bluuebunny/crossref_metadata_2025_split huggingface dataset:
How Polymer Flooding Reduces CO2 Emissions and Energy Consumption - An Exergy Return on Exergy Investment Case Study
Authors: Skauge Tormod , Skauge Arne , Lugo Nancy , Johnson Geoffrey 
Published: April 2024

Abstract
A major part of the energy transition transformation is reduction of carbon footprint in the current oil and gas operations. The energy consumption in the whole chain of operations needs to be evaluated.
The energy efficiency of water flooding is compared to polymer flooding for extraction of heavy oil from an oil field in the UK sector of the North Sea is evaluated using Life Cycle Assessment (LCA) with the concept of Exergy-Return-on-Exergy-Investment (ERoEI). The LCA allows for separation of the process into material and work streams, assessing the impact of each separately. By applying the exergy concept, i.e. the amount of useful energy invested or returned, a comparison of different process steps and different extraction strategies can be achieved.
The Oil field, characterized by an oil viscosity of approximately 80 cP, poses challenges for water flooding operations. Early water breakthrough in producers and high water cuts are anticipated outcomes. While thermal EOR methods could potentially address sweep efficiency concerns, they come at a considerable energy and CO2 cost. Building upon recent advancements in the understanding of polymer flooding for heavy oil extraction, a low-dosage polymer flood was implemented, yielding highly positive results. By utilizing the established water channels in the field, cross-flow of oil into the channels generates a rapid increase in oil production by polymer. In this paper we present the results of an expansion of the current polymer flood to new sections of the field. When comparing like for like development infrastructure and UR recovery times scales, polymer flood leads to a strong acceleration of the oil production which results in a significant increase in Net-Present-Value (NPV). Furthermore, there is an increase of 2.4 times the exergy return on exergy investment and a reduction of 35 % in CO2 emissions.
Extraction of heavy oil has for a long time been dominated by energy intensive and/or inefficient methods. Our study demonstrates that the implementation of low-dosage polymer flooding not only significantly enhances recovery rates, accelerating production by decades, but also accomplishes this with reduced energy cost. The CO2 intensity (kg CO2/bbl oil) is quantified and providing a useful optimization factor for the polymer flood design.
Associative Polymer Propagation, Pressure Response, and Recovery
Authors: Mai K. L. , Watts N. A. , Herman G. C. 
Published: April 2024

Abstract
Hydrophobically modified polyacrylamides, commonly referred to as associative polymers (aP), present a promising alternative to conventional hydrolyzed polyacrylamides (HPAM) used in enhanced oil recovery (EOR). The bulk rheological properties of associative polymers have been studied in the literature and are believed to be well understood. However, debate continues over the underlying mechanisms that govern the observed behaviors of aP in porous media testing. In this study, a mechanistic single-phase coreflood test was conducted to investigate aP behaviors in porous media at shear rates representative of deep-reservoir flow. Additionally, a series of two-phase coreflood tests were performed to study potential application advantages of aP over HPAM. The resulting observations support a hypothesis that high resistance factors (RF) generated by aP are caused by formation in the porous media of an associative network which modifies permeability. This study also provides support for proposals from literature that the formation of the permeability-modifying associative network is dependent upon specific surface characteristics in which the hydrophobic groups of aP adsorbed on the pore surface can functionally anchor an associative network in the pore space. Building upon these concepts and study of previous observations, we propose a mechanism that certain processes can affect these associative anchor points to allow for the mobilization and removal of the retained associative network out of the porous media. This observed behavior may function by either removing these anchor points or by masking their attraction to the non-adsorbed associative polymer. In addition to these studies of flow mechanisms, the two-phase testing demonstrated superior RF generation and incremental oil recovery when utilizing aP compared to HPAM of similar molecular weight, showing potential for aP to improve incremental recovery with reduced concentration versus conventional HPAM.
Does Interfacial Viscoelasticity Increase Oil Recovery at Very High Temperature and Salinity in Carbonates?
Authors: Chávez-Miyauchi Tomás Eduardo , Kar Taniya , Ayirala Subhash , Yousef Ali , Firoozabadi Abbas 
Published: April 2024

