bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Polymer Flooding to Enhance Oil Recovery from the Largest Oil-Bearing Clastic Reservoir in the South of the Sultanate of Oman
Authors: Al Nabhani H. , Al Riyami O. , Al Sulaimani H. , Karpan V. , Bellmann L. 
Published: April 2024

Abstract
For more than 85 years, Petroleum Development Oman (PDO) has gained significant experience in oil production from different types of reservoirs, of which Gharif is the largest clastic formation in terms of oil reserves. The formation bears mainly medium to heavy oil, making primary and secondary (waterflooding) oil recovery less efficient due to the unfavorable oil-water mobility ratio. This paper demonstrates that polymer flooding is the best technology to improve sweep efficiency and achieve higher oil recovery at acceptable costs and risks. The technology is not new to PDO and has been implemented in the Al-Khlata formation in the Marmul oil field since 2010 (Svec et al., 2021). Gharif reservoir properties are more complex than those of Al-Khlata; therefore, additional laboratory studies were performed. The paper aims to present the results of such studies complemented by the production forecast results obtained from fit-for-purpose modeling approach. The approach was then used to accelerate phased project development in the Rahab field with multiple Gharif reservoirs, each characterized by a different oil viscosity.
The Rahab polymer project aims to develop heavy oil in the Gharif formation through vertical polymer injection patterns. The success of this project will pave the way for future developments in the fields with similar reservoir (Gharif) characteristics.
In order to reduce technical risks for Rahab polymer flooding, the project development was phased with Phase 1 as a trial and Phase 2 as a commercial-scale project. This paper is focused on the technical work done to design a polymer injection project for Phase 1. The objectives of Phasel are to: Expedite polymer injection in this field to monetize the opportunity while collecting more data and building a more robust understanding of Gharif polymer performance.Evaluate the surface facility modular approach against the standalone facility per single field (standard PDO approach). This could minimize the surface facility Capex and provide more operational flexibility.
Multi-Scale Optimization of Three-Million-Ton-Class CCUS Project in the Largest Oilfield in China: Zone Control Technology of Large PV CO2 Flooding
Authors: Wen Xin , Zhao Yang , Zhang Zheng , Peng Zesen , Liu Yueliang , Hu Ting , Rui Zhenhua 
Published: April 2024

Abstract
Large-PV (&gt;1 PV) CO2 flooding is a technology that significantly improves oil recovery for ultra-low-permeability reservoirs. However, connected water-flooded channels formed by high-pressure water injection can lead to serious gas channeling, reducing the performance of large-PV CO2 injection. This article innovatively proposes a zoning control technology based on engineering geological characteristics of implementing million-ton CCUS in Changqing (China's largest oilfield). Multi-scale optimization is performed to achieve efficient and safe storage while maximizing oil recovery.
Taking HX block of Changqing Oilfield as an example, through production performance analysis, the entire area is divided into different levels based on the lifecycle of the well network. Conduct sensitivity analysis and ranking of oil recovery and storage efficiency. Parameter optimization of typical well patterns through CMOST-AI. Based on the comprehensive economic indicators, the collaborative optimization of oil recovery and CO2 storage efficiency is completed, and the channeling control method is further explored through gel plugging and shut-in timing simulation.
According to statistics, over 60% of the well patterns have entered the medium to high water cut. Through multi-scale classification and control, both types of well patterns CO2 flooding increased oil recovery by over 25%, and the ultimate CO2 storage capacity could reach over 3 million tons. The low water cut model was more effective in storing CO2 under the same injection conditions. Through sensitivity analysis, we found that the impact of injection-production parameters on recovery and storage efficiency varied. Gas injection pressure had the greatest impact on recovery and storage efficiency in the medium- to high-water-cut well patterns. While in the low-water-cut well pattern, it was the water slug volume. In addition, the water-to-gas ratio was the main influencing factor. Therefore, precise and case-specific optimization of injection parameters was necessary. In the later stage of the low-water-cut well pattern, gas channeling was severe, and the gradual alternation of water-gas-ratio can suppress this phenomenon. Consequently, appreciable oil recovery can be maintained in the later stages of development to ensure economic benefits.
This article proposes for the first time a multi-scale collaborative, hierarchical classification-controlled large-PV CO2 injection technology that can simultaneously consider recovery efficiency and achieve CO2 million-ton level storage. In short, it is simple and fast to predict the development and storage effects of CO2 flooding in the entire region and provide guidance for the development of ultra-low permeability reservoirs and CCUS engineering.
A Novel On-Chip Oil Swelling Measurement Platform for Gas Injection EOR Processes
Authors: Barikbin Z. , Ahitan S. , Genereux J. , Abedini A. , Ungar F. , Yang T. , Wanat E. , Li Z. , Alboudwarej H. , Burger J. 
Published: April 2024

