bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Systematic Experimental Study of Low Salinity, Carbonated Water and Low Salinity Carbonated Water EOR Injection Schemes in Carbonate Reservoir Conditions
Authors: Alhashboul A. A. , Farzaneh A. S. , Sohrabi M. S. 
Published: April 2024

Abstract
Smart Water (SW) can be defined as brine that has been chemically adjusted/optimized in terms of salinity and ionic composition or carbonation (CO2 enrichment). The aim is to create a brine with an optimum chemical & ionic composition such that it changes the equilibrium of the oil crude/brine/rock interaction (CBR). Recently, combining more than one EOR method in hybrid mode has gained attention; several SW hybrid modes have been investigated with positive results. The most promising hybrid mode is combining low salinity injection (LSI) with Carbonated Water Injection (CWI). A carbonated Low Salinity Carbonated Water Injection (LSCSWI) study was carried out to both study the effectiveness and explore the prospects of combining carbonated water (phase behaviour), with low salinity (wettability alteration) mechanisms. A series of high-pressure/temperature carbonate reservoir core flood experiments were performed at reservoir conditions (100ºC - 3100 psig), so the incremental oil recovery factor and differential pressure behaviour of Low Salinity (LS), Carbonated Water (CW). LSCW and CO2 EOR injection schemes could be compared.
A near perfect oil recovery often associated with miscible CO2 core flooding experiments was achieved. However, field implementations where gravity override challenges of CO2 injection are faced, do not produce oil recovery %'s near the recovery factors that are achieved in miscible CO2 core flooding experiments. The highest incremental oil recovery % IOIP of the waterflooding based injection modes was achieved by tertiary LSCSW, with a value of 28.49%, followed by CSWI at 23.18%, and finally LSSWI at 5.5%. The magnitude effect of the Dp drop caused by the carbonated water's new gas phase that was produced with the effluent was higher than the wettability alteration increases of Dp that was caused by reducing the salinity of the injected brine. Several observations supported the claim that mechanisms of wettability alteration, associated with LSI and phase behavior change associated with CWI, work simultaneously. The wettability alteration mechanism that was triggered by reducing the salinity of injected brine is much more dependent on the remaining oil saturation, in order for it to have a significant positive influence on oil recovery.
To the author's best knowledge, there has not been a systematic experimental investigation that compared these four EOR recovery methods, by using the same carbonate reservoir core sample, live crude oil sample and injected brines, at the same reservoir conditions.
Core-To-Field Scale Simulations of Low Salinity Polymer (LSP) Flooding in Carbonate Reservoirs Under Harsh Conditions
Authors: Hassan Anas M. , Zeynalli Mursal , Adila Ahmed S. , Al-Shalabi Emad W. , Kamal Muhammad S. , Patil Shirish 
Published: April 2024

Abstract
Low Salinity Polymer (LSP) injection is a promising hybrid enhanced oil recovery (EOR) technique with immense synergistic advantages in improving injectivity, displacement efficiency, sweep efficiency, polymer rheology, and polymer viscoelasticity. To model the LSP injection, the Polymer-Brine-Rock (PBR) interactions must be precisely captured at core-scale and further upscaled to field-scale predictive model. Also, although the literature has many experimental and theoretical studies on LSP floods, few of these works address the industry's experience with LSP-based EOR at field-scale applications. Therefore, moving from experimental laboratory study to field-scale predictive modeling is an enormous challenge. This contribution describes a pertinent reservoir simulation analysis of an LSP-based EOR method from core-to-field scale. This work employs a proposed MATLAB-Reservoir-Simulation Toolbox (MRST) flow model to gain an in-depth understanding of LSP techniques at the field-scale. This proposed MRST simulator captures the physico-chemical aspects of the LSP flooding, including inaccessible pore volume (IPV), polymer rheology, permeability reduction, and the effects of shear rate and salinity. After successful implementation and validation of the proposed MRST simulator to predict LSP performance at the core scale, field-scale simulations were used to assess LSP injection in a quarter 5-spot well pattern. To identify the optimal LSP injection scenario on oil recovery and oil residual saturation, we carried out a sensitivity analysis by varying the injected water salinity, polymer concentration, and injection scheme.
The field-scale simulation results revealed the positive effect of injection polymer concentration on polymer viscosity, and thus, oil displacement efficiency. Likewise, tertiary polymer flooding may increase volumetric sweep efficiency by reducing gravity underride and sweeping top layers. Also, tertiary low salinity polymer (LSP) flooding might lead to an additional 11% oil recovery OOIP since it would increase both the microscopic and macroscopic sweep efficiencies. Furthermore, the effect of polymer concentration was not much pronounced compared to the effect of water chemistry (i.e., salinity) on oil recovery and remaining oil saturation. Nonetheless, it is thought that polymer concentration may be one of the key parameters significantly boosting sweep efficiency and oil recovery in reservoirs with more viscous oil. Finally, starting early with LSP flooding in the secondary stage improve oil recovery while yielding higher benefits for environmental and economic advantages. The findings of this study suggest that significant attention must be provided to the selection of water salinity, polymer concentrations, and the adjustment of injection strategies for successful LSP flooding in harsh conditioned carbonate reservoirs.
Quantifying Polymer Injectivity and Performance in the Milne Point Oil Field
Authors: Dean R. M. , Aitkulov A. , Edwards R. 
Published: April 2024