Abstract
Flooding with low salinity water (LSW) may increase oil recovery. Despite the general belief that the mechanism of LSW is governed by wettability alteration, crude oil-water interfacial viscoelasticity appears to be a more dominant oil recovery process. Our recent work using 15 crude oils from different parts of the world show that there is a strong correlation between the elasticity of the oil-brine interface and oil recovery. The elasticity of the crude oil – water interface may be tuned by a very small amount of a polymeric surfactant.
In this work, we present a systematic study in four different crude oils (A, B, C, D) with different viscoelastic interfaces in different crude oil-brines. We have measured interfacial elasticity of crude-low salinity water (LSW), crude-high salinity water (HSW), and crude-high salinity water with 100 ppm polymeric surfactant (HSW-PS). The polymeric surfactant may increase the interfacial elasticity of the interface significantly. Two of the crude oils (A and C) show an increase in interface elasticity with 100 ppm PS in HSW. In the second crude oil (B), there is not much change in interface elasticity observed with HSW, LSW, and HSW-PS. With the fourth crude oil (D) we observe LSW and HSW-PS increase interface elasticity. We have conducted nine different coreflooding experiments. Six are at 50 °C, one at 90 C, and other two at 100 °C. Extra recoveries vary in the range of 8% to 20% for systems with high elasticity promoted by the addition of 100 ppm polymeric surfactant in HSW. In crude A, we observe the largest extra recovery with HSW-PS at 50°C; it is 20% higher in comparison to LSW. At 100°C, extra recovery with HSW-PS is 10%. At both temperatures, pressure drop is lower with HSW-PS than with LSW. The implication is higher injectivity besides mobilizing incremental residual oil from carbonate cores.
Measurements and Modeling of Polyacrylamide Polymer Viscosities for Chemical EOR Applications
Authors: Jang Sung Hyun , Nurmi Leena , Mattis Nytara , Bava Luciana , Rosati Louis 
Published: April 2024

Abstract
High molecular weight Polyacrylamide polymer brine viscosities were measured and modeled in a wide range of conditions to improve fundamental understanding and field application of chemical enhanced oil recovery (EOR) processes. More than 300 steady shear rate sweep viscosity curves were generated using a copolymer of acrylamide-polyacrylate and two sulfonated tert-polyacrylamide polymers. The generated viscosity curves were fitted to the Carreau-Yasuda (C-Y) viscosity model with fixed Huggins coefficient of 0.2. Intrinsic viscosity was determined using Martin's equation for the given polymer and brine. The obtained intrinsic viscosity was correlated to the brine composition using the 22 data points for each polymer, so this correlation for intrinsic viscosity is a function of material and brine composition. The zero-shear viscosity, shear thinning index, and time constant parameters of the C-Y model were then correlated to intrinsic viscosity, polymer concentration, and temperature for all three polymers simultaneously, which enabled a unified model approach. Polymer solution viscosities were modeled by plugging three individual correlations for zero shear viscosity, time constant, and shear thinning exponent into C-Y model. The modeling results were compared and discussed with those of the Abdullah et al. model (Abdullah et al., 2023) and the Jouenne and Lavache model (Jouenne and Levache, 2020). Of particular importance is the range and composition of the synthetic brines which are representative of the real brine chemistry variable space in chemical EOR research and field applications. The synthetic brine compositions were derived from 119 brines of polymer flooding field projects worldwide, so the work is aimed at practical field applications by excluding unrealistic brine compositions from the design-of-experiment stage. The proposed viscosity model demonstrated significantly improved prediction performances and/or workflow compared to the existing models.
Critical Thresholds for Deep CO2 Foam Generation: Effects of Injected Quality, Surfactant Concentration and Permeability
Authors: Wei B. , Yang M. , Tang J. , Wang Y. , Lu J. , Rossen W. R. 
Published: April 2024

