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1
Gilman, J. R. y D. J. MacMillan. "Improved Interpretation of the Inaccessible Pore-Volume Phenomenon". SPE Formation Evaluation 2, n.º 04 (1 de diciembre de 1987): 442–48. http://dx.doi.org/10.2118/13499-pa.
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Sotirchos, Stratis V. y Solon Zarkanitis. "Inaccessible pore volume formation during sulfation of calcined limestones". AIChE Journal 38, n.º 10 (octubre de 1992): 1536–50. http://dx.doi.org/10.1002/aic.690381006.
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Bahadur, Jitendra, Cristian R. Medina, Lilin He, Yuri B. Melnichenko, John A. Rupp, Tomasz P. Blach y David F. R. Mildner. "Determination of closed porosity in rocks by small-angle neutron scattering". Journal of Applied Crystallography 49, n.º 6 (2 de noviembre de 2016): 2021–30. http://dx.doi.org/10.1107/s1600576716014904.
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Small-angle neutron scattering (SANS) and ultra-small-angle neutron scattering (USANS) have been used to study a carbonate rock from a deep saline aquifer that is a potential candidate as a storage reservoir for CO2sequestration. A new methodology is developed for estimating the fraction of accessible and inaccessible pore volume using SANS/USANS measurements. This method does not require the achievement of zero average contrast for the calculation of accessible and inaccessible pore volume fraction. The scattering intensity at highQincreases with increasing CO2pressure, in contrast with the low-Qbehaviour where the intensity decreases with increasing pressure. Data treatment for high-Qscattering at different pressures of CO2is also introduced to explain this anomalous behaviour. The analysis shows that a significant proportion of the pore system consists of micropores (<20 Å) and that the majority (80%) of these micropores remain inaccessible to CO2at reservoir pressures.
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Xiong, Lei, Yu Huang, Yuewei Wu, Chaochao Gao y Wenxi Gao. "Study on the Influence of Inaccessible Pore Volume of Polymer Development". IOP Conference Series: Earth and Environmental Science 170 (julio de 2018): 022045. http://dx.doi.org/10.1088/1755-1315/170/2/022045.
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Lund, T., E. Ø. Bjørnestad, A. Stavland, N. B. Gjøvikli, A. J. P. Fletcher, S. G. Flew y S. P. Lamb. "Polymer retention and inaccessible pore volume in North Sea reservoir material". Journal of Petroleum Science and Engineering 7, n.º 1-2 (abril de 1992): 25–32. http://dx.doi.org/10.1016/0920-4105(92)90005-l.
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Rusin, Zbigniew, Piotr Stępień y Karol Skowera. "Influence of fly ash on the pore structure of mortar using a differential scanning calorimetry analysis". MATEC Web of Conferences 322 (2020): 01027. http://dx.doi.org/10.1051/matecconf/202032201027.
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In the paper a low-temperature thermoporometry using differential scanning calorimetry (DSC) was employed for analyse of influence of siliceous fly ash (FA) on pore structure of non-air-entrained mortars (pore size, connectivity). A method of interpreting a heat flux differential scanning calorimetry records in pore structure was used for this purpose. The results demonstrated that the: (i) fly ash mortars have virtually no pores inaccessible to water, unlike the mortars with plain Portland cement in which inaccessible pores constitute a significant fraction, growing with the increase in w/b; (ii) with a decrease in w/b the ink-bottle volume decreases. Fraction of this pore type is relatively larger in fly ash mortars; (iii) Siliceous fly ash increased the volume of pores greater than 8 nm, in particular in the group with radii larger than 20 nm at all w/b ratios.
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Lan, Yuzheng, Rouzbeh Ghanbarnezhad Moghanloo y Davud Davudov. "Pore Compressibility of Shale Formations". SPE Journal 22, n.º 06 (17 de agosto de 2017): 1778–89. http://dx.doi.org/10.2118/185059-pa.
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Summary This study introduces a novel outlook on a shale-pore system and on the potential effect of pore compressibility on the production performance. We divide porosity of the system into accessible and inaccessible pores, and incorporate inaccessible pores with grains into the part of the rock that is not accessible. In general, accessible pores contribute to flow directly, whereas inaccessible pores do not. We present a mathematical model that uses mercury-injection capillary pressure (MICP) data to determine the accessible-pore and inaccessible part of the rock (IRP) compressibility as a function of pressure. During MICP testing in a typical shale sample, the rock sample experiences conformance, compression, and intrusion as effective pressure increases. We characterize the compressibility value dependent on MICP data as a function of pressure. The calculated compressibility values for accessible pores generally appear to be much greater (two to three orders of magnitude) than those of IRP. Next, we evaluate how calculated accessible-pore-compressibility values affect gas recovery in several shale-gas plays. Our results suggest that substitution of total pore compressibility with accessible-pore compressibility can significantly change the reservoir-behavior prediction. The fundamental rock property used in many reservoir-engineering calculations including reserves estimates, reservoir performance, and production forecasting is the total pore-volume (PV) compressibility, which has an approximate value typically within the range of 1 × 10−6 to 1 × 10−4 psi−1 (Mahomad 2014). By recognizing the part of the pore system that actually contributes to production and identifying its compressibility, we can substitute total pore compressibility with accessible-pore compressibility. The result changes the value by nearly two orders of magnitude. The outcome of the paper changes the industry's take on prediction of reservoir performance, especially the rock-compaction mechanism. This study finds that production caused by rock compaction is in fact much greater than what has often been regarded, which will change the performance evaluation on a great number of reservoirs in terms of economic feasibility.
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Ferreira, V. H. S. y R. B. Z. L. Moreno. "Rheology-based method for calculating polymer inaccessible pore volume in core flooding experiments". E3S Web of Conferences 89 (2019): 04001. http://dx.doi.org/10.1051/e3sconf/20198904001.
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Polymer flooding is an enhanced oil recovery (EOR) method that reduces the mobility ratio between the displaced oil and the displacing injected water. The flow of polymer solutions through porous media is subject to some process-specific phenomena, such as the inaccessible pore volume (IAPV). Due to IAPV, polymer molecules move faster through the porous medium than smaller ones. Thus the IAPV value needs to be accounted for in experiments and field projects. Recent reports found that polymer in-situ rheology correlates with the IAPV. The objective of this paper is to develop a method for estimating IAPV based on the in-situ rheology of polymers. The methodology proposed here can be used in both single- and two-phase experiments. The technique requires measurement of polymer resistance factor (RF) and residual resistance factor (RRF) at steady state conditions. Core permeability, porosity, and residual oil saturation, as well as water and polymer bulk viscosities, also need to be taken into account. Correlations for polymer in-situ viscosity and shear rate are solved simultaneously, to wield an estimative for the IAPV. Aiming at to prove the method, we report 16 core-flooding experiments, eight single- and eight two-phase experiments. We used a flexible polymer and sandstone cores. All the tests were run using similar rock samples. In the single-phase experiments, we compare the alternative method with the classic tracer method to estimate IAPV. The results show an average relative difference of 11.5% between the methods. The two-phase results display, on average, an 18% relative difference to the IAPV measured in the single-phase experiments. The difference between single- and two-phase results can be an effect of the higher shear rates experienced in the two-phase floodings since, in these cases, the aqueous phase shear rate is also dependent on the phase saturation. Additionally, temperature, core length, pore pressure, and iron presence on the core did not show any influence on the IAPV for our two-phase experiments. The method proposed in this paper is limited by the accuracy of the pressure drop measurements across the core. For flexible polymers, the method is valid only for low and mid shear rates, but, accoording to literature, for rigid polymers the method should be accurate for a broad range of shear rates. The method proposed here allows the measurement of polymer IAPV on two- and single- phase core-flooding experiments when a tracer is not used.
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Leng, Jianqiao, Xindi Sun, Mingzhen Wei y Baojun Bai. "A Novel Numerical Model of Gelant Inaccessible Pore Volume for In Situ Gel Treatment". Gels 8, n.º 6 (13 de junio de 2022): 375. http://dx.doi.org/10.3390/gels8060375.