Abstract
Polymer floods often collect a large amount of injectivity data that is often overlooked or minimally explored for additional value. This paper uses a plethora of existing field data for numerous polymer injectors to improve injectivity prediction, potentially identify problem wells, and perform polymer QA/QC using existing field wellhead pressure, bottom hole pressure, and rate data.
Existing injectivity models (Aitkulov, et al. 2021) (Jackson, et al. 2019) (Poulsen, et al. 2018) are used to predict performance and determine difference between prediction and actual injectivity. Step-rate tests (SRT) or cases with multiple rates are also used to quantify well performance, constrain, and quantify rheology parameters in the reservoir, and look for bottom-hole pressures approaching the minimum horizontal stress. Polymer flow in tubing is used to determine friction reduction capabilities and is used to double check that polymer rheology is on specification via calibration with known viscosity using Moody diagrams (Moody 1944).
Many wells were found to be below ideal injectivity on both water and polymer, however most of them were easily explained by pattern orientation, e.g., injection well with only one offset producer. The concept of friction factor (fDW) plots vs. Reynolds numbers (Re) are demonstrated for the purpose of performing QA/QC checks on polymer being injected where applicable.
Unveiling the Enigma of Waterflood Inefficiency: A Multifaceted Analysis of Geological, Petrophysical, and Reservoir Dynamics - A Case Study in a Morrowan Clastic Reservoir
Authors: Morgan A. , Ampomah W. , Grigg R. , Wang S. , Czarnota R. 
Published: April 2024

Abstract
The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the East half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. Furthermore, the use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and poor quality of the injected water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the East half of the reservoir.
A Novel Polymer Gel System for In-Depth Water Conformance in High Temperature and High Salinity Reservoirs
Authors: Lu Meng , Zhang Danhua Leslie , Li Jianshen , Huang Qiushi , Zu Yu , Guo Hongyu , Zhou Nancy , Niu Fangya , Mohanty Kishore 
Published: April 2024

Abstract
Delayed polymer gel systems have been the leading in-depth water conformance control agents in enhanced oil recovery applications. However, most polymer gel systems had limitations to tolerance high temperature and high salinity conditions. The objective of this work is to develop a new delayed polymer gel system that could form stable gels at 80-100 ℃ in brines with salinity up to 200,000 mg/L and a gelation time of more than 3 days.
The gelation tests of a new Acrylamide-ATBS copolymer and a crosslinking agent were performed in anaerobic chambers around 90 ℃ in various synthetic brines with salinity of 50,000 to 200,000 mg/L. Gelation profiles and relationships between gelation time and polymer and crosslinking agent’s concentrations were obtained. Sydansk Gel Code was used to determine gel strength. Sandpack and coreflood experiments were performed to evaluate in-situ gel strength and long-term stability and to measure polymer and crosslinking agent’s adsorption/retention.
The gelation profiles of gelation systems with polymer concentration ranging from 2500-4500 mg/L and crosslinker concentration from 100-1000 mg/L showed that the gelation time was 3-30 days around 90 ℃ with a low pre-gelation viscosity. The gelation time was varied by either the concentration of the polymer or that of the crosslinker and the brine salinity. The gel strength ranged from Code C to Code F. Sandpack and coreflood experiments of injected gelant showed formation of strong gels in-situ with low polymer/crosslinker retention. The permeability reduction of the cores plugged by the polymer gel was greater than 99% and the plugging was effective for more than 12 months.
This work presents a new two-components polymer gel system with low pre-gelation viscosity, long and tunable gelation time, good gel strength and long-term stability to effectively shutoff high permeability channels/zones for in-depth conformance control in high temperature and high salinity reservoirs.
Untethered Downhole Viscosity Logging for EOR Polymer Fluid Degradation Monitoring
Authors: Gonzalez Miguel , Seren Huseyin , Thiel Tim , Hillman Thomas , Ayirala Subhash , Maskeen Lyla , Alkhateeb Abdulaziz , Deffenbaugh Max 
Published: April 2024