Abstract
Oil swelling test data is essential to tune the EOS models to simulate gas injection EOR processes and evaluate the reservoir-scale recovery performances. PVT cells are typically used to measure this property; however, it may involve some challenges with runtime, fluid handling, and test operations. Here, a high-pressure high-temperature microfluidic approach is developed to measure the oil swelling in response to gas exposure under step-wise increasing pressure with different injection gas mole fractions. The microfluidic chip consists of a high-throughput gas-in-oil slug generator that produces multiple isolated gas-in-oil compound slugs with known initial volumes of gas and oil phases, each representing a single mixing condition that can be tested for oil swelling measurements. These isolated gas-in-oil compound slugs are generated at a pressure slightly higher than the oil bubble point pressure to ensure that oil remains in single-phase. A high-resolution microscopic camera is utilized to record time-lapse images of the volume at elevated pressures and the swelling factor is measured at the corresponding saturation pressure. Additionally, liquid volume fraction and relative volume are measured at each pressure step. The range of the data can be broadened so that the saturation pressure curve covers both bubble and dew points, representing both oil and retrograde gas condensate phase behaviors of single-phase fluid once reservoir oil and injection gas are fully mixed. The microfluidic swelling test results are also compared with those obtained with the conventional PVT cell, exhibiting a promising agreement between the measured data (i.e., average of ~5% deviation). While the PVT cell method may require several weeks to provide a full oil swelling dataset, the microfluidic approach developed here is notably faster and easier to operate for different types of reservoir oils and injection gases, stemming from small volume of fluid samples required for the testing procedure. The novel microfluidic platform developed here provides a unique opportunity to rapidly measure the large-scale oil swelling data, which has not been historically obtainable using conventional PVT cell. It can also facilitate tailoring and optimizing the injection gas through fast and accurate access to the relevant swelling data, informing the operators to better design gas injection projects. This can make gas injection PVT data accessible by an order of magnitude reduction in time, cost, and sample size requirements - in stark comparison with conventional methods.
A 2D Visualization Study of Polymer-Alternating-Gas Flood for Heterogeneous Reservoirs
Authors: Pang J. , Mohanty K. 
Published: April 2024

Abstract
Miscible gas flooding is an effective enhanced oil recovery method, but its sweep efficiency is low due to gravity segregation and viscous fingering. This issue is worse in reservoirs with a high-level heterogeneity. Water-alternating-gas (WAG) injection is often applied to improve sweep efficiency, but with limited success. Polymer flooding is a proven approach to improve sweep efficiency. This study aims to evaluate the performance of CO2 Polymer-Altering-Gas (CO2-PAG) floods through a series of visualized experiments conducted at the lab scale. Simulations were employed to optimize the injection schedule of CO2-PAG. The experiments included continuous gas (CG), WAG, and PAG injection in 2D heterogeneous sand-packs. To visualize and understand the performance of CO2-PAG, a 2D view cell was used, and a layered heterogeneous sand-pack was constructed. During water flooding, the layer with higher permeability was highly swept and the layer with lower permeability was minimally swept. In PAG flooding, the polymer solution selectively swept the lower portion of the higher permeability layer, while the solvent predominantly swept the upper portion of the higher permeability layer. A small portion of the solvent also entered the upper part of the low permeability region. PAG flooding exhibited a higher swept area (than CG and WAG), leading to increased incremental oil recovery. However, gravity segregation remained a challenge, leaving a significant portion of the lower permeability layer upswept. The simulation results show that the injection schedule with more 5 PAG cycles had the highest incremental oil recovery. The introduction of tapering slug sizes did not significantly impact the performance of PAG. These findings provide valuable insights into optimizing the PAG process for enhanced oil recovery.
Chemical Osmosis-Driven Thermodynamically Coupled Processes: Mechanistic Insights into Oil Recovery from Core-Scale Experiments
Authors: Takeda M. , Manaka M. , Goto A. 
Published: April 2024