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Inaccessible pore volume (IAPV) can have an important impact on the placement of gelant during in situ gel treatment for conformance control. Previously, IAPV was considered to be a constant factor in simulators, yet it lacked dynamic characterization. This paper proposes a numerical simulation model of IAPV. The model was derived based on the theoretical hydrodynamic model of gelant molecules. The model considers both static features, such as gelant and formation properties, and dynamic features, such as gelant rheology and retention. To validate our model, we collected IAPV from 64 experiments and the results showed that our model fit moderately into these lab results, which proved the robustness of our model. The results of the sensitivity test showed that, considering rheology and retention, IAPV in the matrix dramatically increased when flow velocity and gelant concentration increased, but IAPV in the fracture maintained a low value. Finally, the results of the penetration degree showed that the high IAPV in the matrix greatly benefited gelant placement near the wellbore situation with a high flow velocity and gelant concentration. By considering dynamic features, this new numerical model can be applied in future integral reservoir simulators to better predict the gelant placement of in situ gel treatment for conformance control.
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Hilden, Sindre T., Halvor Møll Nilsen y Xavier Raynaud. "Study of the Well-Posedness of Models for the Inaccessible Pore Volume in Polymer Flooding". Transport in Porous Media 114, n.º 1 (15 de junio de 2016): 65–86. http://dx.doi.org/10.1007/s11242-016-0725-8.
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Meirer, Florian, Sam Kalirai, Darius Morris, Santosh Soparawalla, Yijin Liu, Gerbrand Mesu, Joy C. Andrews y Bert M. Weckhuysen. "Life and death of a single catalytic cracking particle". Science Advances 1, n.º 3 (abril de 2015): e1400199. http://dx.doi.org/10.1126/sciadv.1400199.
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Fluid catalytic cracking (FCC) particles account for 40 to 45% of worldwide gasoline production. The hierarchical complex particle pore structure allows access of long-chain feedstock molecules into active catalyst domains where they are cracked into smaller, more valuable hydrocarbon products (for example, gasoline). In this process, metal deposition and intrusion is a major cause for irreversible catalyst deactivation and shifts in product distribution. We used x-ray nanotomography of industrial FCC particles at differing degrees of deactivation to quantify changes in single-particle macroporosity and pore connectivity, correlated to iron and nickel deposition. Our study reveals that these metals are incorporated almost exclusively in near-surface regions, severely limiting macropore accessibility as metal concentrations increase. Because macropore channels are “highways” of the pore network, blocking them prevents feedstock molecules from reaching the catalytically active domains. Consequently, metal deposition reduces conversion with time on stream because the internal pore volume, although itself unobstructed, becomes largely inaccessible.
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Ferreira, V. H. S. y R. B. Z. L. Moreno. "POLYMER APPARENT VISCOSITY DEPENDENCE ON INACCESSIBLE PORE VOLUME: LABORATORY AND FIELD STUDIES OF ITS INFLUENCE ON ENHANCED OIL RECOVERY". Brazilian Journal of Petroleum and Gas 12, n.º 4 (10 de enero de 2019): 205–18. http://dx.doi.org/10.5419/bjpg2018-0019.
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Jiang, Y., M. Lawrence, M. P. Ansell y A. Hussain. "Cell wall microstructure, pore size distribution and absolute density of hemp shiv". Royal Society Open Science 5, n.º 4 (abril de 2018): 171945. http://dx.doi.org/10.1098/rsos.171945.
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This paper, for the first time, fully characterizes the intrinsic physical parameters of hemp shiv including cell wall microstructure, pore size distribution and absolute density. Scanning electron microscopy revealed microstructural features similar to hardwoods. Confocal microscopy revealed three major layers in the cell wall: middle lamella, primary cell wall and secondary cell wall. Computed tomography improved the visualization of pore shape and pore connectivity in three dimensions. Mercury intrusion porosimetry (MIP) showed that the average accessible porosity was 76.67 ± 2.03% and pore size classes could be distinguished into micropores (3–10 nm) and macropores (0.1–1 µm and 20–80 µm). The absolute density was evaluated by helium pycnometry, MIP and Archimedes' methods. The results show that these methods can lead to misinterpretation of absolute density. The MIP method showed a realistic absolute density (1.45 g cm −3 ) consistent with the density of the known constituents, including lignin, cellulose and hemi-cellulose. However, helium pycnometry and Archimedes’ methods gave falsely low values owing to 10% of the volume being inaccessible pores, which require sample pretreatment in order to be filled by liquid or gas. This indicates that the determination of the cell wall density is strongly dependent on sample geometry and preparation.
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Li, Jing, Keliu Wu, Zhangxin Chen, Kun Wang, Jia Luo, Jinze Xu, Ran Li, Renjie Yu y Xiangfang Li. "On the Negative Excess Isotherms for Methane Adsorption at High Pressure: Modeling and Experiment". SPE Journal 24, n.º 06 (5 de agosto de 2019): 2504–25. http://dx.doi.org/10.2118/197045-pa.
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Summary An excess adsorption amount obtained in experiments is always determined by mass balance with a void volume measured by helium (He) –expansion tests. However, He, with a small kinetic diameter, can penetrate into narrow pores in porous media that are inaccessible to adsorbate gases [e.g., methane (CH4)]. Thus, the actual accessible volume for a specific adsorbate is always overestimated by an He–based void volume; such overestimation directly leads to errors in the determination of excess isotherms in the laboratory, such as “negative isotherms” for gas adsorption at high pressures, which further affects an accurate description of total gas in place (GIP) for shale–gas reservoirs. In this work, the mass balance for determining the adsorbed amount is rewritten, and two particular concepts, an “apparent excess adsorption” and an “actual excess adsorption,” are considered. Apparent adsorption is directly determined by an He–based volume, corresponding to the traditional treatment in experimental conditions, whereas actual adsorption is determined by an adsorbate–accessible volume, where pore–wall potential is always nonpositive (i.e., an attractive molecule/pore–wall interaction). Results show the following: The apparent excess isotherm determined by the He–based volume gradually becomes negative at high pressures, but the actual one determined by the adsorbate–accessible volume always remains positive.The negative adsorption phenomenon in the apparent excess isotherm is a result of the overestimation in the adsorbate–accessible volume, and a larger overestimation leads to an earlier appearance of this negative adsorption.The positive amount in the actual excess isotherm indicates that the adsorbed phase is always denser than the bulk gas because of the molecule/pore–wall attraction aiding the compression of the adsorbed molecules. Practically, an overestimation in pore volume (PV) is only 3.74% for our studied sample, but it leads to an underestimation reaching up to 22.1% in the actual excess amount at geologic conditions (i.e., approximately 47 MPa and approximately 384 K). Such an overestimation in PV also underestimates the proportions of the adsorbed–gas amount to the free–gas amount and to the total GIP. Therefore, our present work underlines the importance of a void volume in the determination of adsorption isotherms; moreover, we establish a path for a more–accurate evaluation of gas storage in geologic shale reservoirs with high pressure.
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Manichand, R. N. N. y R. S. S. Seright. "Field vs. Laboratory Polymer-Retention Values for a Polymer Flood in the Tambaredjo Field". SPE Reservoir Evaluation & Engineering 17, n.º 03 (29 de mayo de 2014): 314–25. http://dx.doi.org/10.2118/169027-pa.
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Summary During a polymer flood, polymer retention can have a major impact on the rate of polymer propagation through a reservoir, and consequently on oil recovery. A review of the polymer-retention literature revealed that iron and high-surface-area minerals (e.g., clays) dominate polymer-retention measurements in permeable rock and sand (>100 md). A review of the literature on inaccessible pore volume (IAPV) revealed inconsistent and unexplained behavior. A conservative approach to design of a polymer flood in high-permeability (>1 darcy) sands would assume that IAPV is zero. Laboratory measurements using fluids and sands associated with the Sarah Maria polymer flood in Suriname suggested polymer retention and IAPV values near zero [0±20 μg/g for retention and 0±10% pore volume (PV) for IAPV]. A procedure was developed using salinity-tracer and polymer concentrations from production wells to estimate polymer retention during the Sarah Maria polymer flood in the Tambaredjo reservoir. Field calculations indicated much higher polymer-retention values than those from laboratory tests, typically ranging from approximately 50 to 250 μg/g. Field cores necessarily represent an extremely small fraction of the reservoir. Because of the importance of polymer retention, there is considerable value in deriving polymer retention from field results, so that information can be used in the design of project expansions.
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FERNANDEZ, LAURA GABRIELA, Esteban Gonzalez, A. Pizarro, S. Abrigo, J. Choque y M. Tealdi. "NANOFLUID INJECTIVITY STUDY FOR ITS APPLICATION IN A PROCESS OF ENHANCED OIL RECOVERY (CEOR)". Latin American Applied Research - An international journal 49, n.º 2 (29 de marzo de 2019): 125–30. http://dx.doi.org/10.52292/j.laar.2019.37.