Abstract
Long-distance propagation of foam is one key to deep gas mobility control for enhanced oil recovery and CO2 sequestration. It depends on two processes: convection of bubbles and foam generation at the displacement front. Prior studies with N2 foam show the existence of a critical threshold for foam generation in terms of a minimum pressure gradient (∇pgenmin) or minimum total interstitial velocity (vt,genmin), beyond which strong-foam generation is triggered. The same mechanism controls foam propagation. There are few data for ∇pgenmin or vt,genmin for CO2 foam.
We extend previous studies to quantify ∇pgenmin and vt,genmin for CO2 foam generation, and relate ∇pgenmin and vt,genmin with factors including injected quality (gas volume fraction in the fluids injected) - fg, surfactant concentration - Cs, and permeability - K. In each experiment, steady pressure gradient, ∇p, is measured at fixed injection rate and quality, with total interstitial velocity, vt, increasing-then-decreasing in a series of steps. The trigger for strong-foam generation features an abrupt jump in ∇p upon an increase in vt.
In most cases, the data for ∇p as a function of vt identify three regimes: coarse foam with low ∇p, an abrupt jump in ∇p, and strong foam with high ∇p. The abrupt jump in ∇p upon foam generation demonstrates the existence of ∇pgenmin and vt,genmin for CO2 foam. We further show how ∇pgenmin and vt,genmin scale with fg, Cs and K. Conditions that stabilize lamellae reduce the values of the thresholds: both ∇pgenmin and vt,genmin increase with fg and decrease with increasing Cs or K. Specifically, ∇pgenmin scales with fg as (fg)2 and vt,genmin scales as (fg)4, and both ∇pgenmin and vt,genmin scale with Cs as (Cs)−0.4. The effect of K on the thresholds for foam generation is greater than the effects of fg and Cs. Our data in artificial consolidated cores show that ∇pgenmin scales with K as K−2 for CO2 foam, in comparison to K−1 for N2 foam in unconsolidated sand/bead packs. More data are needed to verify the confidence of these correlations.
It is encouraging that ∇pgenmin in the cores with K = 270 mD or greater is less than 0.17 bar/m (~ 0.75 psi/ft), 2 to 3 orders of magnitude less than for N2 foam. Such low ∇pgenmin can be easily attainable throughout a formation. This suggests that: limited ∇p deep in formations is much less of a restriction for long-distance propagation of CO2 foam than for N2 foam. Foam propagation could still be challenging in low-K reservoirs (∇pgenmin ~ 10 bar/m for K = 27 mD). Nevertheless, formation heterogeneity and alternating slug injection of gas and liquid help foam generation and may well reduce the values of ∇pgenmin. More research is needed to predict long-distance propagation of foam under those conditions.
An Experimental Investigation of Polymer Enhanced CO2 Foam Flooding: Foam Stabilization and CO2 Mobility Control
Authors: Lliguizaca-Davila Jorge Rodrigo , Sanz Jorge Segundo Mendoza , Brattekås Bergit , Alcorn Zachary Paul 
Published: April 2024

Abstract
Carbon dioxide (CO2) foam mobility control in CO2 storage and enhanced oil recovery can improve the storage potential and oil production by reducing CO2 mobility and increasing reservoir sweep efficiency. A coreflooding study of CO2 foam strength and stability during the co-injection of CO2 and a nonionic surfactant (CO2 foam) solution with and without hydrolyzed polyacrylamide (HPAM) polymers was conducted, including one experiment adding chromium cross-linker solution to the surfactant-polymer solution, to assess gelation effects to assess the effects on improving CO2 mobility reduction. Foam strength, stability, and propagation at unsteady-state flow were compared between the surfactant-based CO2 foam and the polymer-enhanced foam (PEF) solution at 70% foam quality in sandstone cores at scales of 9 cm and 83 cm in length, and rates of 2 ft/day and 4 ft/day. In addition, pure CO2 was injected after foam to identify dynamic changes in foam stability and determine CO2 flow reduction efficiency of the solutions after their placement. Furthermore, the experiment with the 83 cm core added a stage of injection with a chromium cross-linker solution to the surfactant-polymer solution to assess the propagation and strength of the PEF gelled. Apparent viscosity quantified foam strength during co-injections of CO2 foam and CO2 PEF. Adding HPAM polymers significantly increased the foam's apparent viscosity, efficiently creating a stronger foam. PEF propagated at a higher differential pressure compared to CO2 foam, but differential pressure did not increase substantially during the injection of several pore volumes. While the effect of foam injections without polymer was fully reversible during pure CO2 injections, polymer-enhanced foams could significantly reduce the flow of CO2 after placement. The PEF floods high DP showed that the polymer has the ability to block flow channels. The chromium cross-linker with the polymer solution showed that gelation occurred during injection, after which gel entirely blocked the core so CO2 could not enter. Higher rates showed the shearthining behavior of foams and a higher impact on reducing flow mobility during and after the PEF placement. Foam with added polymers may be promising for CO2 mobility reduction during and after placement. Foam has been acknowledged to reduce carbon dioxide (CO2) mobility during its injection in a porous media from pore scale to field scale. Therefore, enhancing in-situ CO2 foam propagation into sedimentary reservoirs is essential to maximize CO2 storage and EOR, and it may be achieved by adding polymers in the liquid lamellae.
Evaluation of a Wettability Modifier on Improving Oil Recovery in Fractured Reservoirs
Authors: Siddique A. K. , Uzun O. , Alghunaim E. S. , Zerpa L. E. , Kazemi H. 
Published: April 2024