Abstract
Chemical osmosis-driven oil migration is a viable mechanism for improved oil recovery (IOR) obtained by low-salinity water flooding (LSFW) in various reservoirs, including shale, sandstone, and carbonate rocks. Chemical osmosis generates a driving force on crude oil trapped alongside connate high-salinity water (HSW) in hydraulically stagnant zones that are not directly accessible by injected low-salinity water (LSW). However, the extent to which chemical osmosis contributes to oil recovery remains unclear. This uncertainty arises partly due to the limited experimental evidence directly demonstrating chemical osmosis-driven oil migration in actual rocks and mainly because the underlying processes have not been comprehensively clarified. This study re-examines the thermodynamically coupled processes involved in chemical osmosis-driven oil migration at the pore scale. Building on the underlying mechanisms, previous studies indicating osmotic effects were reviewed to gain mechanistic insights. These studies specify the necessary factors enabling chemical osmosis-driven oil recovery in LSWF: leaky semipermeability, permeability gap, and hydraulic dead-end boundary. With these factors, chemical osmosis via pores with membrane effects generates effective osmotic pressure and volumetric increase in HSW, driving oil migration through pores with less or no membrane effects from hydraulically stagnant to conductive zones. These thermodynamically coupled processes continue in a dynamic equilibrium state until the salinity difference eventually vanishes between the hydraulically stagnant and conductive zones. Therefore, chemical osmosis-driven oil recovery lasts long and progresses into a hydraulically stagnant zone at the scales of pores, pore networks, and rocks. "Effective" osmotic pressure acts on HSW as a driving force and breakthrough pressure to counteract the viscous and capillary forces working on the oil to migrate. However, the magnitude of the effective osmotic pressure is subtle or non-detectable in rocks with large pores, causing chemical osmosis-driven oil migration to resemble static oil displacement, seemingly caused by the volume increase of the HSW and/or oil phase, as observed in microfluidic pore models.
Novel Thermal Stimuli-Responsive Surfactants to Reduce Operation Costs for Chemical Flooding
Authors: Xu L. M. , Huang T. P. , Alotaibi M. , Boqmi A. 
Published: April 2024

Abstract
Demulsification of produced fluids in chemical flooding is a costive treatment due to the stable emulsion in the presence of injected surfactants. The objective of this study is to develop unique thermal stimuli-responsive surfactant, which reduces interfacial tension (IFT) at high temperature in reservoir for improving oil production and loses effectiveness when temperature decreases to easily break the produced emulsion at low temperature in surface to reduce operation costs. The surfactant formulation was developed by mixing two different surfactants and one has thermal stimuli-responsive group. Compatibility, IFT and particle size measurements were conducted at different temperatures from 90°C to 25°C representing the temperatures from reservoir to surface. Compatibility was performed using Stability Analyzer by recording transmission light intensity. IFT was tested by spinning drop tensiometer. The measurement kept going until the equilibrium IFT was reached. Particle size was obtained using dynamic light scattering instrument. Emulsion was prepared by homogenizer and evaluated by Stability Analyzer. The developed surfactant formulation present unique interfacial properties: high oil/water IFT at low temperature in surface while ultra-low oil/water IFT at high temperature in reservoir. IFT was 10−1mN/m at 25°C and 40°C. The value decreased to 10−3 mN/m when temperature increased to 80°C and 90°C which indicated the synergistic effect between the mixing surfactants at high temperature. This suggests that the formulation has thermal stimuli-responsiveness, which is due to the molecular structure change with the temperature. Other surfactants with similar structures can also be used to develop thermal stimuli-responsive surfactants (TRS). Emulsions using TRS and another surfactant formulation which has low IFT at 25°C were prepared. Results show that the emulsions with TSR separated much faster. These results demonstrate that TRS has good potential for improving oil production in high temperature reservoir due to ultra-low IFT, and the high IFT value at low temperature is beneficial for produced fluids treatment. This work developed thermal stimuli-responsive surfactants by mixing two different surfactants to enhance oil production and to reduce cost for demulsifying produced fluids at surface in chemical flooding operation.
Subsurface Waterflood Management Improvement: The Art of Reservoir Connectivity Characterization
Authors: Setiyawan Hanif , Evelyn Katerina , Hisan Rizaq Faidul , Fardiansyah Iqbal 
Published: April 2024