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The application of tertiary recovery techniques through chemical injection (CEOR) is in full development in the mature oil fields of Argentina. An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. A polyacrylamide solution prepared in brine with addition of silica nanoparticles was used as the focus of the study. Dynamic sweep tests of the displacement fluids in a laboratory-scale triaxial cell using a standard Berea sandstone cores that simulates the formation of the reservoir allow the calculation of parameters related to its injectivity, which take into account damage to the formation and blockade of poral throats , such as the resistance factor (FR), the residual resistance factor (FRR), the inaccessible pore volume (VPI) and the dynamic retention of the nanofluid (RD). The injection of the nanofluid has not produced an increase in the damage of the porous medium, so it is potential for its application in the displacement of crude oil.
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Ding, Lei, Qianhui Wu, Lei Zhang y Dominique Guérillot. "Application of Fractional Flow Theory for Analytical Modeling of Surfactant Flooding, Polymer Flooding, and Surfactant/Polymer Flooding for Chemical Enhanced Oil Recovery". Water 12, n.º 8 (4 de agosto de 2020): 2195. http://dx.doi.org/10.3390/w12082195.
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Fractional flow theory still serves as a powerful tool for validation of numerical reservoir models, understanding of the mechanisms, and interpretation of transport behavior in porous media during the Chemical-Enhanced Oil Recovery (CEOR) process. With the enrichment of CEOR mechanisms, it is important to revisit the application of fractional flow theory to CEOR at this stage. For surfactant flooding, the effects of surfactant adsorption, surfactant partition, initial oil saturation, interfacial tension, and injection slug size have been systematically investigated. In terms of polymer flooding, the effects of polymer viscosity, initial oil saturation, polymer viscoelasticity, slug size, polymer inaccessible pore volume (IPV), and polymer retention are also reviewed extensively. Finally, the fractional flow theory is applied to surfactant/polymer flooding to evaluate its effectiveness in CEOR. This paper provides insight into the CEOR mechanism and serves as an up-to-date reference for analytical modeling of the surfactant flooding, polymer flooding, and surfactant/polymer flooding CEOR process.
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Sui, Yingfei, Chuanzhi Cui, Yidan Wang, Shuiqingshan Lu y Yin Qian. "Displacement Mechanism and Flow Characteristics of Polymer Particle Dispersion System Based on Capillary Bundle Model". International Journal of Energy Research 2024 (3 de mayo de 2024): 1–11. http://dx.doi.org/10.1155/2024/4550335.
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During the development of oil reservoirs, a rapid increase in water cut following reservoir flooding leads to inefficient or ineffective circulation of injected water, rendering a significant portion of the remaining oil in the reservoir inaccessible. The displacement method using polymer particle dispersion systems effectively solves the issue of rapid water breakthrough in oil reservoirs. Owing to the particle phase separation phenomenon, polymer particles can selectively penetrate into the larger pores where water circulation is inefficient, enhance their flow resistance, and thereby achieve equilibrium displacement along with an increased swept volume. This paper investigates the heterogeneous distribution of polymer particles within a porous medium, incorporates the red blood cell dendrite concentration distribution theory from biological fluid mechanics, and develops a mathematical model to delineate the viscosity characteristics of polymer particle dispersion systems, taking into account the phase separation phenomenon. Building on this foundation, it formulates a capillary bundle model for the polymer particle dispersion system specifically designed for oil displacement and proceeds to determine its relative permeability curve. Simulation outcomes reveal that at a water saturation level of 0.063, the concentration of polymer particles in fractured large pore capillaries is markedly elevated, yet capillaries with a pore size under 26 μm remain devoid of polymer particles. With the increase of water saturation, the concentration of polymer particles in large pore capillaries reduces, whereas it progressively augments in medium pore capillaries. Upon reaching a peak water saturation of 0.751, capillaries smaller than 18 μm are entirely free of polymer particles. These findings suggest that the heterogeneous distribution of polymer particles markedly inhibits the percolation capabilities of the dispersed system following a water phase breakthrough, facilitating the entry of more dispersion into oil-laden capillaries and thus enhancing the flow capacity of the oil phase.
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Nie, Xiang Rong y Shi Qing Cheng. "Pressure Transient Analysis of Polymer Injection Wells". Advanced Materials Research 361-363 (octubre de 2011): 370–76. http://dx.doi.org/10.4028/www.scientific.net/amr.361-363.370.
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Polymer solution is known as non-Newtonian Fluid. Hence, when a well is injected by polymer solution, the well test data analysis using Newtonian fluid flow model will be erroneous. However, the analysis results usually were inaccurate when generalized non-Newtonian fluid model which considering polymer solution as power law fluid and taking no account of physical and chemical behaviors. These results clearly suggest the need for a study to come up with a new model considering both physical and chemical behaviors when polymer solution flowing in the reservoirs. At first, this study modified two parameter models: viscosity model and permeability decreasing coefficient model, all of them considering diffusion, conduction and IPV (inaccessible pore volume). Then, those models were applied to set up the new well testing model of a well located in an infinite reservoir. The log-log plots of the pressure and pressure derivatives have been prepared through numerical solutions. A further study has been done about the characteristics of the new type curves considering different parameters.
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Ferreira, Vitor H. S. y Rosangela B. Z. L. Moreno. "Experimental evaluation of low concentration scleroglucan biopolymer solution for enhanced oil recovery in carbonate". Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 61. http://dx.doi.org/10.2516/ogst/2020056.
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Injection of polymers is beneficial for Enhanced Oil Recovery (EOR) because it improves the mobility ratio between the displaced oil and the displacing injected water. Because of that benefit, polymer flooding improves sweep and displacing efficiencies when compared to waterflooding. Due to these advantages, polymer flooding has many successful applications in sandstone reservoirs. However, polymer flooding through carbonatic rock formations is challenging because of heterogeneity, high anionic polymer retention, low matrix permeability, and hardness of the formation water. The scleroglucan is a nonionic biopolymer with the potential to overcome some of those challenges, albeit its elevated price. Thus, the objective of this work is to characterize low concentration scleroglucan solutions focusing on EOR for offshore carbonate reservoirs. The laboratory evaluation consisted of rheology, filtration, and core flooding studies, using high salinity multi-ionic brines and light mineral oil. The tests were run at 60 °C, and Indiana limestone was used as a surrogate reservoir rock. A rheological evaluation was done in a rotational rheometer aiming to select a target polymer concentration for the injection fluid. Different filtration procedures were performed using membrane filters to prepare the polymer solution for the displacement process. Core flooding studies were done to characterize the polymer solution and evaluate its oil recovery relative to waterflooding. The polymer was characterized for its retention, inaccessible pore volume, resistance factor, in-situ viscosity, and permeability reduction. Rheology studies for various polymer concentrations indicated a target scleroglucan concentration of 500 ppm for the injection solution. Among the tested filtration methods, the best results were achieved when a multi-stage filtration was performed after an aging period of 24 h at 90 °C temperature. The single-phase core flooding experiment resulted in low polymer retention (20.8 μg/g), inaccessible pore volume (4.4%), and permeability reduction (between 1.7 and 2.4). The polymer solution in-situ viscosity was slightly lower and less shear-thinning than the bulk one. The tested polymer solution was able to enhance the oil recovery relative to waterflooding, even with a small reduction of the mobility ratio (38% relative reduction). The observed advantages consisted of water phase breakthrough delay (172% relative delay), oil recovery anticipation (159% and 10% relative increase at displacing fluid breakthrough and 95% water cut, respectively), ultimate oil recovery increase (6.3%), and water-oil ratio reduction (38% relative decrease at 95% water cut). Our results indicate that the usage of low concentration scleroglucan solutions is promising for EOR in offshore carbonate reservoirs. That was supported mainly by the low polymer retention, injected solution viscosity maintenance under harsh conditions, and oil recovery anticipation.
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Zhu, Changyu, Shiqing Cheng, Youwei He, Engao Tang, Xiaodong Kang, Yao Peng y Haiyang Yu. "Pressure Transient Behavior for Alternating Polymer Flooding in a Three-zone Composite Reservoir". Polymers and Polymer Composites 25, n.º 1 (enero de 2017): 1–10. http://dx.doi.org/10.1177/096739111702500101.