Abstract
Enhanced Oil Recovery (EOR) operations based on polymer flooding can be severely impacted if the long-chained polymer molecules used to increase the viscosity of the injected fluid are degraded. This may occur either by mechanical or chemical means at any point of the injection process. Degradation leads to a reduced viscosity, ultimately reducing the effectiveness of the EOR operation. Monitoring the polymer viscosity would help reducing the risk of degradation, which could significantly impact oil recovery rates. Currently, there are no means to perform frequent checks for polymer degradation downhole during injection. We describe a small, untethered downhole tool with an onboard viscometer. The tool is simple and cost-effective, and it can be deployed routinely without need of a wireline logging crew. This instrument may be useful in detecting polymer degradation downhole.
Cyclic Stimulation with Steam and Nitrogen as an Alternative to Improve the Recovery Factor and Energy Efficiency in Colombian Heavy Crude Oil Fields
Authors: Padilla J. M. , Amaya M. P. , Luque I. S. , Osma Laura , Villadiego D. O. , González A. , Pérez R. A. 
Published: April 2024

Abstract
One of the main challenges for exploiting heavy crudes is coupling oil productivity with optimal energy efficiency and low emissions. In that sense, Ecopetrol S.A. has been evaluating EOR technologies, some of them already incorporated in the field development plans, such as the co-injection of steam and nitrogen (N2) in the cyclic stimulation process (CSS), managing to recover a greater volume of incremental oil, reducing the carbon intensity, and optimizing the total heat injected.
In general, the CSS comprises a period of nine (9) days: three days of injecting steam, four days of co-injection (steam through the tubing and nitrogen through the annular), and it ends by injecting steam for two days. The co-injection of steam and nitrogen has been applied in six fields of the Magdalena Middle Valley (MMV) basin, and in the last year, 248 wells were intervened with the objective of improving the efficiency of the injected heat and the response in production. Trying to optimize the field operation of CSS+N2, an exhaustive reservoir engineering analysis, and the development of numerical feasibility studies using a radial single well model built based on representative petrophysical and fluid properties of MMV fields, it was possible to reduce steam volumes by evaluating different injection schemes.
After one year of evaluation, it was found that compared to a conventional steam stimulation cycle, all the wells presented a 30% reduction in carbon intensity (KgCO2/stbo), an increase in energy efficiency by around 27% associated with less energy required to produce a barrel of oil (MMBTU/stbo), represented savings over 4,000,000 USD in natural gas to generate steam and 43% more crude was recovered, additionally the duration of the cycle was extended. According to the numerical evaluation, it is possible to improve these results by finding an injection scheme, which, through post-nitrogen injection for five days, reduces 30% of the volume of steam usually used and improves the indicators of carbon intensity and energy efficiency by 23%. Considering the results obtained, an extended nitrogen injection pilot is proposed for MMV.
Combining field results and experiences with the numerical methodology developed represents a great opportunity for the future of heavy crude oil field production aligned with the carbon footprint reduction goals established in Colombia.
Sustainable On-Off Polymer Injection Reduces more than 50% CO2 Emissions, Materials Demand, and Water by Energy Storage in Formation Compressibility Achieving Equal Recovery Factor as Continuous Polymer Injection
Authors: Serrano V. , Campos H. , Allende C. , Juri J. E. 
Published: April 2024