Abstract
Developing subsurface waterflood management strategy at mature field and complex stratigraphic trough advance and integrated analysis of various subsurface discipline is very critical to characterize reservoir connectivity to improved oil recovery. This paper focus on technical analysis of defining the vertical and lateral connectivity practically applied for injector-producer well alignment. Detailed study has been done as efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir.
Advance and integration of analysis of all subsurface discipline aspect as a foundation of static and dynamic studies trough stratigraphy interpretation, seismic wave propagation, log shape clustering analysis, pair analysis of linked injector-producer, spinner surveillance analysis, and CRM (capacitance resistance modelling). Combine all those analyses to fill the gap of each method and validate with pressure analysis and production data is key to reduce uncertainty. Integration of these analysis provides better understanding of injection–production relationship, water cycling well, water breakthrough impacts and unoptimized production reservoir. The recommendation was used to lead further injection–production alignment strategy.
Waterflood management has successfully implemented and is able to put more injections at the right place, right amount and right time. Workovers and well intervention program are executed as plan in both injector and producer wells and successfully delivered additional oil gain impact to 50% of total production. A significant additional reserve has been achieved through this new workflow implementation. The other benefit from this effort was creating additional fluid space at the current constrained surface facility that allow to execute delayed workovers. A better understanding reservoir connectivity has improved workover success rate from 67% to 95%. In overall, this initiative has successfully managed Alpha field annualized decline from 41% to 28%.
This methodology and workflow can be applied to other waterflood fields that have similar conditions. Integrating subsurface assessment, surveillance, and engineering data has proven to improve the performance and recovery of the Alpha field. The extensive application of reservoir connectivity appears to be an important tool to economically extend the life of this mature field, achieve high recovery, and maintain production decline. Diligent and creative integrated subsurface and engineering analysis can provide an excellent optimization strategy for mature waterflood fields. The project team was able to exploit the upside potential to increase the oil field performance through the implementation of this integrated methodology.
First Nanoparticle-Based EOR Project in Japan : Field Pilot Test
Authors: Kumasaka J. , Kaito Y. , Goto A. , Ito D. , Kitagawa H. , Nogami T. , Murakami S. 
Published: April 2024

Abstract
Nanoparticle-based enhanced oil recovery (Nano-EOR) is an improved waterflooding assisted by nanoparticles dispersed in injection water (nanofluid). Although Nano-EOR has been revealed to become a promising technique from many laboratory experiments, field applications are still limited. This paper discusses the first Nano-EOR field pilot tests for the Sarukawa oil field in Japan. The field pilot tests were divided into two stages: short-term injection test and long-term inter-well test. The short-term injection test was performed mainly to investigate the effects of nanofluid on the well injectivity. Nanofluid was injected into an existing water injection line by an air-driven liquid pump at a concentration of 0.5 wt. % which was optimized in the series of our study. The result of the short-term injection test showed that the nanoparticles used in this study can be injected into the target formation without any damage when the concentration is properly controlled. For the long-term inter-well test, 0.5 wt. % nanofluid was injected into the injection well for two months to validate the increase in oil production. The production behavior was monitored frequently and compared to the reference decline curve. Inductively coupled plasma optical emission spectroscopy (ICP-OES) analysis of the production fluid was also performed to detect the breakthrough of the injected nanoparticles. Although nanoparticles were not detected in the producer well, the oil production rate showed a positive deviation from the estimated baseline decline curve, suggesting an increase in oil production due to the nanoparticles injected from the injector. This paper has made a comprehensive discussion and summary of the challenges based on the current status of the long-term inter-well test. This study established a simple pilot scheme for Nano-EOR and this will contribute to the upcoming Nano-EOR projects.
Lesson Learned from Multiple Field Implementations of Foam EOR Technology in Conventional and Unconventional Reservoirs
Authors: Singh Robin , Katiyar Amit , Hassanzadeh Armin , Akhade Pramod , Crosley Matt , Groothuis Erik , Rozowski Pete , Nguyen Quoc 
Published: April 2024

Abstract
The goal of this paper is to share valuable insights gained from five field implementations of foam as gas-conformance and/or gas-containment solution. These trials encompass both CO2-foam and hydrocarbon-foam in various reservoir types, including conventional carbonate, conventional sandstone, and fractured-propped tight sandstone reservoirs with varying reservoir characteristics. A systematic EOR pilot design workflow is proposed to drive the foam technology from the conceptual stage to full-field commercial implementation. Critical aspects such as reservoir and well selection, surfactant chemistry selection, reservoir data analysis, and the experimental and modeling workflow for the optimal injection strategy, along with effective management of pilot operations, are discussed. A workflow for screening optimal surfactant formulation tailored specifically for the target field that meets the technical KPIs is shared. The key nuances of selecting water-soluble vs gas-soluble surfactant chemistries for in-situ foaming is discussed. Specific examples of operational challenges encountered during implementation of these projects are also discussed. Additionally, we shared best practices for foam field implementation to increase the likelihood of successful foam pilot trials. Foam as a gas mobility control solution has been tested theoretically, experimentally and in the field for over three decades. This paper distills the technical advancements and deployment strategies needed for commercial adoption of this solution. Such advancements would be critical for the oil and gas industry's energy transition journey by enabling efficient greenhouse gas injection projects.