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Alternating polymer flooding has achieved great attractions recently in oil industry, however, the research of pressure analysis in alternating polymer flooding reservoir is rare. This work presents a numerical pressure analysis method of three-zone composite model for formation evaluation. A new numerical pressure analysis model (three-zone composite model) is established by considering diffusion, convection, shear, and inaccessible pore volume, which is based on the rheology experiments. Based on this model, the type curves are then developed and sensitivity analysis is further conducted. The type curves have seven regimes in three-zone composite model. The characteristic is the obvious upturn of pressure derivative curve in transient regime between low concentration and high concentration polymer solution. Formation parameters can be interpreted by history matching and formation evaluation can be conducted based on this model. As an important part of formation evaluation, formation damage as a result of adsorption of polymers in porous media is evaluated by comparing the interpreted permeability with the original value before polymer flooding. The field test data proves that this proposed method can accurately evaluate reservoir characteristics in alternating polymer flooding reservoirs, which emphasizes the potential application of this method in petroleum industry.
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Bryant, Steven y Sue Raikes. "Prediction of elastic‐wave velocities in sandstones using structural models". GEOPHYSICS 60, n.º 2 (marzo de 1995): 437–46. http://dx.doi.org/10.1190/1.1443781.
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Elastic‐wave propagation in fluid‐saturated sandstones depends upon two sets of rock features: (1) the volume fractions and elastic constants of the rock constituents (quartz, clay, water, etc.) and (2) microstructural geometry (grain contacts, pore aspect ratios). While the former data are usually obtainable, the latter are relatively inaccessible. We present a new method for determining microstructural data using idealized but physically representative models of sandstone. The key to the method is the simulation of certain depositional and diagenetic processes in a manner that completely specifies the geometry of the resulting models. Hence, the geometric features of the grain space and void space required for various theories of elastic propagation can be calculated directly from the models. We find good agreement between predictions and measurements of compressional‐ and shear‐wave velocities in both clean and clay‐bearing saturated sandstones. In contrast with previous efforts at predicting velocities, we use no adjustable parameters and require no additional measurements on samples, such as dry velocities or analysis of thin‐section images. The results suggest that it is feasible to predict elastic velocities directly from geological models in the absence of rock samples.
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Liu, Yongge, Jian Hou, Lingling Liu, Kang Zhou, Yanhui Zhang, Tao Dai, Lanlei Guo y Weidong Cao. "An Inversion Method of Relative Permeability Curves in Polymer Flooding Considering Physical Properties of Polymer". SPE Journal 23, n.º 05 (7 de marzo de 2018): 1929–43. http://dx.doi.org/10.2118/189980-pa.
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Summary Reliable relative permeability curves of polymer flooding are of great importance to the history matching, production prediction, and design of the injection and production plan. Currently, the relative permeability curves of polymer flooding are obtained mainly by the steady-state, nonsteady-state, and pore-network methods. However, the steady-state method is extremely time-consuming and sometimes produces huge errors, while the nonsteady-state method suffers from its excessive assumptions and is incapable of capturing the effects of diffusion and adsorption. As for the pore-network method, its scale is very small, which leads to great size differences with the real core sample or the field. In this paper, an inversion method of relative permeability curves in polymer flooding is proposed by combining the polymer-flooding numerical-simulation model and the Levenberg-Marquardt (LM) algorithm. Because the polymer-flooding numerical-simulation model by far offers the most-complete characterization of the flowing mechanisms of polymer, the proposed method is able to capture the effects of polymer viscosity, residual resistance, diffusion, and adsorption on the relative permeability. The inversion method was then validated and applied to calculate the relative permeability curve from the experimental data of polymer flooding. Finally, the effects of the influencing factors on the inversion error were analyzed, through which the inversion-error-prediction model of the relative permeability curve was built by means of multivariable nonlinear regression. The results show that the water relative permeability in polymer flooding is still far less than that in waterflooding, although the residual resistance of the polymer has been considered in the numerical-simulation model. Moreover, the accuracy of the polymer parameters has great effect on that of the inversed relative permeability curve, and errors do occur in the inversed water relative permeability curve—the measurements of the polymer solution viscosity, residual resistance factor, inaccessible pore-volume (PV) fraction, or maximum adsorption concentration have errors.
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Muhammed, Nasiru Salahu, Md Bashirul Haq, Dhafer Al-Shehri, Mohammad Mizanur Rahaman, Alireza Keshavarz y S. M. Zakir Hossain. "Comparative Study of Green and Synthetic Polymers for Enhanced Oil Recovery". Polymers 12, n.º 10 (21 de octubre de 2020): 2429. http://dx.doi.org/10.3390/polym12102429.
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Several publications by authors in the field of petrochemical engineering have examined the use of chemically enhanced oil recovery (CEOR) technology, with a specific interest in polymer flooding. Most observations thus far in this field have been based on the application of certain chemicals and/or physical properties within this technique regarding the production of 50–60% trapped (residual) oil in a reservoir. However, there is limited information within the literature about the combined effects of this process on whole properties (physical and chemical). Accordingly, in this work, we present a clear distinction between the use of xanthan gum (XG) and hydrolyzed polyacrylamide (HPAM) as a polymer flood, serving as a background for future studies. XG and HPAM have been chosen for this study because of their wide acceptance in relation to EOR processes. To this degree, the combined effect of a polymer’s rheological properties, retention, inaccessible pore volume (PV), permeability reduction, polymer mobility, the effects of salinity and temperature, and costs are all investigated in this study. Further, the generic screening and design criteria for a polymer flood with emphasis on XG and HPAM are explained. Finally, a comparative study on the conditions for laboratory (experimental), pilot-scale, and field-scale application is presented.
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Yu, Haiyang, Hui Guo, Youwei He, Hainan Xu, Lei Li, Tiantian Zhang, Bo Xian, Song Du y Shiqing Cheng. "Numerical Well Testing Interpretation Model and Applications in Crossflow Double-Layer Reservoirs by Polymer Flooding". Scientific World Journal 2014 (2014): 1–11. http://dx.doi.org/10.1155/2014/890874.
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This work presents numerical well testing interpretation model and analysis techniques to evaluate formation by using pressure transient data acquired with logging tools in crossflow double-layer reservoirs by polymer flooding. A well testing model is established based on rheology experiments and by considering shear, diffusion, convection, inaccessible pore volume (IPV), permeability reduction, wellbore storage effect, and skin factors. The type curves were then developed based on this model, and parameter sensitivity is analyzed. Our research shows that the type curves have five segments with different flow status: (I) wellbore storage section, (II) intermediate flow section (transient section), (III) mid-radial flow section, (IV) crossflow section (from low permeability layer to high permeability layer), and (V) systematic radial flow section. The polymer flooding field tests prove that our model can accurately determine formation parameters in crossflow double-layer reservoirs by polymer flooding. Moreover, formation damage caused by polymer flooding can also be evaluated by comparison of the interpreted permeability with initial layered permeability before polymer flooding. Comparison of the analysis of numerical solution based on flow mechanism with observed polymer flooding field test data highlights the potential for the application of this interpretation method in formation evaluation and enhanced oil recovery (EOR).
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Gaus, Garri, Anton Kalmykov, Bernhard M. Krooss y Reinhard Fink. "Experimental Investigation of the Dependence of Accessible Porosity and Methane Sorption Capacity of Carbonaceous Shales on Particle Size". Geofluids 2020 (14 de febrero de 2020): 1–13. http://dx.doi.org/10.1155/2020/2382153.