Abstract
Polymer injection projects need to reduce CO2 emissions, material demand for facilities, water use, and waste to compete as viable solutions in the energy transition. Steel production process is the main contributor to CO2 emission. To address this issue, we have embarked on reducing in 50% our mobile expansion concept, which replaces conventional massive injection plants with reusable ones storing energy in the subsurface.
Here we propose to design a polymer injection project that is in line with circular economic concepts. We reduce the size of the needed facilities and reuse them by storing energy in the formation during injection periods (On) in half patterns and releasing it during shut-in periods (Off) in the other half of patterns. This mechanism is based on the high rock compressibility of the fluvial system in Manantiales Behr. Coupling the high rock compressibility with an On-Offcyclical injection strategy makes the system behave analogue to a spring-mass system that can store and release energy and has resonance conditions. We tested the idea in a conceptual simulator model, then in a sector model and finally, we implemented a pilot in four patterns that already had an oil response baseline by continuous polymer injection. Now, We expanded it to 14 patterns.
We reduced more than 50% of the needs in steel consumption and the energy requirement for constructing and mounting a polymer injection unit. These savings amount to 170 to 405 tCO2 depending on the source of the steel which represents about 0.6% of the annual CO2 reduction per year in London. The incremental recovery factor is 19% incremental almost the same as continuous polymer injection. The reservoir simulations carried out show similarincremental recovery factors with this methodology than those that would be achieved with a massive injection for the same injection wells, achieving slightly lower production peaks, but with less decline and with polymer consumption 30% less than in the case of mass injection.On-Off injection strategy allowed us to feed a greater number of injectors with the same modular plant and reduce polymer consumption by not injecting massively into all the wells of the project at the same time. By Implementing this technology, we managed to reduce the environmental impact by lowering the number of modular injection plants needed and we improved the economics of the project by reducing both the CAPEX and OPEX involved.
This process has a significant impact on all polymer flooding projects that are being undertaken in fluvial Complex Two of Comodoro Rivadavia Formation. Moreover, our mobile expansion concept with modular reusable plants (SPE-200355-MS) targets the installation of ten plants per year. Therefore, the potential reduction in emissions could be ten times greater.
Microscopic Visualization Experiment of High Temperature and High Pressure CO2-C2H6/DME Displacement in Tight Reservoirs
Authors: Wang Chengwei , Su Yuliang , Wang Wendong , Li Lei , Hao Yongmao , Zhu Haiwen 
Published: April 2024

Abstract:
The tight reservoir exhibits pronounced heterogeneity and possesses complex physical properties, thereby constraining crude oil exploitation. Water and CO2 injection for enhanced oil recovery encounter challenges related to low sweep efficiency and viscous fingering, resulting in suboptimal recovery effectiveness. In recent years, there has been growing attention towards the synergistic advantages of oil displacement through the injection of fluids such as CO2, hydrocarbon gases, and chemical additives. This paper presents the design of a microscopic visualization experimental system specifically tailored for studying high-temperature and high-pressure composite fluid displacement in actual tight oil reservoir conditions. Based on the pore throat characteristics inside the core, a visual micro-nano scale pore throat model was created to simulate the flow of composite fluid in micro-nano channels under high temperature and high pressure conditions. The research findings indicate that adding dimethyl ether and ethane to composite gases enhances their solubility and expansion in crude oil. Comparing the occurrence characteristics of residual oil after CO2 injection development reveals that injecting a composite gas (CO2- C2H6-DME) leads to a notable reduction in residual oil in the form of Clustered and oil Porous. The experimental results show that the final recovery rate of composite gas flooding can reach 92.8%, which is 46.7% higher than pure CO2. This paper presents, for the first time, the synergistic enhanced oil recovery (EOR) technology of injecting a composite gas mixture (CO2, C2H6, DME) into tight reservoirs. This study employs microscopic visualization techniques to assess the variation in residual oil characteristics and the enhancement of recovery in crude oils driven by different gases.
Inhomogeneous Fluid Transport Modeling of Gas Injection in Shale Reservoirs Considering Fluid-Solid Interaction and Pore Size Distribution
Authors: Ma Ming , Emami-Meybodi Hamid 
Published: April 2024

Abstract
Gas injection presents unique enhanced oil recovery (EOR) mechanisms in shale reservoirs compared to conventional reservoirs due to the complex nature of fluid transport and fluid-solid interaction in nanopores. We propose a multiphase multicomponent transport model for primary production and gas injection in shale reservoirs considering dual scale porous medium and fluid-solid interactions in nanopores. The shale matrix is separated into macropore and nanopore based on pore size distribution. The density functional theory is employed, accounting for fluid-solid interactions, to compute the inhomogeneous fluid density distribution and phase behavior within multiscale matrix. The calculated fluid thermodynamic properties and transmissibility values are then integrated into the multiphase multicomponent transport model grounded in the Maxwell-Stefan theory to simulate primary production and gas injection processes. Our research underscores the precision of density functional theory in capturing intricate fluid inhomogeneities within nanopores, which is overlooked by the cubic equation of state. The fluid system within varying pores can be classified into confined fluid and bulk fluid, separated by a pore width threshold of 30 nm. Distinct fluid compositions are observed in macropores and nanopores, with heavy components exhibiting a preference for distribution in nanopores due to stronger fluid-solid interactions compared to light components. During primary production period, the robust fluid-solid interactions in nanopores impede the mobility of heavy components, leading to their confinement. Consequently, heavy components within nanopores are difficult to extract during primary production processes. During the CO2 injection period, the injected CO2 induces a significant alteration in fluid composition within both macropores and nanopores, promoting fluid redistribution. The competitive fluid-solid interaction of CO2 results in efficient adsorption on pore walls, displacing propane from nanopores.