Abstract
Enhanced Oil Recovery (EOR) methods using injection of cost-effective, water-soluble chemical additives (e.g., surfactants and mutual solvents) have great potential for increasing oil recovery from low-permeability fractured reservoirs. In a previous paper (Alghunaim et al., 2021), we presented experimental results pertaining to the efficacy of using a 1% solution of 3-pentanone (a mutual solvent) and separately a 1% non-ionic surfactant solution injected in four unfractured Permian Basin carbonate cores saturated with a low-salinity brine. The experiments indicated that we produced substantial amounts of oil from the four non-fractured Permian Basin San-Andres cores with permeability ranging from 2.67 mD to 17 mD, and porosity from 7.4% to 12.14%. In the experimental study pertaining to this paper, we used a fractured and an unfractured sandstone core to demonstrate oil recovery potential of 3-pentanone. The main factors that affect oil recovery from fractured reservoirs are preferential flow through fractures that provide large surface areas, matrix rock heterogeneity, and rock wettability.
The wettability modifying agents reduce both the interfacial tension between oil and water and the water-oil contact angle to enhance oil recovery. The laboratory assessment included measurements of interfacial tension, rock wettability alteration, and incremental oil recovery beyond waterflood. To quantify the efficacy of 3-pentanone, coreflooding experiments included injecting this mutual solvent both in an unfractured core and a fractured core in a Colton sandstone from Central Utah. The effects of changing concentration of 3-pentanone and duration of soaking period before injecting water were also investigated. The results showed that the oil recoveries from the unfractured core and fractured core at the end of the flooding tests were 59.85% and 64.28%, respectively with the incremental oil recovery of 7% and 22%, respectively. The incremental oil recovery from 3-Pentanone can be explained by the combination of various mechanisms that includes a slight reduction in interfacial tension, alteration of rock wettability from water-wet to strongly water-wet (contact angle reduced from 38° to 18°) and ketone partitioning into the oil phase with a reduction in oil viscosity and increased oil mobility. The increase in enhanced oil recovery by ketone solution in the fractured core is probably due to the increase in mass transfer surface area between the fracture and the rock matrix. The 3-pentanone solution provides an operationally simple, environmentally friendly, and cost-effective EOR method in low-permeability formations.
Insights Into Oil Bank Propagation in Reservoirs Under Bottom Aquifer Drive During Polymer Flooding
Authors: Al Ghafri Al Yaqathan , Karpan Volodimir , Al Sulaimani Hanaa , Al Ramli Najib , van Batenburg Diederik 
Published: April 2024