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Crushing and grinding of carbonaceous shale samples is likely to enhance the accessibility of pores and embedded organic matter as compared to the intact rock. This may lead to an overestimation of the total (volume and sorptive) gas storage capacity. In order to investigate the importance of these effects we have measured unconfined apparent grain densities (helium pycnometry) and methane sorption capacities (high-pressure methane excess sorption) of four carbonaceous shales (Cambro-Ordovician Alum Shale, Jurassic Kimmeridge Clay, Jurassic/Cretaceous Bazhenov Shale, and Late Cretaceous Eagle Ford Shale) as a function of particle size. Measurements were first conducted on 38 mm diameter core plugs, which then were crushed and milled to successively smaller particle sizes (<10 mm, <2 mm, <64 μm, and <1 μm). Apparent grain densities of the smallest particle fractions of the Alum, Bazhenov and Kimmeridge samples were consistently higher by 0.5 to 1% than apparent grain densities of the original sample plugs. Methane excess sorption capacity increased significantly for particle sizes <64 μm for the Alum and <1 μm for the Bazhenov and Kimmeridge samples while no significant changes upon grinding were observed for the Eagle Ford Shale. For the Bazhenov Shale, the apparent grain density increased slightly from 2.446 g/cm3 to 2.450 g/cm3 upon particle size reduction from <64 μm to <1 μm while the maximum sorption capacity (“Langmuir volume”) increased substantially from 0.11 mmol/g to 0.19 mmol/g. Similarly, for the Kimmeridge Clay and Alum Shale, a slight increase of the apparent grain density from 1.546 g/cm3 to 1.552 g/cm3 and from 2.362 g/cm3 to 2.385 g/cm3, respectively, was accompanied by increases in sorption capacity from 0.37 mmol/g to 0.45 mmol/g and from 0.14 mmol/g to 0.185 mmol/g, respectively. The increase in sorption capacity indicates an opening of a considerable amount of micropores with large internal surface area upon physical disruption of the rock fabric and/or removal of included fluids. It may also be due to increased swelling abilities of clay minerals and organic matter upon destruction of the stabilizing rock fabric with decreasing particle size. Grain density and sorption isotherms measured on small particle sizes are likely to overestimate the gas storage capacities and the amounts of producible gas-in-place since under field conditions (largely undisrupted rock fabric), significant portions of this storage capacity are essentially inaccessible. Poor interconnectivity of the pore system and slow, diffusion-controlled transport will massively retard gas production. Based on these findings, particle sizes >64 μm should be used for porosity and sorption measurements because they are more likely to retain the properties of the rock fabric in terms of accessible pore volume and sorptive storage capacity.
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Erfando, Tomi y Rizqy Khariszma. "Sensitivity Study of The Effect Polymer Flooding Parameters to Improve Oil Recovery Using X-Gradient Boosting Algorithm". Journal of Applied Engineering and Technological Science (JAETS) 4, n.º 2 (5 de junio de 2023): 873–84. http://dx.doi.org/10.37385/jaets.v4i2.1871.
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Implementation of waterflooding sometimes cannot increase oil recovery effectively and requires additional methods to increase oil recovery. Polymer flooding is a common chemical EOR method that has been implemented in the last few decades and provides good effectiveness in increasing oil recovery and can reduce the amount of injection fluid injected into the reservoir. Seeing the success of polymer flooding in increasing oil recovery, it is necessary to know the parameters that influence the success of polymer flooding so that it can be evaluated and taken into consideration in creating a new scheme to increase oil recovery with polymer flooding. The parameters tested in this study include Injection Rate, Injection Time, Injection Pressure, Adsorption, Inaccessible Pore Volume, Residual Resistance Factor. This research uses the X-Gardient Boosting Algorithm to look at the most influential parameters in polymer flooding. The parameters that most influence the performance of polymer flooding on the value of oil recovery with the importance level of each parameter in this study are injection time of 0.452632, injection rate of 0.430075, injection pressure of 0.064662, Adsorption of 0.025564, RRF of 0.021053, IPV of 0.006014 and produce accurate predictive modeling using x-gradient boosting where with 3 variations of the comparison ratio of training and testing data obtained at a ratio of 0.7 : 0.3 obtained an R2 train of 0.9886 and an R2 test of 0.9645, a ratio of 0.8 : 0.2 obtained an R2 train of 0.9891 and an R2 test of 0.9579, and a ratio of 0.9: 0.1 obtained R2 train of 0.9890 and R2 test of 0.9660.
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Aadland, Reidun, Carter Dziuba, Ellinor Heggset, Kristin Syverud, Ole Torsæter, Torleif Holt, Ian Gates y Steven Bryant. "Identification of Nanocellulose Retention Characteristics in Porous Media". Nanomaterials 8, n.º 7 (19 de julio de 2018): 547. http://dx.doi.org/10.3390/nano8070547.
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The application of nanotechnology to the petroleum industry has sparked recent interest in increasing oil recovery, while reducing environmental impact. Nanocellulose is an emerging nanoparticle that is derived from trees or waste stream from wood and fiber industries. Thus, it is taken from a renewable and sustainable source, and could therefore serve as a good alternative to current Enhanced Oil Recovery (EOR) technologies. However, before nanocellulose can be applied as an EOR technique, further understanding of its transport behavior and retention in porous media is required. The research documented in this paper examines retention mechanisms that occur during nanocellulose transport. In a series of experiments, nanocellulose particles dispersed in brine were injected into sandpacks and Berea sandstone cores. The resulting retention and permeability reduction were measured. The experimental parameters that were varied include sand grain size, nanocellulose type, salinity, and flow rate. Under low salinity conditions, the dominant retention mechanism was adsorption and when salinity was increased, the dominant retention mechanism shifted towards log-jamming. Retention and permeability reduction increased as grain size decreased, which results from increased straining of nanocellulose aggregates. In addition, each type of nanocellulose was found to have significantly different transport properties. Experiments with Berea sandstone cores indicate that some pore volume was inaccessible to the nanocellulose. As a general trend, the larger the size of aggregates in bulk solution, the greater the observed retention and permeability reduction. Salinity was found to be the most important parameter affecting transport. Increased salinity caused additional aggregation, which led to increased straining and filter cake formation. Higher flow rates were found to reduce retention and permeability reduction. Increased velocity was accompanied by an increase in shear, which is believed to promote breakdown of nanocellulose aggregates.
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Clemens, Torsten, Markus Lüftenegger, Ajana Laoroongroj, Rainer Kadnar y Christoph Puls. "The Use of Tracer Data To Determine Polymer-Flooding Effects in a Heterogeneous Reservoir, 8 Torton Horizon Reservoir, Matzen Field, Austria". SPE Reservoir Evaluation & Engineering 19, n.º 04 (14 de febrero de 2016): 655–63. http://dx.doi.org/10.2118/174349-pa.
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Summary Polymer-injection pilot projects aim at reducing the uncertainty and risk of full-field polymer-flood implementation. The interpretation of polymer-pilot projects is challenging because of the complexity of the process and fluids moving out of the polymer-pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir. In the polymer pilot performed in the 8 Torton Horizon (TH) reservoir of the Matzen field in Austria, a polymer-injection well surrounded by a number of production wells was selected. A tracer was injected 1 week before polymer injection. The tracer showed that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. Despite short breakthrough times of 4 to 10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates were not substantially changed. The tracer signal indicated that the reservoir is heterogeneous, with high flow velocities occurring along a number of flow paths with a limited volume that are strongly connecting the injection and production wells. By injecting polymers, the mobility of the polymer-augmented water was reduced compared with water injection, and led to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymer injected. This response was used to assess the changes of the amount of water flowing from the injection well to production wells. After a match for the tracer curve was obtained, adsorption, residual resistance factor (RRF), and dispersivity were calculated. The results showed that, even for heterogeneous reservoirs without good conformance of the pilot, the critical parameters for polymer-injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive. Along the flow path that is connecting injection and production well, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume (IPV) in the reservoir were in the same range as in corefloods. Incremental oil recovery caused by acceleration along the flow path was estimated at approximately 20% of the overall incremental oil production caused by polymer injection and 80% was attributed to improved sweep efficiency.
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Wang, Dongmei, Randall S. Seright, Zhenbo Shao y Jinmei Wang. "Key Aspects of Project Design for Polymer Flooding at the Daqing Oilfield". SPE Reservoir Evaluation & Engineering 11, n.º 06 (1 de diciembre de 2008): 1117–24. http://dx.doi.org/10.2118/109682-pa.
