO2 has some disadvantages to limit its application in hydraulic fracturing, such as ultra-low viscosity, asphaltene deposition and high miscible pressure. Diluted microemulsion (DME) shows great potential as the additive of fracturing fluid to improve the well productivity through strengthening the spontaneous imbibition during the shut-in period after hydraulic fracturing. Therefore, it is essential to further understand the synergic effects between scCO2 and DME at the pore scale. In this study, three soaking sequences are designed and compared, which include only scCO2 soaking, water-scCO2-DME soaking sequence, and DME-scCO2-DME soaking sequence using shale cores from the Lucaogou Formation. Low-field nuclear-magnetic-resonance (NMR) technique are utilized to quantify the oil distribution among different pores in each soaking stage. Furthermore, component change of the produced oil is characterized by the gas chromatography (GC). Notably, T1-T2 spectra are introduced to verify the results of T2 spectra and GC. Results show that DME can replace the oil from small pores into large pores and thus improve the extraction effects of scCO2. The solid-liquid and oil-water/scCO2 interactions determine the adhesion work of heavy components. DME can enhance the heavy component (C17+) mobilization through interfacial tension (IFT) reduction and wettability alteration. Combing scCO2 and DME can effectively improve the mobilization of both light and heavy components of crude oil, and thus achieve a better ultimate oil recovery rate.
Chemical Enhanced Oil Recovery Experiences in Colombia: Field Pilots Review
Authors: Gutierrez M. , Castro R. H. , Corredor L. M. , Fernández F. R. , Zapata J. , Jimenez J. A. , Reyes J. D. , Rojas D. M. , Jimenez R , Acosta T. , Dueñas D. E. , Solorzano P. L. , Mayorga H. , Llanos S. , Quintero H. I. , Garcia H. A. 
Published: April 2024

AbstractPolymer injection is a technique that has been applied worldwide to improve oil reservoir volumetric sweep efficiency and increase the recovery factor. Different applications using partially hydrolyzed polyacrylamide (HPAM) polymers have been carried out in some Colombian fields since 2011. Several pilots have been implemented to test both technical and economic feasibility. This article summarizes the pilot's results and the lessons learned. The different polymer technologies evaluated for chemical Enhanced Oil Recovery (CEOR) are i) Colloidal dispersion gels (CDG) for mobility control and deep divergence executed in Dina Cretáceo and Tello fields, ii) Polymer flooding for mobility control executed in Yariguí- Cantagallo, Casabe, Palogrande-Cebu, Chichimene, and La Cira- Infantas, iii) Alkaline-Surfactant Polymer (ASP) flooding to increase recovery executed in San Francisco, and Caracara Sur fields.The results of pilots have caused a positive impact, such as an increase in oil production and a decrease in water production, improving the recovery factor in the influenced reservoir volume. The advances in the last decade have increased the interest in applying polymer injection technologies in different Colombian fields. This article reviews Colombian references and our experience in the first designs and polymer applications in the field. From their view, a short state-of-the-art description of the characteristics of each polymer technology was structured, as well as the objectives and results of each pilot implemented factors such as design, operating conditions during its execution, and process efficiency.