Abstract
The current work aims to understand and characterise the parameters governing the development of the oil bank and its propagation in viscous oil reservoirs under bottom aquifer drive during polymer flooding. The interest in the scope originated from two recent polymer trials which culminated in different results in terms of the oil bank breakthrough time. A two-dimensional numerical model, homogeneous and anisotropic medium under the influence of gravity, is deployed. The model, subjected to an infinite Carter-Tracy type bottom aquifer uses trial's data. Various parameters were studied and compared, including remaining oil saturation, injector-producer distance, voidage replacement ratio, and polymer viscosity. The polymer trials, namely E6 and E157 gave breakthrough time within a few months and a few years respectively. Based on our study, it was concluded that the primary factor for delaying the oil gain in E157 was the remaining oil saturation. The findings address how the initial remaining oil saturation, if overlooked, could significantly delay the oil gain. Nevertheless, the injector-producer distance is another factor that could also contribute to such a delay. The work outcome should be taken as a learning when developing mature oil reservoirs with similar engineering and geological settings.
Synergistic Effects of Binary Surfactant Systems for Enhanced Oil Recovery in Carbonates
Authors: Bello Ayomikun , Rodionov Alexander , Ivanova Anastasia , Cheremisin Alexey 
Published: April 2024

Abstract
This study investigates the use of binary surfactant systems for enhancing oil recovery (EOR) in carbonate formations, which have complex surface charges and harsh conditions (high temperature, high salinity) that limit the effectiveness of single surfactants. Binary surfactants form mixed micelles with lower interfacial tension (IFT) and higher solubilization capacity than single surfactants, thus improving their performance and synergism. We measured the critical micelle concentrations (CMCs) of various binary surfactant ratios and applied Rubingh's Regular Solution Theory (RST) to analyze their behavior and interactions. We found that the binary surfactants had lower CMCs than their individual components, which means less surfactant is needed to achieve optimal surface activity, reducing costs and environmental impact. The nonionic surfactant concentration was a key factor for synergism. We also conducted static adsorption and spontaneous imbibition tests to examine the effects of binary surfactants on oil recovery. We observed that the nonionic surfactant reduced the adsorption of the anionic and cationic surfactants by 53% and 28%, respectively, and increased the recovery factor to nearly 60%. Our results demonstrate the potential of binary surfactant systems for EOR in carbonate formations, as well as for CO2 sequestration and filtration optimization.
Polymer Flooding: The Good, the Bad, and the Ugly - Lessons Learned from Field Practices
Authors: Chang Harry L. , Guo Zhidong , Zhang Jieyuan 
Published: April 2024

AbstractIt has been over 40 years since the publication of an early paper titled 'Polymer Flooding, Yesterday, Today, and Tomorrow' in the Journal of Petroleum Technology (Chang, 1978). Significant progress has been achieved since then, with successful commercial-scale applications in China (Daqing, Shengli, Xinjiang, Henan, and Bohai Bay offshore), Canada (Pelican Lake and Brintnell), India (Mangala), Oman (Marmul), the UK North Sea (Captain), and the USA (Yates, Vacuum, and Milne Point) since then. However, global polymer flooding (PF) production remains below expectations by the industry, particularly in the US (NPC, 1976 and 1984). The objective of this paper is to share our analyses and lessons learned to encourage more commercial-scale applications of PF worldwide.This paper reviews basic concepts, screening criteria, and mechanisms of polymer flooding and analyzes historical PF field activities from the early 1960s through 2023. It then presents reasons for the lower-than-forecast productions. Conventional wisdom holds that low crude oil prices are the roadblock to the commercialization of all chemical flooding. However, our analysis suggests that this is not the case, and there are other reasons for the lower-than-forecast results.Based on the progress made over the decades, we divide PF into three stages: the exploration stage from 1960 through 1980, the development stage from 1981 through 2000, and the commercialization stage from 2001 through 2023, including nine major commercial-scale polymer flooding projects worldwide. We analyzed key factors that impacted PF technology over the years, including the critical amount of polymer used, the impact of reservoir heterogeneity on-field performance, the issue of ineffective polymer recycling, the reversal of injection profile, injectivity and productivity problems, and difficulties in treating produced fluids.After these analyses, we propose a set of design criteria, including reservoir evaluation, polymer selection and slug design, laboratory and simulation studies, pre-commercial field tests, and surveillance/monitoring programs to ensure commercial success. We suggest areas for improvement in future operations, such as enhanced PF combined with other technologies. Future applications of polymer flooding in high-temperature and high-salinity, heavy oil, and carbonate reservoirs are also discussed.