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Summary This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field. Special emphasis is placed on some new design factors that were found to be important on the basis of extensive experience with polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations and injection rates, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs. For some Daqing wells, oil recovery can be enhanced by 2 to 4% of original oil in place (OOIP) with profile modification before polymer injection. For some Daqing wells with significant permeability differential between layers and no crossflow, injecting polymer solutions separately into different layers improved flow profiles, reservoir sweep efficiency, and injection rates, and it reduced the water cut in production wells. Experience over time revealed that larger polymer-bank sizes are preferred. Bank sizes grew from 240-380 mg/L·PV during the initial pilots to 640 to 700 mg/L·PV in the most recent large-scale industrial sites [pore volume (PV)]. Economics and injectivity behavior can favor changing the polymer molecular weight and polymer concentration during the course of injecting the polymer slug. Polymers with molecular weights from 12 to 35 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer-injection volume varied around 0.7 PV, depending on the water cut in the different flooding units. The average polymer concentration was designed approximately 1000 mg/L, but for an individual injection station, it could be 2000 mg/L or more. At Daqing, the injection rates should be less than 0.14-0.20 PV/year, depending on well spacing. Introduction Many elements have long been recognized as important during the design of a polymer flood (Li and Niu 2002; Jewett and Schurz 1970; Sorbie 1991; Vela et al. 1976; Taber et al. 1997; Maitin 1992; Koning et al. 1988; Wang et al. 1995; Wang and Qian 2002; Wang et al. 2008). This paper spells out some of those elements, using examples from the Daqing oil field. The Daqing oil field is located in northeast China and is a large river-delta/lacustrine-facies, multilayer, heterogeneous sandstone in an inland basin. The reservoir is buried at a depth of approximately 1000 m, with a temperature of 45°C. The main formation under polymer flood (i.e., the Saertu formation) has a net thickness ranging from from 2.3 to 11.6 m with an average of 6.1 m. The average air permeability is 1.1 µm2, and the Dykstra-Parsons permeability coefficient averages 0.7. Oil viscosity at reservoir temperature averages approximately 9 mPa·s, and the total salinity of the formation water varies from 3000 to 7000 mg/L. The field was discovered in 1959, and a waterflood was initiated in 1960. The world's largest polymer flood was implemented at Daqing, beginning in December 1995. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding should boost the ultimate recovery for the field to more than 50% OOIP--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 11.6 million m3 (73 million bbl) per year (sustained for 6 years). The polymers used at Daqing are high-molecular-weight partially hydrolyzed polyacrylamides (HPAMs). During design of a polymer flood, critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer-bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water. This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field.
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Nino J.C, Lizcano, Ferreira Vitor Hugo de Sousa y Moreno Rosangela B. Z. L. "Less-Concentrated HPAM Solutions as a Polymer Retention Reduction Method in CEOR". Revista Fuentes el Reventón Energético 18, n.º 1 (11 de marzo de 2020): 75–92. http://dx.doi.org/10.18273/revfue.v17n1-2020008.
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Polymer Flooding has become one of the most implemented EOR techniques, due to three factors: First, Polymer flooding has expanded the range of the screening criteria parameters. Second, this EOR method is more effective than water injection, while handling water management issues in high water-cut reservoirs. Nevertheless, polymer retention can turn a viable technical project into an uneconomical one. Polymer loss due to retention is an inevitable phenomenon, which happens during injection processes. The development of experimental analysis aiming to minimize or reduce polymer loss from the displacing fluid bank is beneficial to broaden the application of this CEOR method. This experimental work evaluated the injection schemes aiming to reduce polymer retention in porous media. The approach consisted of injecting less-concentrated polymer banks followed for the main polymer bank designed for mobility control. An experimental methodology to quantify polymer retention due to each injected polymer bank, cumulative polymer retention, resistance factor, residual resistance factor and inaccessible pore volume (IPV) was developed. The measurement process was based on the injection of 20 PV polymer banks at a constant flow rate of 1ml/min at 25°C, separated by 30 PV brine banks. Two HPAM with molecular weights of 6-8 million and 20 million Daltons using 350mD and 5000 mD sandstone cores were tested, respectively. The HPAM solutions considering a Colombian field (0.7% NaCl) and seawater (3.5% TDS) salinities were prepared. All rock samples were previously submitted to the injection of 50 PV for preventing fines migration. Two injection schemes with variable polymer concentrations were performed: The first one in which the polymer concentration increased in each successive bank, and the second one in which the concentration decreased. HPAM concentration solutions from 50 ppm to 2000 ppm were sequentially used in both injection schemes. By comparing the results of these two schemes, the effect of the injection of the less-concentrated polymer solutions was evaluated. For the increasing concentration experiments, cumulative retention values of 175.7 μg/g and 58.9 μg/g were calculated for the low-molecular weight polymer and the high-molecular weight polymer, respectively. While comparing with decreasing concentration experiments, for the high-molecular weight HPAM a 19% of retention reduction was evidenced, but no retention reduction was observed for the low-molecular weight one. The results indicate that different retention mechanisms are strongly dependents on the absolute permeability of the samples. Additionally, IPV values of 0.5 PV and 0.25 PV were calculated using low and high permeability samples, respectively. There was no linear relation between the absolute permeability reduction and the polymer concentration of the first bank injected into the sample. The novelty of this work is to use sacrificial banks of less-concentrated HPAM solutions as a reducing retention agent for the polymer bank designed for mobility control.
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Carpenter, Chris. "Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs". Journal of Petroleum Technology 73, n.º 11 (1 de noviembre de 2021): 60–61. http://dx.doi.org/10.2118/1121-0060-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.
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Khorsandi, Saeid, Changhe Qiao y Russell T. Johns. "Displacement Efficiency for Low-Salinity Polymer Flooding Including Wettability Alteration". SPE Journal 22, n.º 02 (26 de octubre de 2016): 417–30. http://dx.doi.org/10.2118/179695-pa.
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Summary Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high-salinity brines, so it is advantageous to inject low-salinity water as a preflush. Low-salinity waterflooding (LSW) can also improve local-displacement efficiency by changing the wettability of the reservoir rock from oil-wet to more water-wet. The mechanism for wettability alteration for LSW in sandstones is not very well-understood; however, experiments and field studies strongly support that cation-exchange (CE) reactions are the key elements in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport have not been explained to date. This paper presents the first analytical solutions for the coupled synergistic behavior of LSW and polymer flooding considering CE reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the CE of Ca2+, Mg2+, and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase-flow and reactive-transport model is decoupled into three simpler subproblems—the first in which CE reactions are solved, the second in which a variable polymer concentration can be added to the reaction path, and the third in which fractional flows can be mapped onto the fixed cation and polymer-concentration paths. The solutions are used to develop a front-tracking algorithm, which can solve the slug-injection problem of low-salinity water as a preflush followed by polymer. The results are verified with experimental data and PennSim (2013), a general-purpose compositional simulator. The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low-salinity preflush before polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned low-salinity polymer (LSP) flood can be as much as 10% original oil in place (OOIP) greater than with considering polymer alone. The results show the structure of the solutions, and, in particular, the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in corefloods for small-slug sizes of low salinity are explained by the intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP flooding as a less-expensive and more-effective way for performing polymer flooding when the reservoir wettability can be altered with chemically tuned low-salinity brine.
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Wang, Dongmei, Chunxiao Li y Randall S. Seright. "Laboratory Evaluation of Polymer Retention in a Heavy Oil Sand for a Polymer Flooding Application on Alaska's North Slope". SPE Journal 25, n.º 04 (14 de mayo de 2020): 1842–56. http://dx.doi.org/10.2118/200428-pa.
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Summary For a polymer flooding field trial in a heavy oil reservoir on Alaska's North Slope, polymer retention is a key parameter. Because of the economic impact of retention, this parameter was extensively studied using field core material and conditions. In this paper, multiple types of laboratory measurements were used to assess hydrolyzed polyacrylamides (HPAM) polymer retention, including a brine tracer, effluent viscosity, total effluent organic carbon, and effluent chemiluminescent nitrogen. Retention tests were conducted in different Milne Point Schrader Bluff sands, with extensive permeability, grain size distribution, X-ray-diffraction (XRD), and X-ray fluorescence (XRF) characterizations. Several important findings were noted. Polymer retention based on effluent viscosity measurements can be overestimated unless the correct (nonlinear) relation between polymer concentration and viscosity is used. Polymer degradation (either mechanical or oxidative) can also lead viscosity-based measurements to overestimate retention. Inaccessible pore volume (PV) (IAPV) can be overestimated if insufficient brine is flushed through the sand between polymer banks. Around 100 PVs of brine may be needed to displace mobile polymer to approach a true residual resistance factor and properly measure IAPV. Even for a sandpack with kwsor = 20 md, IAPV was zero for HPAM with a molecular weight (Mw) of 18 MM g/mol. Fine-grained particles (<20 µm) strongly impacted polymer retention values. Native NB#1 sand with a significant component of particles <20 µm exhibited 290 µg/g, while the same sand exhibited 28 µg/g after these small particles were removed. Polymer retention did not necessarily correlate with mineral composition. The NB#1, NB#3, and OA sands had similar elemental and clay compositions, but the NB#1 sand exhibited ∼10 times higher retention than the NB#3 sand. Polymer retention did not necessarily correlate with permeability. NB#1 sand exhibited much higher retention than OA sand, even though NB#1 sand was twice as permeable as OA sand. No evidence of chromatographic separation of HPAM molecular weights was found in our experiments. Although retention tended to be greater without a residual oil saturation (than at Sor), the effect was not strong. Aging a core (with high oil saturation) at 60°C reduced HPAM retention by a factor of two. Under similar conditions, polymer retention was greater for a higher Mw HPAM (18 MM g/mol) than for a lower Mw HPAM (10 to 12 MM g/mol). In many cases with high polymer retention values (e.g., 240 µg/g), polymer arrival at the end of the core was relatively quick, but achieving the injected concentration occurred gradually over many PVs. This effect was not caused by chromatographic separation of polymer molecular weights. Results from modeling of this behavior were consistent with concentration-dependent polymer retention. The form assumed for the retention function in a simulator can have an important impact on the timing and magnitude of the oil response from a polymer flood. Field-based observations can underestimate polymer retention, depending on when the tracer and polymer concentrations were measured and the assumptions made about reservoir heterogeneity.
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Souayeh, Maissa, Rashid S. Al-Maamari, Ahmed Mansour, Mohamed Aoudia y Thomas Divers. "Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution". SPE Journal 27, n.º 01 (1 de diciembre de 2021): 840–63. http://dx.doi.org/10.2118/208581-pa.
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Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.
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Santoso, Ryan, Victor Torrealba y Hussein Hoteit. "Investigation of an Improved Polymer Flooding Scheme by Compositionally-Tuned Slugs". Processes 8, n.º 2 (6 de febrero de 2020): 197. http://dx.doi.org/10.3390/pr8020197.
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Polymer flooding is an effective enhanced oil recovery technology used to reduce the mobility ratio and improve sweep efficiency. A new polymer injection scheme is investigated that relies on the cyclical injection of low-salinity, low-concentration polymer slugs chased by high-salinity, high-concentration polymer slugs. The effectiveness of the process is a function of several reservoir and design parameters related to polymer type, concentration, salinity, and reservoir heterogeneity. We use reservoir simulations and design-of-experiments (DoE) to investigate the effectiveness of the proposed polymer injection scheme. We show how key objective functions, such as recovery factor and injectivity, are impacted by the reservoir and design parameters. In this study, simulations showed that the new slug-based process was always superior to the reference polymer injection scheme using the traditional continuous injection scheme. Our results show that the process is most effective when the polymer weight is high, corresponding to large inaccessible pore-volumes, which enhances polymer acceleration. High vertical heterogeneity typically reduces the process performance because of increased mixing in the reservoir. The significance of this process is that it allows for increased polymer solution viscosity in the reservoir without increasing the total mass of polymer, and without impairing polymer injectivity at the well.
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Najafiazar, Bahador, Dag Wessel-Berg, Per Eirik Bergmo, Christian Rone Simon, Juan Yang, Ole Torsæter y Torleif Holt. "Polymer Gels Made with Functionalized Organo-Silica Nanomaterials for Conformance Control". Energies 12, n.º 19 (30 de septiembre de 2019): 3758. http://dx.doi.org/10.3390/en12193758.
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Deep placement of gel in waterflooded hydrocarbon reservoirs may block channels with high water flow and may divert the water into other parts of the reservoir, resulting in higher oil production. In order to get the gel constituents to the right reservoir depths, a delay in the gelling time in the order of weeks at elevated temperatures will be necessary. In this work, a methodology for controlled gelation of partially hydrolyzed polyacrylamide using hybrid nanomaterials with functional groups as cross-linkers was developed. Two delay mechanisms with hybrid materials and polyelectrolyte complexes were designed and tested. Both mechanisms could significantly delay the gelation rate, giving gelling times ranging from several days to several weeks in synthetic sea water at 80 . Gelling experiments in sandstone cores showed that gel strength increased with aging time. For long aging times, strong gels were formed which resulted in almost no water permeability. A series of coreflooding experiments with polymer and deactivated nanomaterial were performed. In addition to differential pressures and concentration profiles, the experiments enabled calculation of retention and inaccessible pore volumes. A novel numerical model of 1D two-phase flow has been developed and tested with results from core flooding experiments. The model can track the age distribution and concentrations of the nanomaterial (and therefore water viscosity) throughout the porous medium at every time step. The model generated a good fit of experimental results.
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Smiraglia, Claudio. "L’Antartide è veramente un "awful place"? I caratteri ambientali del continente più freddo della Terra". ACME - Annali della Facoltà di Lettere e Filosofia dell’Università degli Studi di Milano, n.º 03 (diciembre de 2012): 29–46. http://dx.doi.org/10.7358/acme-2012-003-smir.
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The Antarctic continent is certainly made an "awful" place by its harsh climate: in the past, explorers and researchers endured terrible hardships and the climate remains a challenge today, in spite of the many improvements in knowledge and technology. The Antarctic may be termed "the continent of the extremes", as it occupies an area unlike any other on earth. It is the farthest and most inaccessible and isolated continent; the most regular because of its rounded shape, with the South Pole at the centre; the coldest continent, with temperatures falling to -90°C; the driest (with an average of 130 mm of precipitation); the windiest, the highest, the most glacialized (it contains 91% of the volume of the earth’s ice). It also displays the most monotonous landscapes and presents the greatest contrast between marine and terrestrial ecosystems. But the Antarctic is also "extreme" because it is the least populated continent, with no indigenous population at all, while its few settlements (consisting in scientific bases) are concentrated on the coast; it is the only place that does not belong to one nation, but to all the world; it is the place where unique information on the past, present and future of humankind is revealed.
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Yoshizawa, N., Y. Yamada, M. Shiraishi, K. Kaneko y N. Setoyama. "Evaluation of Inaccessible Pore Structures in Random Porous Solids". MRS Proceedings 407 (1995). http://dx.doi.org/10.1557/proc-407-51.
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ABSTRACTA fine pore characterization method is investigated for a disordered solid including inaccessible pores. Here inaccessible pores denote ones into which N2 molecule cannot access at 77 K. Activated carbons prepared differently are examined. The basic idea of the method is as follows: (1) Pores are classified into effective micropores (further devided into smaller and larger micropores distinguished from DR (Dubinin-Radushkevich) analysis and inaccessible pores. (2) Volume fraction is determined for each type of pore considering densities. (3) Debye-Bueche plot derived from SAXS analysis is used to estimate the average transversal length of solid part and pore, respectively, convinedwith their volume fractions obtained from (1) and (2). (4) In case of a porous systemwith a symmetrical shape of pores, relative number and size of inaccessible pore to effective micropore are calculated.
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Zhang, Chu, Yanbin Yao, Rudy Swennen y Yuheng Zhang. "Re-evaluating the methane adsorption behavior in shale kerogen: Unifying experiment and molecular simulation". Physics of Fluids 36, n.º 2 (1 de febrero de 2024). http://dx.doi.org/10.1063/5.0188365.
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The methane adsorption capacity is crucial for evaluating gas-in-place resources and the gas production potential in shale gas reservoirs. There are many reports concerning the interfacial interaction between methane fluid and rock using various thermodynamic models; however, little research has been performed to reveal how methane is adsorbed into nanopores with different scales. In this study, we did methane adsorption experiments on nine Longmaxi Formation shale kerogen. Then, molecular simulation and an improved Ono–Kondo model were used to analyze the methane adsorption behaviors. Results show that methane is preferentially adsorbed in sulfur-containing sites by surface adsorption and pore-filling adsorption, and methane adsorbed in the form of pore-filling contributes dominantly to the total methane adsorption amount. Surface adsorption capacity nS increases with increasing mesopore volume, while pore-filling adsorption capacity nF is affected by both micropore (<2 nm) development and the micropore accessibility of methane. On the one hand, nF increases logarithmically with increasing micropore volume. On the other hand, the mean interplanar distance of the aromatic layers d002 is the key parameter in determining nF because the micropores within the aromatic layer with d002 less than 0.38 nm will be inaccessible for methane. This study is essential for understanding the methane adsorption mechanism and lay the foundation for future investigation of fluids–rock interactions.
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S. Seright, Randall y Dongmei Wang. "Literature Review and Experimental Observations of the Effects of Salinity, Hardness, Lithology, and ATBS Content on HPAM Polymer Retention for the Milne Point Polymer Flood". SPE Journal, 1 de junio de 2023, 1–16. http://dx.doi.org/10.2118/212946-pa.
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Summary At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).
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Ramadani y Tomi Erfando. "Optimization of Polymer Flooding Using Genetic Algorithm". Journal of Earth Energy Science, Engineering, and Technology 6, n.º 1 (29 de abril de 2023). http://dx.doi.org/10.25105/jeeset.v6i1.16319.
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One of the methods to achieve optimal conditions in increasing oil recovery through injecting polymers is by optimizing the parameters that influence the success of injecting polymers to provide information and be considered when determining new schemes for implementation in the future. Optimization to obtain the optimum value of the recovery factor and the best value of the parameters PV, injection rate, injection time, injection pressure, adsorption, residual resistance factor (RRF), and inaccessible pore volume (IPV) using a genetic algorithm with three training ratios and testing 70: 30, 80: 20 and 90: 10 using 1000 datasets. The best value obtained for each parameter is at a ratio of 90: 10, which is the best model with the lowest reference error value with RSME of 0.241104 and MAPE value of 19.1964 classified as good prediction with the value of each adsorption parameter 0.1737 (g/l), injection rate 703 (bpd), injection pressure 1816, IPV 0.2524, RRF 4.8319 and finally the optimum value for recovery factor is 53.9557.
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Scholz, Gunthard, Mario Zauer, Jan Van den Bulcke, Denis Van Loo, Alexander Pfriem, Joris Van Acker y Holger Militz. "Investigation on wax-impregnated wood. Part 2: Study of void spaces filled with air by He pycnometry, Hg intrusion porosimetry, and 3D X-ray imaging". Holzforschung 64, n.º 5 (1 de agosto de 2010). http://dx.doi.org/10.1515/hf.2010.090.
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Abstract The quantification of wax and remaining voids filled with air in wax-treated wood has not been described in detail in the literature, although such products are commercially available. In this paper, Scots pine (Pinus sylvestris L.) and beech (Fagus sylvatica L.) samples were impregnated with a hot melting amide wax and characterized. The apparent densities were measured with helium pycnometry and mercury intrusion porosimetry. The pore size distribution was determined by means of mercury intrusion porosimetry and samples were visualized with 3D X-ray tomography. The remaining void spaces were calculated based on the data of all three methods. The apparent densities range from 1.18 to 1.19 g cm-3 for treated pine and from 1.21 to 1.23 g cm-3 for treated beech. As a result of the wax impregnation, the pore volume decreases from 65–68% to 12–13% for pine and from 53–58% to 7–9% for beech. The pore size distribution shifts to smaller pores. The amount of the micropores measured by mercury intrusion porosimetry is overestimated. On the one hand, blocked large pores are compressed by the movement of wax deposits under high pressure during the mercury intrusion porosimetry (“movement-effect”). On the other hand, large pores remain inaccessible or are only accessible via smaller openings (“bottle-neck-effect”). Non-invasive 3D X-ray imaging detects such macropores but the size of the detected pores is limited by the given resolution of the method. Therefore, mercury intrusion porosimetry and X-ray tomography are complementary techniques.
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Song, Haofeng, Pinaki Ghosh, Miguel Mejia y Kishore Mohanty. "Polymer Transport in Low-Permeability Carbonate Rocks". SPE Reservoir Evaluation & Engineering, 1 de abril de 2022, 1–14. http://dx.doi.org/10.2118/206024-pa.
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Summary The efficiency of a polymer flood depends on polymer transport and retention. Most studies on polymer transport in the literature have been focused on high-permeability sandstones. A limited number of investigations have been conducted in carbonates with permeability less than 100 md and very few in the presence of residual oil. In this work, transport of four polymers with different molecular weights (MW) and functional groups was studied in 1-ft-long Edwards Yellow outcrop cores (permeability < 50 md) with and without residual oil. The retention of polymers was estimated by both the material balance method and the double-bank method. The polymer concentration in coreflood effluents was measured by both the total organic carbon (TOC) analyzer and the capillary tube pressure drop. The results demonstrated that in tight carbonate rocks at 100% water saturation, partially hydrolyzed acrylamide (HPAM) polymers exhibited high retention (>160 µg/g), inaccessible pore volume (IPV) greater than 7%, and high residual resistance factor (RRF) (>9). The propagation of HPAM improved with the residual oil saturation and the retention was reduced by 50 µg/g because of thin oil films in pores that prevented the direct adsorption of the carboxyl group of polymers on the mineral surface. The sulfonated polyacrylamide, AN132, showed low retention (<15 µg/g) and negligible IPV in all experiments. The RRF of AN132 in the water-saturated rock was less than 2, indicating minimal blocking of pore throats in these tight rocks. The RRF of the AN132 polymer increased slightly in the presence of residual oil saturation because of partial blocking of the smaller pore throats available for polymer propagation in the oil-aged core.
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Jia, Hu, Pengwu Li y Yufei Zhang. "Polymer Gel for Water Shutoff in Complex Oil and Gas Reservoirs: Mechanisms, Simulation, and Decision-Making". SPE Journal, 1 de septiembre de 2023, 1–17. http://dx.doi.org/10.2118/217457-pa.
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Summary Gel treatment is often used for water shutoff in high water-cut oil or gas wells. Although the properties and usage methods of gel have been well documented by different investigators, gel treatment performance is not always satisfactory in field application, especially in oil or gas reservoirs with complex conditions, such as strong bottomwater reservoirs, high-permeability-ratio oil reservoirs, and fractured gas reservoirs. In this work, we attempt to improve gel treatment application in complex situations according to the causes of disappointing performance, including unreliable numerical simulation and the misapplication of experiences. We propose a new numerical simulation method of gel treatment mechanisms and verify it by improving the acquiring method of inaccessible pore volume (IAPV), dynamic polymer adsorption (DPA), and the simulation method of disproportionate permeability reduction (DPR). The performance and optimization measures of gel treatment in different types of complex oil and gas reservoirs are discussed extensively. Moreover, the dominant influencing factor of the gel treatment effect is determined by gray relation analysis to provide more direct and effective suggestions for field application. The results suggest that the improved access methods for IAPV and DPA can help to obtain more precise parameters easily to construct a numerical gel model. In addition, the new DPR simulation method, which considers oil or gas blocking, reduces the overestimation of gel DPR ability obtained with the conventional method. The misapplication of gel treatment experience probably causes a disappointing response, for example, gel treatment time had opposite influences on water shutoff in strong bottomwater reservoirs and high-permeability-ratio oil reservoirs, and the experience of reservoir thickness in oil reservoirs was not suitable for gas reservoirs. Furthermore, the major factors of gel treatment are varied in different oil and gas reservoirs, demonstrating that primary evaluation indicators for candidate wells are not permanent.
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Alfazazi, Umar, Nithin Chacko Thomas, Emad Walid Al-Shalabi y Waleed AlAmeri. "Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions". SPE Journal, 1 de noviembre de 2023. http://dx.doi.org/10.2118/207892-pa.
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Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.
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Zhang, Bingjun, Abdelhalim I. A. Mohamed, Lamia Goual y Mohammad Piri. "Pore-scale experimental investigation of oil recovery enhancement in oil-wet carbonates using carbonaceous nanofluids". Scientific Reports 10, n.º 1 (16 de octubre de 2020). http://dx.doi.org/10.1038/s41598-020-74450-w.
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Abstract This study investigates the pore-scale displacement mechanisms of crude oil in aged carbonate rocks using novel engineered carbon nanosheets (E-CNS) derived from sub-bituminous coal. The nanosheets, synthesized by a simple top-down technique, were stable in brine without any additional chemicals. Owing to their amphiphilic nature and nano-size, they exhibited dual properties of surfactants and nanoparticles and reduced the oil/brine interfacial tension (IFT) from 14.6 to 5.5 mN/m. X-ray micro-computed tomography coupled with miniature core-flooding was used to evaluate their ability to enhance oil recovery. Pore-scale displacement mechanisms were investigated using in-situ contact angle measurements, oil ganglia distribution analysis, and three-dimensional visualization of fluid occupancy maps in pores of different sizes. Analysis of these maps at the end of various flooding stages revealed that the nanofluid invaded into medium and small pores that were inaccessible to base brine. IFT reduction was identified as the main displacement mechanism responsible for oil recovery during 1 to 8 pore volumes (PVs) of nanofluid injection. Subsequently, wettability alteration was the dominant mechanism during the injection of 8 and 32 PVs, decreasing the average contact angle from 134° (oil wet) to 85° (neutral wet). In-situ saturation data reveals that flooding with only 0.1 wt% of E-CNS in brine resulted in incremental oil production of 20%, highlighting the significant potential of this nanofluid as a recovery agent.